What is Hydro-X:

Hydro-X is the name given to a method and solution invented in Denmark 70 years ago that provides the necessary corrective treatment of water for heating systems and boilers, both hot water and steam, with low steam pressure (up to 40 atm). When using the Hydro-X method, only one solution is added to the circulating water, which is supplied to the consumer at plastic canisters or barrels in a form ready for use. This allows enterprises to not have special warehouses for chemical reagents, workshops for preparing the necessary solutions, etc.

The use of Hydro-X ensures the maintenance of the required pH value, purification of water from oxygen and free carbon dioxide, prevention of the appearance of scale, and, if present, cleaning of surfaces, as well as protection against corrosion.

Hydro-X is a transparent yellowish-brown liquid, homogeneous, strongly alkaline, with a specific gravity of about 1.19 g/cm at 20 °C. Its composition is stable and even with long-term storage There is no liquid separation or sedimentation, so there is no need to stir before use. The liquid is not flammable.

The advantages of the Hydro-X method are the simplicity and efficiency of water treatment.

When operating water heating systems, including heat exchangers, hot water or steam boilers, as a rule, they are recharged additional water. To prevent the appearance of scale, it is necessary to carry out water treatment in order to reduce the content of sludge and salts in the boiler water. Water treatment can be carried out, for example, through the use of softening filters, desalting, reverse osmosis, etc. Even after such treatment, problems remain associated with possible corrosion. When caustic soda, trisodium phosphate, etc. are added to water, the problem of corrosion and, for steam boilers, steam contamination also remains.

Enough simple method, which prevents the appearance of scale and corrosion, is the Hydro-X method, according to which a small amount of an already prepared solution containing 8 organic and inorganic components is added to the boiler water. The advantages of the method are as follows:

– the solution is supplied to the consumer in a form ready for use;

– the solution is introduced into the water in small quantities either manually or using a dosing pump;

– when using Hydro-X there is no need to use other chemicals;

– approximately 10 times less active substances are supplied to the boiler water than when using traditional methods water treatment;

Hydro-X does not contain toxic components. Except hydroxide sodium NaOH and trisodium phosphate Na3PO4, all other substances are extracted from non-toxic plants;

– when used in steam boilers and evaporators provide clean steam and prevent the possibility of foaming.

Composition of Hydro-X.

The solution contains eight different substances, both organic and inorganic. The mechanism of action of Hydro-X is complex physico-chemical in nature.

The direction of influence of each component is approximately as follows.

Sodium hydroxide NaOH in an amount of 225 g/l reduces water hardness and regulates the pH value, protects the magnetite layer; trisodium phosphate Na3PO4 in an amount of 2.25 g/l - prevents the formation of scale and protects the iron surface. All six organic compounds in total do not exceed 50 g/l and include lignin, tannin, starch, glycol, alginate and sodium mannuronate. The total amount of base substances NaOH and Na3PO4 when treating Hydro-X water is very small, approximately ten times less than is used in traditional treatment, according to the principle of stoichiometry.

The effect of Hydro-X components is physical rather than chemical.

Organic supplements serve the following purposes.

Sodium alginate and mannuronate are used in conjunction with some catalysts and promote the precipitation of calcium and magnesium salts. Tannins absorb oxygen and create a layer of iron that protects against corrosion. Lignin acts like tannin and also helps remove existing scale. Starch forms sludge, and glycol prevents foaming and entrainment of moisture droplets. Inorganic compounds maintain the slightly alkaline environment necessary for the effective action of organic substances and serve as an indicator of the concentration of Hydro-X.

Operating principle of Hydro-X.

Organic components play a decisive role in the action of Hydro-X. Although they are present in minimal quantities, due to deep dispersion their active reaction surface is quite large. The molecular weight of the organic components of Hydro-X is significant, which provides a physical effect of attracting molecules of water pollutants. This stage of water treatment occurs without chemical reactions. The absorption of pollutant molecules is neutral. This allows you to collect all such molecules as those that create hardness, as well as iron salts, chlorides, silicic acid salts, etc. All water pollutants are deposited in the sludge, which is mobile, amorphous and does not stick together. This prevents the possibility of scale formation on heating surfaces, which is a significant advantage of the Hydro-X method.

Neutral Hydro-X molecules absorb both positive and negative ions (anions and cations), which in turn neutralize each other. Neutralization of ions directly affects the reduction of electrochemical corrosion, since this type of corrosion is associated with different electrical potentials.

Hydro-X is effective against corrosive gases - oxygen and free carbon dioxide. A Hydro-X concentration of 10 ppm is quite sufficient to prevent this type of corrosion, regardless of the ambient temperature.

Caustic soda can cause caustic brittleness. The use of Hydro-X reduces the amount of free hydroxides, significantly reducing the risk of caustic brittleness of steel.

Without stopping the system for flushing, the Hydro-X process allows you to remove old existing scale. This occurs due to the presence of lignin molecules. These molecules penetrate the pores of the boiler scale and destroy it. Although it should still be noted that if the boiler is very dirty, it is more economically feasible to carry out chemical washing, and then use Hydro-X to prevent scale, which will reduce its consumption.

The resulting sludge is collected in sludge accumulators and removed from them by periodic blowing. Filters (mud collectors) can be used as sludge collectors, through which part of the water returned to the boiler is passed.

It is important that the sludge formed under the action of Hydro-X is removed, if possible, by daily blowdowns of the boiler. The amount of blowing depends on the hardness of the water and the type of enterprise. IN initial period When surfaces are being cleaned from existing sludge and there is a significant content of pollutants in the water, the blowing should be greater. Purge is carried out by fully opening the purge valve for 15-20 seconds daily, and with a large supply of raw water, 3-4 times a day.

Hydro-X can be used in heating systems, in centralized heating systems, for low-pressure steam boilers (up to 3.9 MPa). No other reagents should be used simultaneously with Hydro-X except sodium sulfite and soda. It goes without saying that make-up water reagents do not fall into this category.

In the first few months of operation, the reagent consumption should be slightly increased in order to eliminate the scale existing in the system. If there is concern that the boiler superheater is contaminated with salt deposits, it should be cleaned using other methods.

If there is an external water treatment system, it is necessary to select the optimal operating mode for Hydro-X, which will ensure overall savings.

An overdose of Hydro-X does not adversely affect either the reliability of the boiler operation or the quality of steam for steam boilers and only leads to an increase in the consumption of the reagent itself.

Steam boilers

Raw water is used as additional water.

Constant dosage: 0.2 l of Hydro-X for every cubic meter of additional water and 0.04 l of Hydro-X for every cubic meter of condensate.

Softened water is used as make-up water.

Initial dosage: 1 liter of Hydro-X for every cubic meter of water in the boiler.

Constant dosage: 0.04 liters of Hydro-X for every cubic meter of additional water and condensate.

Dosage for boiler descaling: Hydro-X is dosed in an amount 50% more than the constant dose.

Heating systems

Raw water is used as make-up water.

Initial dosage: 1 liter of Hydro-X for every cubic meter of water.

Constant dosage: 1 liter of Hydro-X for every cubic meter of make-up water.

Softened water is used as make-up water.

Initial dosage: 0.5 liters of Hydro-X for every cubic meter of water.

Constant dosage: 0.5 liters of Hydro-X for every cubic meter of make-up water.

In practice, additional dosage is based on the results of pH and hardness tests.

Measurement and control

The normal dosage of Hydro-X per day is approximately 200-400 ml per ton of make-up water with an average hardness of 350 mcEq/dm3 calculated as CaCO3, plus 40 ml per ton of return water. These are, of course, approximate figures, and more precise dosing can be established by monitoring water quality. As already noted, an overdose will not cause any harm, but the correct dosage will save money. For normal operation, hardness (calculated as CaCO3), total concentration of ionic impurities, specific electrical conductivity, caustic alkalinity, and hydrogen ion concentration (pH) of water are monitored. Due to its simplicity and wide range of reliability, Hydro-X can be used in both manual dosing and automatic mode. If desired, the consumer can order a monitoring and computer control system for the process.

For the first time, external corrosion of screen pipes was discovered at two power plants in high-pressure boilers TP-230-2, which operated on ASh grade coal and sulfur fuel oil and had previously been in operation for about 4 years. The outer surface of the pipes was subjected to corrosion on the side facing the furnace, in the zone of maximum flame temperature. 88

It was mainly the pipes in the middle (width) part of the firebox that were destroyed, directly above the incendiary. belt Wide and relatively shallow corrosion pits had irregular shape and often closed with each other, as a result of which the damaged surface of the pipes was uneven and lumpy. Fistulas appeared in the middle of the deepest ulcers, and jets of water and steam began to escape through them.

Characteristic was the complete absence of such corrosion on the screen pipes of the medium-pressure boilers of these power plants, although the medium-pressure ones were in operation there for a much longer time.

In subsequent years, external corrosion of screen pipes also appeared on other high-pressure boilers operating on solid fuel. The zone of corrosion destruction sometimes extended to a considerable height; In some places, the thickness of the pipe walls as a result of corrosion decreased to 2-3 mm. It has also been observed that this corrosion is virtually absent in high-pressure oil-fired boilers.

External corrosion of screen pipes was discovered in TP-240-1 boilers after 4 years of operation, operating at a pressure in the drums of 185 at. These boilers burned brown coal from the Moscow region, which had a moisture content of about 30%; Fuel oil was burned only for kindling. In these boilers, corrosion damage also occurred in the area of ​​the highest thermal load of the screen pipes. The peculiarity of the corrosion process was that the pipes were destroyed both from the side facing the firebox and from the side facing the lining (Fig. 62).

These facts show that corrosion of screen pipes depends primarily on their surface temperature. In medium-pressure boilers, water evaporates at a temperature of about 240 ° C; for boilers designed for a pressure of 110 atm, the calculated boiling point of water is 317 ° C; in TP-240-1 boilers, water boils at a temperature of 358 ° C. The temperature of the outer surface of the screen pipes usually exceeds the boiling point by about 30-40 ° C.

Can. assume that intense external corrosion of the metal begins when its temperature rises to 350 ° C. For boilers designed for a pressure of 110 atm, this temperature is reached only on the fire side of the pipes, and for boilers with a pressure of 185 atm, it corresponds to the temperature of the water in the pipes . That is why corrosion of screen pipes on the lining side was observed only in these boilers.

A detailed study of the issue was carried out on TP-230-2 boilers operating at one of the mentioned power plants. There samples of gases and combustion were taken

A small amount of particles from the torch at a distance of about 25 mm from the screen pipes. Near the front screen in the zone of intense external corrosion of pipes, the flue gases contained almost no free oxygen. Near the rear screen, where there was almost no external corrosion of the pipes, there was much more free oxygen in the gases. In addition, the test showed that in the area where corrosion occurred, more than 70% of gas samples

It can be assumed that in the presence of excess oxygen, hydrogen sulfide burns and corrosion does not occur, but in the absence of excess oxygen, hydrogen sulfide enters into a chemical combination with the metal of the pipes. This forms iron sulfide FeS. This corrosion product was actually found in deposits on screen pipes.

Not only carbon steel, but also chrome-molybdenum steel is susceptible to external corrosion. In particular, in TP-240-1 boilers, corrosion affected screen pipes made of 15ХМ steel.

There are still no proven measures to completely prevent the described type of corrosion. Some reduction in the rate of destruction. metal was achieved. after adjusting the combustion process, in particular when increasing the excess air in the flue gases.

27. CORROSION OF SCREENS AT EXTRA HIGH PRESSURE

This book briefly describes the operating conditions of the metal of steam boilers of modern power plants. But energy progress in the USSR continues, and now a large number of new boilers are coming into operation, designed for higher steam pressures and temperatures. In these conditions, practical experience in operating several TP-240-1 boilers, operating from 1953-1955, is of great importance. at a pressure of 175 at (185 at in the drum). In particular, information about the corrosion of their screens is very valuable.

The screens of these boilers were subject to corrosion both from the outside and from the inside. Their external corrosion is described in the previous paragraph of this chapter, but the destruction of the internal surface of the pipes is not similar to any of the types of metal corrosion described above

Corrosion occurred mainly from the fire side of the upper part of the inclined pipes of the cold funnel and was accompanied by the appearance of corrosion pits (Fig. 63a). Subsequently, the number of such shells increased, and a continuous strip (sometimes two parallel stripes) of corroded metal appeared (Fig. 63.6). The absence of corrosion in the area of ​​welded joints was also characteristic.

Inside the pipes there was a deposit of loose sludge 0.1-0.2 mm thick, consisting mainly of iron and copper oxides. The increase in corrosion destruction of the metal was not accompanied by an increase in the thickness of the sludge layer; therefore, corrosion under the sludge layer was not the main cause of corrosion of the inner surface of the screen pipes.

The boiler water maintained a pure phosphate alkalinity regime. Phosphates were introduced into the boiler not continuously, but periodically.

Of great importance was the fact that the temperature of the pipe metal periodically increased sharply and sometimes was above 600 ° C (Fig. 64). The zone of the most frequent and maximum temperature increase coincided with the zone of greatest destruction of the metal. Reducing the pressure in the boiler to 140-165 atm (i.e., to the pressure at which new serial boilers operate) did not change the nature of the temporary increase in pipe temperature, but was accompanied by a significant decrease in the maximum value of this temperature. The reasons for this periodic increase in the temperature of the fire side of the inclined pipes are cold. funnels have not yet been studied in detail.

This book addresses specific issues related to the performance of steel parts of a steam boiler. But to study these purely practical issues you need to know general information concerning the structure of steel and its properties. In diagrams showing the structure of metals, atoms are sometimes depicted as balls in contact with each other (Fig. 1). Such diagrams show the arrangement of atoms in a metal, but it is difficult to clearly show the arrangement of atoms relative to each other friend. Erosion is the gradual destruction of the surface layer of metal under the influence of mechanical stress. The most common type of erosion of steel elements - a steam boiler - is their abrasion by solid ash particles moving along with flue gases. With prolonged abrasion, a gradual decrease in the thickness of the pipe walls occurs, and then their deformation and rupture under the influence of internal pressure.

Corrosion of screen pipes is most active in places where coolant impurities are concentrated. This includes areas of screen pipes with high thermal loads, where deep evaporation of boiler water occurs (especially if there are porous deposits with low thermal conductivity on the evaporation surface). Therefore, in relation to preventing damage to screen pipes associated with internal metal corrosion, the need for an integrated approach must be taken into account, i.e. impact on both water chemistry and combustion conditions.

Damage to screen pipes is mainly of a mixed nature; they can be divided into two groups:

1) Damage with signs of steel overheating (deformation and thinning of pipe walls at the point of destruction; the presence of graphite grains, etc.).

2) Brittle fractures without characteristic features overheating of the metal.

On the inner surface of many pipes there are significant deposits of a two-layer nature: the upper one is weakly adherent, the lower one is scale-like, tightly adhered to the metal. The thickness of the bottom layer of scale is 0.4-0.75 mm. In the damage zone, the scale on the inner surface is destroyed. Near the places of destruction and at some distance from them, the inner surface of the pipes is affected by corrosion pits and brittle microdamages.

The general appearance of the damage indicates the thermal nature of the destruction. Structural changes on the frontal side of the pipes - deep spheridization and decomposition of pearlite, formation of graphite (transition of carbon into graphite 45-85%) - indicate that not only the operating temperature of the screens, but also the permissible temperature for steel is exceeded 20,500 oC. The presence of FeO also confirms the high level of metal temperatures during operation (above 845 oK - i.e. 572 oC).

Brittle damage caused by hydrogen typically occurs in areas with high heat flows, under thick layers of deposits, and inclined or horizontal pipes, as well as in heat transfer areas near weld backing rings or other devices that impede the free movement of flows. .Experience has shown that damage caused by hydrogen occurs in boilers operating at pressures below 1000 psi. inch (6.9 MPa).

Damage caused by hydrogen usually results in thick-edged tears. Other mechanisms that contribute to the formation of thick-edged tears are stress corrosion cracking, corrosion fatigue, stress ruptures, and (in some rare cases) extreme overheating. It may be difficult to visually distinguish damage caused by hydrogen damage from other types of damage, but several features can help.

For example, hydrogen damage almost always involves pitting in the metal (see precautions in Chapters 4 and 6). Other types of failure (with the possible exception of corrosion fatigue, which often begins in individual sinks) are usually not associated with severe corrosion.

Pipe failures as a result of hydrogen damage to metal often manifest themselves in the form of the formation of a rectangular “window” in the pipe wall, which is not typical for other types of damage.

To assess the damageability of screen pipes, it should be taken into account that the metallurgical (initial) content of hydrogen gas in pearlite class steel (including Art. 20) does not exceed 0.5-1 cm3/100g. When the hydrogen content is higher than 4-5 cm3/100g, the mechanical properties of steel deteriorate significantly. In this case, one must focus primarily on the local content of residual hydrogen, since in the case of brittle fractures of screen pipes, a sharp deterioration in the properties of the metal is observed only in a narrow zone along the cross-section of the pipe, with the structure and mechanical properties of the adjacent metal invariably satisfactory at a distance of only 0.2-2 mm.

The obtained values ​​of average hydrogen concentrations at the edge of destruction are 5-10 times higher than its initial content for station 20, which could not but have a significant impact on the damageability of pipes.

The presented results indicate that hydrogen embrittlement turned out to be a decisive factor in the damageability of the screen tubes of KrCHPP boilers.

It was necessary to further study which factor has a decisive influence on this process: a) thermal cycling due to destabilization of the normal boiling regime in zones of increased heat flows in the presence of deposits on the evaporation surface, and, as a result, damage to the protective oxide films covering it; b) the presence in the working environment of corrosive impurities concentrated in deposits near the evaporation surface; c) the combined action of factors “a” and “b”.

Particularly important is the question of the role of the combustion regime. The nature of the curves indicates the accumulation of hydrogen in some cases near the outer surface of the screen pipes. This is possible primarily if there is a dense layer of sulfides on the specified surface, which are largely impermeable to hydrogen diffusing from the inner to the outer surface. The formation of sulfides is due to: high sulfur content of the burned fuel; throwing a torch onto the screen panels. Another reason for hydrogenation of the metal at the outer surface is the occurrence of corrosion processes when the metal comes into contact with flue gases. As the analysis of external deposits of boiler pipes showed, both of the above reasons usually took place.

The role of the combustion regime is also manifested in the corrosion of screen pipes under the influence of clean water, which is most often observed on high-pressure steam generators. Foci of corrosion are usually located in the zone of maximum local thermal loads and only on the heated surface of the pipe. This phenomenon leads to the formation of round or elliptical depressions with a diameter greater than 1 cm.

Overheating of the metal occurs most often in the presence of deposits due to the fact that the amount of heat received will be almost the same for both a clean pipe and a pipe containing scale; the temperature of the pipe will be different.

Galustov V.S. Direct-flow spray devices in thermal power engineering (Document)

Filonov A.G. Water-chemical regimes of thermal power plants (Document)

Physico-chemical processes in the technosphere. Collection of tasks (Document)

Orlov D.S. Soil Chemistry (Document)

n1.doc

3.4. Corrosion of steam generator elements
3.4.1. Corrosion of steam pipesAndsteam generator drums
during their operation
Corrosion damage to the metals of steam generators is caused by one or more factors: excessive heat stress on the heating surface, sluggish water circulation, stagnation of steam, stressed metal, deposition of impurities and other factors that prevent normal washing and cooling of the heating surface.

In the absence of these factors, a normal magnetite film is easily formed and preserved in water with a neutral or moderately alkaline reaction environment that does not contain dissolved oxygen. In the presence of O2, oxygen corrosion can occur. entrance areas water economizers, drums and downpipes of circulation circuits. Low speeds of water movement (in water economizers) have a particularly negative effect, since bubbles of released air are retained in places where the inner surface of the pipes is rough and cause intense local oxygen corrosion. Corrosion of carbon steel in an aqueous environment at high temperatures includes two stages: initial electrochemical and final chemical According to this corrosion mechanism, ferrous ions diffuse through the oxide film to the surface of its contact with water, react with hydroxyl or water to form ferrous hydroxide, which then decomposes into magnetite and hydrogen according to the reaction:

.

(2.4)

Electrons passing along with iron ions through the oxide film are assimilated by hydrogen ions with the release of H 2. Over time, the thickness of the oxide film increases, and diffusion through it becomes more difficult. As a result, a decrease in the corrosion rate over time is observed.

Nitrite corrosion. In the presence of sodium nitrite in the feed water, corrosion of the steam generator metal is observed, which in appearance is very similar to oxygen corrosion. However, unlike it, nitrite corrosion does not affect the inlet sections of the lowering pipes, but the inner surface of the heat-stressed rising pipes and causes the formation of deeper pits with a diameter of up to 15–20 mm. Nitrites accelerate the cathodic process, and thereby the corrosion of the metal of the steam generator. The course of the process during nitrite corrosion can be described by the following reaction:

.

(2.5)

Galvanic corrosion of steam generator metal. The source of galvanic corrosion of steam-generating pipes can be copper entering the steam generators in cases where feed water containing an increased amount of ammonia, oxygen and free carbon dioxide aggressively affects brass and copper pipes regenerative heaters. It should be noted that galvanic corrosion can only be caused by metallic copper deposited on the walls of the steam generator. When maintaining the pH value of the feedwater above 7.6, copper enters the steam generators in the form of oxides or complex compounds, which do not have corrosive properties and are deposited on heating surfaces in the form of sludge. Copper ions present in feed water with a low pH value, entering the steam generator, under alkaline conditions are also precipitated in the form of sludge-like copper oxides. However, under the influence of hydrogen released in steam generators or excess sodium sulfite, copper oxides can be completely reduced to metallic copper, which, deposited on heating surfaces, leads to electrochemical corrosion of the boiler metal.

Sub-sludge (shell) corrosion. Sludge corrosion occurs in stagnant zones of the circulation circuit of a steam generator under a layer of sludge consisting of metal corrosion products and phosphate treatment of boiler water. If these deposits are concentrated in heated areas, then intense evaporation occurs underneath them, increasing the salinity and alkalinity of the boiler water to dangerous values.

Sludge corrosion spreads in the form of large pits with a diameter of up to 50–60 mm on the inside of the steam-generating pipes facing the furnace torch. Within the ulcers, a relatively uniform decrease in the thickness of the pipe wall is observed, often leading to the formation of fistulas. On the ulcers a dense layer of iron oxides in the form of shells is found. The described destruction of metal is called “shell” corrosion in the literature. Sludge corrosion, caused by oxides of ferric iron and divalent copper, is an example of combined metal destruction; The first stage of this process is purely electrochemical, and the second is chemical, caused by the action of water and water vapor on overheated areas of the metal located under the layer of sludge. Most effective means The fight against “shell” corrosion of steam generators is to prevent the occurrence of corrosion of the feed water path and the removal of iron and copper oxides from it with the feed water.

Alkali corrosion. The stratification of the steam-water mixture, which occurs in horizontal or slightly inclined steam-generating pipes, is known to be accompanied by the formation of steam bags, overheating of the metal and deep evaporation of the boiler water film. The highly concentrated film formed during the evaporation of boiler water contains a significant amount of alkali in the solution. Caustic soda, present in boiler water in small concentrations, protects the metal from corrosion, but it becomes a very dangerous corrosion factor if conditions are created on any areas of the surface of the steam generator for deep evaporation of boiler water with the formation of an increased concentration of NaOH.

The concentration of caustic soda in the evaporated film of boiler water depends on:

A) on the degree of overheating of the wall of the steam-generating pipe compared to the boiling point at a given pressure in the steam generator, i.e. quantities?t s;

B) the ratios of the concentration of caustic soda and sodium salts contained in circulating water, which have the ability to greatly increase the boiling point of water at a given pressure.

If the concentration of chlorides in the boiler water significantly exceeds the concentration of NaOH in an equivalent ratio, then before the latter reaches dangerous values ​​in the evaporating film, the content of chlorides in it increases so much that the boiling point of the solution exceeds the temperature of the superheated pipe wall, and further evaporation of water stops. If the boiler water contains predominantly caustic soda, then at ?t s = 7 °C the concentration of NaOH in the film of concentrated water is 10%, and at
?t s = 30 °C reaches 35%. Meanwhile, it has been established experimentally that already 5–10% solutions of caustic soda at boiler water temperatures above 200 °C are capable of intensively corroding the metal of heated areas and welds with the formation of loose magnetic ferrous oxide and the simultaneous release of hydrogen. Alkaline corrosion is selective, moving deeper into the metal mainly along pearlite grains and forming a network of intercrystalline cracks. A concentrated solution of caustic soda is also capable of dissolving the protective layer of iron oxides at high temperatures to form sodium ferrite NaFeO 2, which hydrolyzes to form an alkali:

	(2.6)
	(2.7)

Due to the fact that alkali is not consumed in this circular process, the possibility of a continuous corrosion process is created. The higher the temperature of the boiler water and the concentration of caustic soda, the more intense the process of alkaline corrosion occurs. It has been established that concentrated solutions of caustic soda not only destroy the protective magnetite film, but also inhibit its recovery after damage.

The source of alkaline corrosion of steam generators can also be sludge deposits, which contribute to deep evaporation of boiler water with the formation of a highly concentrated, corrosive alkali solution. Reducing the relative proportion of alkali in the total salt content of boiler water and creating a predominant content of salts such as chlorides in the latter can dramatically reduce alkaline corrosion of boiler metal. Elimination of alkaline corrosion is also achieved by ensuring the cleanliness of the heating surface and intensive circulation in all areas of the steam generator, which prevents deep evaporation of water.

Intergranular corrosion. Intergranular corrosion occurs as a result of the interaction of boiler metal with alkaline boiler water. Feature intercrystalline cracks are that they occur in places of greatest stress in the metal. Mechanical stresses are composed of internal stresses arising during the manufacture and installation of drum-type steam generators, as well as additional stresses arising during operation. The formation of intergranular ring cracks on pipes is promoted by additional static mechanical stresses. They occur in pipe circuits and in steam generator drums with insufficient compensation for temperature expansion, as well as due to uneven heating or cooling of individual parts of the drum or collector body.

Intercrystalline corrosion occurs with some acceleration: in the initial period, the destruction of the metal occurs very slowly and without deformation, and then over time its speed increases sharply and can take on catastrophic proportions. Intergranular corrosion of boiler metal should be considered primarily as a special case of electrochemical corrosion occurring along the grain boundaries of stressed metal in contact with an alkaline concentrate of boiler water. The appearance of corrosive microgalvanic elements is caused by the difference in potentials between the bodies of crystallites that act as cathodes. The role of anodes is played by the collapsing grain faces, the potential of which is greatly reduced due to the mechanical stresses of the metal in this place.

Along with electrochemical processes, atomic hydrogen, a discharge product, plays a significant role in the development of intergranular corrosion
H + -ions on the cathode of corrosion elements; easily diffusing into the thickness of the steel, it destroys carbides and creates large internal stresses in the metal of the boiler due to the appearance of methane in it, which leads to the formation of thin intergranular cracks (hydrogen cracking). In addition, during the reaction of hydrogen with steel inclusions, various gaseous products are formed, which in turn causes additional tensile forces and promotes loosening of the structure, deepening, expansion and branching of cracks.

The main way to prevent hydrogen corrosion of the boiler metal is to eliminate any corrosion processes leading to the formation of atomic hydrogen. This is achieved by weakening the deposit of iron and copper oxides in the steam generator, chemical cleaning of boilers, improving water circulation and reducing local increased thermal loads of the heating surface.

It has been established that intergranular corrosion of boiler metal in the joints of steam generator elements occurs only in the simultaneous presence of local tensile stresses close to or exceeding the yield strength, and when the concentration of NaOH in the boiler water, accumulating in leaks in the joints of boiler elements, exceeds 5–6%. For the development of intercrystalline destruction of boiler metal, it is not the absolute value of alkalinity that is essential, but the proportion of caustic soda in the total salt composition of boiler water. It has been established experimentally that if this proportion, i.e., the relative concentration of caustic soda in boiler water, is less than 10–15% of the amount of mineral soluble substances, then such water, as a rule, is not aggressive.

Steam-water corrosion. In places with defective circulation, where steam stagnates and is not immediately discharged into the drum, the walls of the pipes under the steam bags are subject to severe local overheating. This leads to chemical corrosion of the metal of the steam-generating pipes, overheated to 450 °C and above, under the influence of highly superheated steam. The process of corrosion of carbon steel in highly superheated water vapor (at a temperature of 450 - 470 ° C) comes down to the formation of Fe 3 O 4 and hydrogen gas:

(2.8.)

It follows that the criterion for the intensity of steam-water corrosion of the boiler metal is an increase in the content of free hydrogen in saturated steam. Steam-water corrosion of steam-generating pipes is observed, as a rule, in zones of sharp fluctuations in wall temperature, where heat changes occur, causing the destruction of the protective oxide film. This creates the possibility of direct contact of the superheated metal of the pipe with water or water vapor and chemical interaction between them.

Corrosion fatigue. In the drums of steam generators and boiler pipes, if the metal is exposed simultaneously to a corrosive environment by thermal stresses of variable sign and magnitude, corrosion fatigue cracks deeply penetrating into the steel appear, which can be transgranular, intercrystalline, or mixed in nature. As a rule, cracking of boiler metal is preceded by the destruction of the protective oxide film, which leads to significant electrochemical heterogeneity and, as a consequence, to the development of local corrosion.

In steam generator drums, corrosion fatigue cracks occur during alternating heating and cooling of the metal in small areas at the junction of pipelines (feed water, periodic purging, injection of phosphate solution) and water-indicating columns with the drum body. In all these connections, the drum metal is cooled if the temperature of the feed water flowing through the pipe is less than the saturation temperature at the pressure in the steam generator. Local cooling of the drum walls followed by heating them with hot boiler water (at times of power failure) is always associated with the appearance of high internal stresses in the metal.

Corrosion cracking of steel sharply increases under conditions of alternate wetting and drying of the surface, as well as in cases where the movement of the steam-water mixture through the pipe has a pulsating character, i.e., the speed of movement of the steam-water mixture and its steam content often and sharply change, as well as during a kind of stratification steam-water mixture into separate “plugs” of steam and water, following each other.

3.4.2. Superheater corrosion
The rate of steam-water corrosion is determined primarily by the temperature of the steam and the composition of the metal in contact with it. The magnitude of heat exchange and temperature fluctuations during operation of the superheater are also of significant importance in its development, as a result of which destruction of protective oxide films can be observed. In an environment of superheated steam with a temperature greater
575 °C FeO (wustite) is formed on the steel surface as a result of steam-water corrosion:

It has been established that pipes made of ordinary low-carbon steel, when exposed to highly superheated steam for a long time, are uniformly destroyed with simultaneous degeneration of the metal structure and the formation of a dense layer of scale. In ultra-high and supercritical pressure steam generators at a steam superheat temperature of 550 °C and above, the most thermally stressed elements of the superheater (output sections) are usually made of heat-resistant austenitic stainless steels (chromium-nickel, chromium-molybdenum, etc.). These steels are subject to cracking under the combined action of tensile stresses and a corrosive environment. Most operational damage to steam superheaters, characterized by corrosion cracking of elements made of austenitic steels, is caused by the presence of chlorides and caustic soda in the steam. The fight against corrosion cracking of parts made of austenitic steels is carried out mainly by maintaining a safe water regime in steam generators.
3.4.3. Standstill corrosion of steam generators
When steam generators or other steam power equipment are idle in cold or hot reserve or during repairs, so-called standing corrosion develops on the metal surface under the influence of atmospheric oxygen or moisture. For this reason, equipment downtime without proper corrosion protection measures often results in serious damage, especially in steam generators. Superheaters and steam-generating pipes in the transition zones of direct-flow steam generators suffer greatly from standstill corrosion. One of the reasons for standstill corrosion of the internal surface of steam generators is their filling with water during downtime, oxygenated. In this case, the metal at the water-air interface is especially susceptible to corrosion. If a steam generator left for repairs is completely drained, then a film of moisture always remains on its inner surface with the simultaneous access of oxygen, which, easily diffusing through this film, causes active electrochemical corrosion of the metal. A thin film of moisture persists for quite a long time, since the atmosphere inside the steam generator is saturated with water vapor, especially if steam enters it through leaks in the fittings of parallel operating steam generators. If the water filling the reserve steam generator contains chlorides, this leads to an increase in the rate of uniform corrosion of the metal, and if it contains a small amount of alkali (less than 100 mg/dm 3 NaOH) and oxygen, this contributes to the development of pitting corrosion.

The development of standstill corrosion is also facilitated by sludge accumulating in the steam generator, which usually retains moisture. For this reason, significant corrosion pits are often found in drums along the lower generatrix at their ends, i.e., in areas of greatest accumulation of sludge. Particularly susceptible to corrosion are areas of the internal surface of steam generators that are covered with water-soluble salt deposits, such as superheater coils and the transition zone in once-through steam generators. During steam generator downtime, these deposits absorb atmospheric moisture and spread to form a highly concentrated solution of sodium salts on the metal surface, which has high electrical conductivity. With free access of air, the corrosion process under salt deposits proceeds very intensively. It is very significant that standstill corrosion intensifies the process of corrosion of the boiler metal during operation of the steam generator. This circumstance should be considered the main danger of parking corrosion. The resulting rust, consisting of high-valence iron oxides Fe(OH) 3, during operation of the steam generator plays the role of a depolarizer of corrosive micro- and macrogalvanic couples, which leads to intensified metal corrosion during operation of the unit. Ultimately, the accumulation of rust on the metal surface of the boiler leads to sludge corrosion. In addition, during subsequent downtime of the unit, the restored rust again acquires the ability to cause corrosion due to its absorption of oxygen from the air. These processes are repeated cyclically during alternating downtime and operation of steam generators.

Various preservation methods are used to protect steam generators from static corrosion during periods of inactivity in reserve and for repairs.
3.5. Corrosion steam turbines
During operation, the metal of the turbine flow path may be subject to corrosion in the steam condensation zone, especially if it contains carbonic acid, cracking due to the presence of corrosive agents in the steam, and standstill corrosion when the turbines are in reserve or undergoing repairs. The flow part of the turbine is especially susceptible to standstill corrosion if there are salt deposits in it. Formed during turbine downtime saline solution accelerates the development of corrosion. This implies the need for thorough cleaning of the turbine blade apparatus from deposits before its long-term downtime.

Corrosion during idle periods is usually relatively uniform; under unfavorable conditions, it manifests itself in the form of numerous pits evenly distributed over the metal surface. The place where it flows are those stages where moisture condenses, aggressively affecting the steel parts of the turbine flow path.

The source of moisture is primarily the condensation of steam filling the turbine after it stops. The condensate partially remains on the blades and diaphragms, and partially drains and accumulates in the turbine housing, since it is not discharged through drains. The amount of moisture inside the turbine may increase due to steam leakage from the extraction and backpressure steam lines. The internal parts of the turbine are always cooler than the air entering the turbine. The relative humidity of the air in the machine room is very high, so a slight cooling of the air is enough for the dew point to reach and moisture to form on metal parts.

To eliminate standstill corrosion of steam turbines, it is necessary to exclude the possibility of steam entering the turbines while they are in reserve, both from the side of the superheated steam steam line and from the side of the extraction line, drainage lines, etc. To maintain the surface of the blades, disks and rotor dry This method involves periodically blowing the internal cavity of the reserve turbine with a stream of hot air (t = 80 h 100 °C), supplied by a small auxiliary fan through a heater (electric or steam).
3.6. Corrosion of turbine condensers
Under operating conditions of steam power plants, cases of corrosion damage to brass condenser pipes are often observed, both on the inside, washed by cooling water, and on the outside. The internal surfaces of condenser pipes, cooled by highly mineralized, salty lake waters containing large amounts of chlorides, or by circulating circulating waters with increased mineralization and contaminated suspended particles, intensively corrode.

A characteristic feature of brass as a structural material is its tendency to corrosion under the combined action of increased mechanical stress and an environment with even moderately aggressive properties. Corrosion damage occurs in brass tube condensers in the form of general dezincification, plug dezincification, corrosion cracking, impact corrosion and corrosion fatigue. The occurrence of the noted forms of corrosion of brass is decisively influenced by the composition of the alloy, the manufacturing technology of condenser tubes and the nature of the contacted medium. Due to dezincification, the destruction of the surface of brass pipes can be of a continuous layer nature or belong to the so-called plug type, which is the most dangerous. Cork dezincification is characterized by pits that go deep into the metal and are filled with loose copper. The presence of through fistulas makes it necessary to replace the pipe in order to avoid the suction of cooling raw water into the condensate.

Conducted studies, as well as long-term observations of the condition of the surface of condenser tubes in operating capacitors, have shown that the additional introduction of small amounts of arsenic into brass significantly reduces the tendency of brass to dezincify. Composite brasses, additionally alloyed with tin or aluminum, also have increased corrosion resistance due to the ability of these alloys to quickly restore protective films when they are mechanically destroyed. Due to the use of metals occupying different places in the potential series and being electrically connected, macroelements appear in the capacitor. The presence of an alternating temperature field creates the possibility of developing corrosive and dangerous EMF of thermoelectric origin. Stray currents that occur when grounding near direct current can also cause severe corrosion of capacitors.

Corrosion damage to condenser tubes from condensing steam is most often associated with the presence of ammonia in it. The latter, being a good complexing agent with respect to copper and zinc ions, creates favorable conditions for dezincification of brass. In addition, ammonia causes corrosion cracking of brass condenser tubes in the presence of internal or external tensile stresses in the alloy, which gradually widen the cracks as the corrosion process develops. It has been established that in the absence of oxygen and other oxidizing agents, ammonia solutions cannot have an aggressive effect on copper and its alloys; therefore, there is no need to worry about ammonia corrosion of brass pipes when the ammonia concentration in the condensate is up to 10 mg/dm 3 and lack of oxygen. In the presence of even a small amount of oxygen, ammonia destroys brass and other copper alloys at a concentration of 2–3 mg/dm3 .

Corrosion from the steam side may primarily affect the brass pipes of vapor coolers, ejectors and air suction chambers of turbine condensers, where conditions are created that favor the entry of air and the occurrence of local increased concentrations of ammonia in partially condensed steam.

To prevent corrosion of condenser tubes on the water side, it is necessary in each specific case, when choosing a metal or alloys suitable for the manufacture of these tubes, to take into account their corrosion resistance for a given composition of the cooling water. Particularly serious attention to the selection of corrosion-resistant materials for the manufacture of condenser pipes should be given in cases where the condensers are cooled by running highly mineralized water, as well as in conditions of replenishment of losses of cooling water in the circulating water supply systems of thermal power plants, fresh waters with high mineralization, or contaminated with corrosive industrial and household waste.
3.7. Corrosion of make-up and network equipment
3.7.1. Corrosion of pipelines and hot water boilers
A number of power plants use river and tap water with a low pH value and low hardness to feed heating networks. Additional processing river water at a waterworks usually leads to a decrease in pH, a decrease in alkalinity and an increase in the content of aggressive carbon dioxide. The appearance of aggressive carbon dioxide is also possible in acidification schemes used for large heat supply systems with direct hot water supply (2000–3000 t/h). Softening water according to the Na cationization scheme increases its aggressiveness due to the removal of natural corrosion inhibitors - hardness salts.

With poorly established water deaeration and possible increases in oxygen and carbon dioxide concentrations due to the lack of additional protective measures in heat supply systems, pipelines, heat exchangers, storage tanks and other equipment are susceptible to internal corrosion.

It is known that an increase in temperature promotes the development of corrosion processes that occur both with the absorption of oxygen and with the release of hydrogen. With an increase in temperature above 40 °C, oxygen and carbon dioxide forms of corrosion increase sharply.

A special type of sludge corrosion occurs under conditions of low residual oxygen content (if PTE standards are met) and when the amount of iron oxides exceeds 400 μg/dm 3 (in terms of Fe). This type of corrosion, previously known in the practice of operating steam boilers, was discovered under conditions of relatively weak heating and the absence of thermal loads. In this case, loose corrosion products, consisting mainly of hydrated ferric oxides, are active depolarizers of the cathodic process.

When operating heating equipment, crevice corrosion is often observed, i.e., selective, intense corrosion destruction of metal in a crevice (gap). A feature of the processes occurring in narrow gaps is a reduced oxygen concentration compared to the concentration in the solution volume and a slow removal of corrosion reaction products. As a result of the accumulation of the latter and their hydrolysis, a decrease in the pH of the solution in the gap is possible.

When a heating network with an open water supply is constantly fed with deaerated water, the possibility of the formation of through fistulas on pipelines is completely eliminated only under normal hydraulic conditions, when excess pressure above atmospheric pressure is constantly maintained at all points of the heating supply system.

The causes of pitting corrosion of hot water boiler pipes and other equipment are as follows: poor deaeration of make-up water; low pH value due to the presence of aggressive carbon dioxide (up to 10–15 mg/dm 3); accumulation of oxygen corrosion products of iron (Fe 2 O 3) on heat transfer surfaces. An increased content of iron oxides in network water contributes to the contamination of boiler heating surfaces with iron oxide deposits.

A number of researchers recognize the important role in the occurrence of sub-sludge corrosion of the process of rusting pipes of hot water boilers during their downtime, when proper measures have not been taken to prevent standstill corrosion. Foci of corrosion that arise under the influence of atmospheric air on the wet surfaces of boilers continue to function during operation of the boilers.
3.7.2. Corrosion of heat exchanger tubes
The corrosion behavior of copper alloys depends significantly on temperature and is determined by the presence of oxygen in water.

In table Table 3.1 shows the rate of transition of corrosion products of copper-nickel alloys and brass into water at high (200 μg/dm 3) and low
(3 µg/dm 3) oxygen content. This rate is approximately proportional to the corresponding corrosion rate. It increases significantly with increasing oxygen concentration and salt content of water.

In acidification schemes, the water after the decarbonizer often contains up to 5 mg/dm 3 of carbon dioxide, while the service life of the tubular bundle of L-68 brass heaters is 9–10 months.
Table 3.1

The rate of transition of corrosion products into water from the surface
copper-nickel alloys and brass in a neutral environment, 10 -4 g/(m 2 h)

Material	O 2 content, µg/dm 3	Temperature, °C
		38	66	93	121	149
MN 70-30 MN 90-10 LO-70-1	3	-	3,8	4,3	3,2	4,5

Hard and soft deposits formed on the surface have a significant influence on the corrosion destruction of tubes. The nature of these deposits is important. If deposits are capable of filtering water and at the same time can retain copper-containing corrosion products on the surface of the tubes, the local process of destruction of the tubes intensifies. Deposits with a porous structure (hard scale deposits, organic) have a particularly adverse effect on the course of corrosion processes. With an increase in water pH, the permeability of carbonate films increases, and with an increase in its hardness, it sharply decreases. This explains that in circuits with starved regeneration of filters, corrosion processes occur less intensely than in Na-cationization circuits. Contamination of their surface with corrosion products and other deposits, leading to the formation of ulcers under the deposits, also contributes to a reduction in the service life of tubes. With timely removal of contaminants, local corrosion of tubes can be significantly reduced. Accelerated failure of heaters with brass tubes is observed with increased salt content of water - more than 300 mg/dm 3, and chloride concentrations - more than 20 mg/dm 3.

The average service life of heat exchanger tubes (3–4 years) can be increased if they are made from corrosion-resistant materials. Stainless steel tubes 1Х18Н9Т, installed in the make-up duct at a number of thermal power plants with low-mineralized water, have been in operation for more than 7 years without signs of damage. However, at present it is difficult to count on the widespread use of stainless steels due to their high scarcity. It should also be kept in mind that these steels are susceptible to pitting corrosion at elevated temperatures, salinity, chloride concentrations, and sediment contamination.

When the salt content of make-up and supply water is higher than 200 mg/dm 3 and chlorine ions is higher than 10 mg/dm 3, it is necessary to limit the use of L-68 brass, especially in the make-up tract to the deaerator, regardless of the water preparation scheme. When using softened make-up water containing significant amounts of aggressive carbon dioxide (over 1 mg/dm 3), the flow rate in devices with a brass pipe system must exceed 1.2 m/s.

MNZh-5-1 alloy should be used when the heating network make-up water temperature is above 60 °C.
Table 3.2

Metal tubes of heat exchangers depending on

From the heating network make-up water treatment scheme

Makeup water treatment scheme	Metal of heat exchanger tubes in the path to the deaerator	Metal tubes of network heat exchangers
Liming	L-68, LA-77-2	L-68
Na-cationization	LA-77-2, MNZH-5-1	L-68
H-cationization with starvation filter regeneration	LA-77-2, MNZH-5-1	L-68
Acidification	LA-77-2, MNZH-5-1	L-68
Soft water without treatment W o = 0.5 h 0.6 mmol/dm 3, Sh o = 0.2 h 0.5 mmol/dm 3, pH = 6.5 h 7.5	LA-77-2, MNZH-5-1	L-68

3.7.3. Assessment of the corrosion state of existingsystems

hotwater supply and reasonscorrosion
Hot water supply systems compared to other engineering structures (heating, cold water supply and sewerage systems) are the least reliable and durable. If the established and actual service life of buildings is estimated at 50–100 years, and heating, cold water supply and sewerage systems are estimated at 20–25 years, then for hot water supply systems with a closed heat supply scheme and communications made of uncoated steel pipes, the actual service life does not exceed 10 years, and in some cases 2–3 years.

Hot water pipelines without protective coatings are subject to internal corrosion and significant contamination by its products. This leads to a decrease in communications capacity, an increase in hydraulic losses and disruptions in the supply of hot water, especially to the upper floors of buildings with insufficient pressures of the city water supply. In large hot water supply systems from central heating points, the overgrowth of pipelines with corrosion products disrupts the regulation of branched systems and leads to interruptions in the supply of hot water. Due to intense corrosion, especially of external hot water supply networks from central heating stations, the volume of current and major repairs is increasing. The latter are associated with frequent relocations of internal (in houses) and external communications, disruption of the improvement of urban areas within neighborhoods, and long-term interruption of hot water supply to a large number of consumers when the head sections of hot water supply pipelines fail.

Corrosion damage to hot water supply pipelines from central heating stations if they are laid together with heating distribution networks leads to flooding of the latter hot water and their intense external corrosion. At the same time, great difficulties arise in detecting accident sites, it is necessary to carry out a large amount of excavation work and deteriorate the amenities of residential areas.

With minor differences in capital investments for the construction of hot, cold water supply and heating systems, operating costs associated with frequent relocation and repair of hot water supply communications are disproportionately higher.

Corrosion of hot water supply systems and protection against it are of particular importance due to the scale of housing construction in Russia. The tendency to consolidate the capacity of individual installations leads to a branching network of hot water supply pipelines, which are usually made from ordinary steel pipes without protective coatings. The ever-increasing shortage of drinking-quality water necessitates the use of new sources of water with high corrosive activity.

One of the main reasons affecting the condition of hot water supply systems is the high corrosiveness of heated tap water. According to VTI research, the corrosive activity of water, regardless of the source of water supply (surface or underground), is characterized by three main indicators: the index of equilibrium water saturation with calcium carbonate, the content of dissolved oxygen and the total concentration of chlorides and sulfates. Previously, the domestic literature did not provide a classification of heated tap water by corrosive activity depending on the parameters of the source water.

In the absence of conditions for the formation of protective carbonate films on the metal (j
Observational data from existing hot water supply systems indicate a significant influence of chlorides and sulfates in tap water on pipeline corrosion. Thus, waters, even with a positive saturation index, but containing chlorides and sulfates in concentrations above 50 mg/dm 3, are corrosive, which is due to a violation of the continuity of carbonate films and a decrease in their protective action under the influence of chlorides and sulfates. When the protective films are destroyed, the chlorides and sulfates present in the water increase the corrosion of steel under the influence of oxygen.

Based on the corrosion scale accepted in thermal power engineering and experimental data from VTI, a conditional corrosion classification of tap water at a design temperature of 60 °C is proposed based on the corrosion rate of steel pipes in heated drinking water (Table 3.3).

Rice. 3.2. Dependence of the depth index P of corrosion of steel pipes in heated tap water (60 °C) on the calculated saturation index J:

1, 2, 3 – surface source
; 4 – underground source
; 5 – surface source

In Fig. 3.2. experimental data on the corrosion rate in samples of steel pipes at different qualities of tap water are presented. The graph shows a certain pattern of decrease in the depth corrosion index (depth permeability) with a change in the calculated water saturation index (with a content of chlorides and sulfates up to 50 mg/dm 3). At negative values saturation index, deep permeability corresponds to emergency and severe corrosion (points 1 and 2) ; for river water with a positive saturation index (point 3) there is acceptable corrosion, and for artesian water (point 4) there is weak corrosion. Noteworthy is the fact that for artesian and river water with a positive saturation index and a content of chlorides and sulfates less than 50 mg/dm 3, the differences in the depth of corrosion permeability are relatively small. This means that in waters prone to the formation of an oxide-carbonate film on pipe walls (j > 0), the presence of dissolved oxygen (high in surface water and insignificant in underground water) does not have a noticeable effect on the change in deep corrosion permeability. At the same time, test data (point 5) indicate a significant increase in the intensity of steel corrosion in water with a high concentration of chlorides and sulfates (in total about 200 mg/dm 3), despite the positive saturation index (j = 0.5). Corrosion permeability in this case corresponds to permeability in water having a saturation index j = – 0.4. In accordance with the classification of waters according to corrosive activity, water with a positive saturation index and a high content of chlorides and sulfates is classified as corrosive.
Table 3.3

Classification of water by corrosiveness

J at 60 °C	Concentration in cold water, mg/dm 3		Corrosion characteristics of heated water (at 60 °C)
	dissolved oxygen O 2	chlorides and sulfates (in total)
	Any	Any	Highly corrosive
	Any	>50	Highly corrosive
	Any		Corrosive
	Any	>50	Slightly corrosive
	>5		Slightly corrosive
			Non-corrosive

The classification developed by VTI (Table 3.3) quite fully reflects the influence of water quality on its corrosion properties, which is confirmed by data on the actual corrosion state of hot water supply systems.

Analysis of the main indicators of tap water in a number of cities allows us to classify the majority of water as highly corrosive and corrosive, and only a small part as slightly corrosive and non-corrosive. A large proportion of sources are characterized by increased concentrations of chlorides and sulfates (more than 50 mg/dm 3), and there are examples when these concentrations in total reach 400–450 mg/dm 3. Such a significant content of chlorides and sulfates in tap water determines their high corrosive activity.

When assessing corrosion activity surface waters it is necessary to take into account the variability of their composition throughout the year. For a more reliable assessment, one should use data from not single, but possibly more water analyzes performed in different seasons over the last one or two years.

For artesian springs, water quality indicators are usually very stable throughout the year. As a rule, groundwater is characterized by increased mineralization, a positive saturation index for calcium carbonate and a high total content of chlorides and sulfates. The latter leads to the fact that hot water supply systems in some cities, receiving water from artesian wells, are also subject to severe corrosion.

When there are several sources in one city drinking water, the intensity and mass scale of corrosion damage to hot water supply systems can be different. Thus, in Kyiv there are three sources of water supply:
R. Dnepr, r. Gums and artesian wells. Hot water supply systems in areas of the city supplied with corrosive Dnieper water are most susceptible to corrosion; to a lesser extent - systems operated with slightly corrosive Desnyansk water, and to an even lesser extent - with artesian water. The presence of areas in the city with different corrosive characteristics of tap water greatly complicates the organization of anti-corrosion measures both at the design stage and during the operation of hot water supply systems.

To assess the corrosion state of hot water supply systems, surveys were carried out in a number of cities. Experimental studies of the corrosion rate of pipes using tubular and plate samples were carried out in areas of new housing construction in the cities of Moscow, St. Petersburg, etc. The survey results showed that the condition of pipelines is directly dependent on the corrosive activity of tap water.

A significant influence on the extent of corrosion damage in the hot water supply system is exerted by the high centralization of water heating installations at central heating points or heat distribution stations (DHS). Initially, the widespread construction of central heating stations in Russia was due to a number of reasons: the lack of basements in new residential buildings suitable for placing hot water supply equipment; the inadmissibility of installing conventional (non-silent) circulation pumps in individual heating points; the expected reduction in service personnel as a result of the replacement of relatively small heaters installed in individual heating points with large ones; the need to increase the level of operation of central heating stations by automating them and improving service; the possibility of constructing large installations for anti-corrosion treatment of water for hot water supply systems.

However, as experience in operating central heating stations and hot water supply systems from them has shown, the number of service personnel has not been reduced due to the need to perform a large amount of work during routine and major repairs of hot water supply systems. Centralized anti-corrosion treatment of water at central heating stations has not become widespread due to the complexity of the installations, high initial and operating costs and the lack of standard equipment (vacuum deaeration).

In conditions where hot water supply systems are predominantly used steel pipes without protective coatings, with the high corrosive activity of tap water and the absence of anti-corrosion water treatment at the central heating station, further construction of the central heating station alone is apparently impractical. Construction in last years houses of new series with basements and production of silent centrifugal pumps will contribute in many cases to the transition to the design of individual heating points (IHP) and increasing the reliability of hot water supply.

3.8. Conservation of thermal power equipment

and heating networks

3.8.1. General position

Preservation of equipment is protection against so-called parking corrosion.

Preservation of boilers and turbine units to prevent corrosion of the metal of internal surfaces is carried out during routine shutdowns and withdrawal to reserve for a definite and indefinite period: withdrawal - for current, medium, major repairs; emergency shutdowns, for long-term reserve or repair, for reconstruction for a period exceeding 6 months.

Based production instructions at each power plant and boiler house, a technical solution for organizing the conservation of specific equipment must be developed and approved, defining methods of conservation for various types of shutdowns and the duration of downtime of the technological scheme and auxiliary equipment.

When developing a technological scheme for conservation, it is advisable to make maximum use of standard installations for corrective treatment of feed and boiler water, installations for chemical cleaning of equipment, and the power plant’s tank facilities.

The technological conservation scheme should be as stationary as possible and reliably disconnected from the operating sections of the thermal circuit.

It is necessary to provide for the neutralization or neutralization of waste water, as well as the possibility of reusing preservative solutions.

In accordance with the adopted technical solution, instructions for the preservation of equipment are drawn up and approved with instructions for preparatory operations, preservation and re-preservation technologies, as well as safety measures during conservation.

When preparing and carrying out conservation and re-preservation work, it is necessary to comply with the requirements of the Safety Rules for the operation of thermal mechanical equipment of power plants and heating networks. Also, if necessary, additional safety measures related to the properties of the chemical reagents used should be taken.

Neutralization and purification of spent preservative solutions of chemical reagents must be carried out in accordance with directive documents.
3.8.2. Methods for preserving drum boilers
1. “Dry” shutdown of the boiler.

Dry shutdown is used for boilers of any pressure if they do not have rolling connections between pipes and drums.

A dry shutdown is carried out during a planned shutdown for reserve or repair for up to 30 days, as well as during an emergency shutdown.

The dry shutdown technique is as follows.

After stopping the boiler during its natural cooling or cooling, drainage begins at a pressure of 0.8 - 1.0 MPa. The intermediate superheater is steamed to a condenser. After drainage, close all valves and valves of the steam-water circuit of the boiler.

Draining the boiler at a pressure of 0.8 - 1.0 MPa allows, after emptying it, to maintain the temperature of the metal in the boiler above the saturation temperature at atmospheric pressure due to the heat accumulated by the metal, lining and insulation. In this case, the internal surfaces of the drum, collectors and pipes are dried.

2. Maintaining excess pressure in the boiler.

Maintaining a pressure above atmospheric pressure in the boiler prevents oxygen and air from entering it. Excessive pressure is maintained by flowing deaerated water through the boiler. Preservation while maintaining excess pressure is used for boilers of any type and pressure. This method is carried out when the boiler is put into reserve or repairs not related to work on heating surfaces for up to 10 days. On boilers with rolling connections between pipes and drums, it is allowed to use excess pressure for up to 30 days.

3. Except the above methods conservation on drum boilers is used:

Hydrazine treatment of heating surfaces at boiler operating parameters;

Hydrazine treatment at reduced steam parameters;

Hydrazine “boil-down” of boiler heating surfaces;

Trilon treatment of boiler heating surfaces;

Phosphate-ammonia “dilution”;

Filling the heating surfaces of the boiler with protective alkaline solutions;

Filling the heating surfaces of the boiler with nitrogen;

Preservation of the boiler with a contact inhibitor.

3.8.3. Methods for preserving once-through boilers
1. “Dry” shutdown of the boiler.

Dry shutdown is used on all once-through boilers, regardless of the adopted water chemistry regime. It is carried out during any planned and emergency shutdowns for up to 30 days. Steam from the boiler is partially released into the condenser so that within 20–30 minutes the pressure in the boiler drops to
30–40 kgf/cm 2 (3–4 MPa). Open the drains of the inlet manifolds and the water economizer. When the pressure drops to zero, the boiler is evaporated to the condenser. The vacuum is maintained for at least 15 minutes.

2. Hydrazine and oxygen treatment of heating surfaces at boiler operating parameters.

Hydrazine and oxygen treatment is carried out in combination with a dry shutdown. The technique for carrying out hydrazine treatment of a once-through boiler is the same as for a drum boiler.

3. Filling the heating surfaces of the boiler with nitrogen.

The boiler is filled with nitrogen at excess pressure in the heating surfaces. Nitrogen preservation is used on boilers of any pressure at power plants that have nitrogen from their own installations!

4. Preservation of the boiler with a contact inhibitor.

Boiler preservation with a contact inhibitor is used for all types of boilers, regardless of the water chemistry regime used, and is carried out when the boiler is put into reserve or repaired for a period of 1 month to 2 years.
3.8.4. Methods for preserving hot water boilers
1. Preservation with calcium hydroxide solution.

The protective film remains for 2–3 months after the boiler is emptied of solution after 3–4 or more weeks of contact. Calcium hydroxide is used for the preservation of hot water boilers of any type at power plants, boiler houses with water treatment plants with lime facilities. The method is based on the highly effective inhibitory abilities of a solution of calcium hydroxide Ca(OH) 2. The protective concentration of calcium hydroxide is 0.7 g/dm3 and higher. Upon contact with metal, its stable protective film is formed within 3–4 weeks.

2. Preservation with sodium silicate solution.

Sodium silicate is used for the preservation of hot water boilers of any type when the boiler is put into reserve for a period of up to 6 months or when the boiler is taken out for repairs for a period of up to 2 months.

Sodium silicate (liquid sodium glass) forms a strong protective film in the form of a compound Fe 3 O 4 ·FeSiO 3 . This film shields the metal from the effects of corrosive agents (CO 2 and O 2). When implementing this method The hot water boiler is completely filled with a sodium silicate solution with a concentration of SiO 2 in the preservative solution of at least 1.5 g/dm 3.

The formation of a protective film occurs when the preservative solution is kept in the boiler for several days or the solution is circulated through the boiler for several hours.
3.8.5. Methods for preserving turbine units
Preservation with heated air. Blowing the turbine unit with hot air prevents it from entering the internal cavities. humid air and the occurrence of corrosion processes. Moisture ingress on the surfaces of the turbine flow part is especially dangerous if there are deposits of sodium compounds on them. Preservation of a turbine unit with heated air is carried out when it is put into reserve for a period of 7 days or more.

Preservation with nitrogen. By filling the internal cavities of the turbine unit with nitrogen and subsequently maintaining a small excess pressure, the ingress of moist air is prevented. The supply of nitrogen to the turbine begins after the turbine is stopped and vacuum drying intermediate superheater. Nitrogen preservation can also be used for steam spaces of boilers and preheaters.

Preservation of corrosion with volatile inhibitors. Volatile corrosion inhibitors of the IFKHAN type protect steel, copper, and brass by adsorbing on the metal surface. This adsorption layer significantly reduces the rate of electrochemical reactions that cause the corrosion process.

To preserve the turbine unit, air saturated with the inhibitor is sucked through the turbine. Saturation of the air with the inhibitor occurs when it comes into contact with silica gel impregnated with the inhibitor, the so-called linasil. Impregnation of linasil is carried out at the manufacturer. To absorb excess inhibitor, the air at the outlet of the turbine unit passes through pure silica gel. To preserve 1 m 3 of volume, at least 300 g of linasil is required, the protective concentration of the inhibitor in the air is 0.015 g/dm 3.
3.8.6. Conservation of heating networks
When silicate treatment of make-up water is performed, a protective film is formed from the effects of CO 2 and O 2 . In this case, with direct analysis of hot water, the silicate content in the make-up water should be no more than 50 mg/dm 3 in terms of SiO 2.

When treating feedwater with silicate, the maximum calcium concentration should be determined taking into account the total concentration of not only sulfates (to prevent the precipitation of CaSO 4), but also silicic acid (to prevent the precipitation of CaSiO 3) for set temperature heating of network water taking into account boiler pipes 40 °C (PTE 4.8.39).

With a closed heat supply system, the working concentration of SiO 2 in the preservative solution can be 1.5 - 2 g/dm 3.

If preservation is not carried out with sodium silicate solution, then heating networks in summer period must always be filled with network water that meets the requirements of PTE 4.8.40.

3.8.7. Brief characteristics of the chemical reagents used
for preservation and precautions when working with them
Aqueous solution of hydrazine hydrate N 2 N 4 N 2 ABOUT

A solution of hydrazine hydrate is a colorless liquid that easily absorbs water, carbon dioxide and oxygen from the air. Hydrazine hydrate is a strong reducing agent. Toxicity (hazard class) of hydrazine – 1.

Aqueous solutions of hydrazine with a concentration of up to 30% are not flammable - they can be transported and stored in carbon steel vessels.

When working with hydrazine hydrate solutions, it is necessary to prevent the penetration of porous substances into them, organic compounds.

Hoses must be connected to the places where hydrazine solutions are prepared and stored to wash off the spilled solution from the equipment with water. To neutralize and render harmless, bleach must be prepared.

Any hydrazine solution that gets on the floor should be covered with bleach and washed off with plenty of water.

Aqueous solutions of hydrazine may cause skin dermatitis and irritate the respiratory tract and eyes. Hydrazine compounds entering the body cause changes in the liver and blood.

When working with hydrazine solutions, you must use personal glasses, rubber gloves, a rubber apron, and a KD brand gas mask.

Drops of hydrazine solution that get on the skin or eyes should be washed off with plenty of water.
Aqueous ammonia solutionN.H. 4 (OH)

An aqueous solution of ammonia (ammonia water) is a colorless liquid with a strong, specific odor. At room temperature and especially when heated, it releases ammonia abundantly. Toxicity (hazard class) of ammonia – 4. Maximum permissible concentration of ammonia in the air – 0.02 mg/dm3. Ammonia solution is alkaline. When working with ammonia, the following safety requirements must be met:

– the ammonia solution should be stored in a tank with a sealed lid;

– spilled ammonia solution should be washed off with plenty of water;

– if it is necessary to repair equipment used for preparing and dosing ammonia, it should be thoroughly rinsed with water;

– aqueous solution and ammonia vapor cause irritation to the eyes, respiratory tract, nausea and headache. Getting ammonia into your eyes is especially dangerous;

– when working with ammonia solution, you must use safety glasses;

– ammonia that gets on the skin or eyes must be washed off with plenty of water.

Trilon B
Commercial Trilon B is a white powdery substance.

Trilon solution is stable and does not decompose during prolonged boiling. The solubility of Trilon B at a temperature of 20–40 °C is 108–137 g/dm3. The pH value of these solutions is about 5.5.

Commercial Trilon B is supplied in paper bags with a polyethylene liner. The reagent should be stored in a closed, dry room.

Trilon B does not have a noticeable physiological effect on the human body.

When working with commercial Trilon, you must use a respirator, gloves and safety glasses.
Trisodium phosphateNa 3 P.O. 4 ·12N 2 ABOUT
Trisodium phosphate is a white crystalline substance, highly soluble in water.

In crystalline form it has no specific effect on the body.

In a dusty state, if it gets into the respiratory tract or eyes, it irritates the mucous membranes.

Hot phosphate solutions are dangerous if splashed into the eyes.

When carrying out work involving dust, it is necessary to use a respirator and safety glasses. When working with hot phosphate solution, wear safety glasses.

In case of contact with skin or eyes, rinse with plenty of water.
Sodium hydroxideNaOH
Caustic soda is a white, solid, very hygroscopic substance, highly soluble in water (at a temperature of 20 ° C, the solubility is 1070 g/dm3).

Caustic soda solution is a colorless liquid heavier than water. The freezing point of a 6% solution is minus 5 °C, and a 41.8% solution is 0 °C.

Caustic soda in solid crystalline form is transported and stored in steel drums, and liquid alkali in steel containers.

Any caustic soda (crystalline or liquid) that gets on the floor should be washed off with water.

If it is necessary to repair equipment used for preparing and dispensing alkali, it should be washed with water.

Solid caustic soda and its solutions cause severe burns, especially if they come into contact with the eyes.

When working with caustic soda, it is necessary to provide a first aid kit containing cotton wool, a 3% solution of acetic acid and a 2% solution of boric acid.

Personal protective equipment when working with caustic soda - a cotton suit, safety glasses, a rubberized apron, rubber boots, rubber gloves.

If alkali gets on the skin, it must be removed with cotton wool and the affected area should be washed with acetic acid. If alkali gets into your eyes you need to rinse them with a stream of water, and then with a solution of boric acid and go to the first aid station.
Sodium silicate (sodium liquid glass)
Commercial liquid glass is a thick solution of yellow or gray color, the SiO 2 content in it is 31 - 33%.

Sodium silicate is supplied in steel barrels or tanks. Liquid glass should be stored in dry, closed areas at a temperature not lower than plus 5 °C.

Sodium silicate is an alkaline product, soluble in water at a temperature of 20 - 40 ° C.

If liquid glass solution gets on your skin, it should be washed off with water.
Calcium hydroxide (lime solution) Ca(OH) 2
Lime mortar is a transparent liquid, colorless and odorless, non-toxic and has a weak alkaline reaction.

A solution of calcium hydroxide is obtained by settling the milk of lime. The solubility of calcium hydroxide is low - no more than 1.4 g/dm 3 at 25 °C.

When working with lime mortar People with sensitive skin are recommended to wear rubber gloves.

If the solution gets on your skin or eyes, wash it off with water.
Contact inhibitor
Inhibitor M-1 is a salt of cyclohexylamine (TU 113-03-13-10-86) and synthetic fatty acids of the C 10-13 fraction (GOST 23279-78). In its commercial form it is a paste or solid substance from dark yellow to brown color. The melting point of the inhibitor is above 30 °C, the mass fraction of cyclohexylamine is 31–34%, the pH of the alcohol-water solution with a mass fraction of the main substance of 1% is 7.5–8.5; The density of a 3 percent aqueous solution at a temperature of 20 ° C is 0.995 - 0.996 g/dm 3.

M-1 inhibitor is supplied in steel drums, metal flasks, steel barrels. Each package must be marked with the following data: name of the manufacturer, name of the inhibitor, batch number, date of manufacture, net weight, gross.

The commercial inhibitor is a flammable substance and must be stored in a warehouse in accordance with the rules for storing flammable substances. An aqueous solution of the inhibitor is not flammable.

Any inhibitor solution that gets on the floor must be washed off with plenty of water.

If it is necessary to repair the equipment used for storing and preparing the inhibitor solution, it should be thoroughly rinsed with water.

The M-1 inhibitor belongs to the third class (moderately hazardous substances). MPC in the air working area for an inhibitor should not exceed 10 mg/dm3.

The inhibitor is chemically stable, does not form toxic compounds in the air and wastewater in the presence of other substances or industrial factors.

Persons working with inhibitors must have a cotton suit or robe, gloves, and a hat.

After finishing work with the inhibitor, you must wash your hands. warm water with soap.
Volatile inhibitors
Volatile atmospheric corrosion inhibitor IFKHAN-1(1-diethylamino-2 methylbutanone-3) is a transparent yellowish liquid with a pungent, specific odor.

The liquid inhibitor IFKHAN-1 is classified as a highly hazardous substance in terms of the degree of impact. The maximum permissible concentration of inhibitor vapors in the air of the working area should not exceed 0.1 mg/dm 3 . The IFKHAN-1 inhibitor in high doses causes stimulation of the central nervous system, irritating the mucous membranes of the eyes and upper respiratory tract. Prolonged exposure of unprotected skin to the inhibitor may cause dermatitis.

The IFKHAN-1 inhibitor is chemically stable and does not form toxic compounds in air and wastewater in the presence of other substances.

Liquid inhibitor IFKHAN-1 is a flammable liquid. The ignition temperature of the liquid inhibitor is 47 °C, the auto-ignition temperature is 315 °C. When a fire occurs, the following fire extinguishing agents are used: fire felt, foam fire extinguishers, DU fire extinguishers.

Cleaning of premises should be carried out using a wet method.

When working with the IFKHAN-1 inhibitor, it is necessary to use personal protective equipment - a suit made of cotton fabric (robe), rubber gloves.

Inhibitor IFKHAN-100, also a derivative of amines, is less toxic. A relatively safe exposure level is 10 mg/dm3; ignition temperature 114 °C, self-ignition temperature 241 °C.

Safety measures when working with the IFKHAN-100 inhibitor are the same as when working with the IFKHAN-1 inhibitor.

It is prohibited to carry out work inside the equipment until it is re-opened.

At high concentrations of inhibitor in the air or if it is necessary to work inside the equipment after its re-opening, a gas mask of grade A with a filter box of grade A should be used (GOST 12.4.121-83 and
GOST 12.4.122-83). The equipment should be ventilated first. Work inside the equipment after re-preservation should be carried out by a team of two people.

After finishing working with the inhibitor, you must wash your hands with soap.

If the liquid inhibitor gets on your skin, wash it off with soap and water; if it gets into your eyes, rinse them with plenty of water.
Control questions

1. 
   Types of corrosion processes.
2. 
   Describe chemical and electrochemical corrosion.
3. 
   The influence of external and internal factors on metal corrosion.
4. 
   Corrosion of the condensate-feed tract of boiler units and heating networks.
5. 
   Corrosion of steam turbines.
6. 
   Corrosion of equipment in the make-up and network tracts of the heating network.
7. 
   Basic methods of water treatment to reduce the intensity of corrosion of heating systems.
8. 
   The purpose of conservation of thermal power equipment.
9. 
   List the methods of preservation:

a) steam boilers;

B) hot water boilers;

B) turbine units;

D) heating networks.

10. Give a brief description of the chemical reagents used.

Corrosion phenomena in boilers most often appear on the internal heat-stressed surface and relatively less often on the external surface.

In the latter case, the destruction of the metal is caused - in most cases - by the combined action of corrosion and erosion, which sometimes has a predominant significance.
An external sign of erosion destruction is a clean metal surface. When exposed to corrosion, corrosion products usually remain on its surface.
Internal (in an aquatic environment) corrosion and scale processes can aggravate external corrosion (in a gaseous environment) due to thermal resistance layer of scale and corrosion deposits, and, consequently, an increase in temperature on the metal surface.
External metal corrosion (from the side of the boiler furnace) depends on various factors, but, first of all, on the type and composition of the fuel burned.

Corrosion of gas-oil boilers
Fuel oil contains organic compounds of vanadium and sodium. If molten deposits of slag containing vanadium (V) compounds accumulate on the wall of the pipe facing the furnace, then with a large excess of air and/or a metal surface temperature of 520-880 oC, the following reactions occur:
4Fe + 3V2O5 = 2Fe2O3 + 3V2O3 (1)
V2O3 + O2 = V2O5 (2)
Fe2O3 + V2O5 = 2FeVO4 (3)
7Fe + 8FeVO4 = 5Fe3O4 + 4V2O3 (4)
(Sodium compounds) + O2 = Na2O (5)
Another corrosion mechanism involving vanadium (liquid eutectic mixture) is also possible:
2Na2O. V2O4. 5V2O5 + O2 = 2Na2O. 6V2O5 (6)
Na2O. 6V2O5 + M = Na2O. V2O4. 5V2O5 + MO (7)
(M - metal)
Vanadium and sodium compounds are oxidized to V2O5 and Na2O during fuel combustion. In deposits that adhere to the metal surface, Na2O is a binder. The liquid formed as a result of reactions (1)-(7) melts the protective film of magnetite (Fe3O4), which leads to oxidation of the metal under the deposits (melting temperature of deposits (slag) - 590-880 oC).
As a result of these processes, the walls of the screen pipes facing the firebox become evenly thinner.
The increase in metal temperature, at which vanadium compounds become liquid, is promoted by internal scale deposits in pipes. And thus, when the temperature of the metal’s yield point is reached, a pipe rupture occurs - a consequence of the combined action of external and internal deposits.
The fastening parts of the pipe screens, as well as the protrusions of the weld seams of the pipes, also corrode - the temperature rise on their surface accelerates: they are not cooled by the steam-water mixture, like pipes.
Fuel oil may contain sulfur (2.0-3.5%) in the form of organic compounds, elemental sulfur, sodium sulfate (Na2SO4), which enters the oil from formation waters. On the metal surface under such conditions, vanadium corrosion is accompanied by sulfide-oxide corrosion. Their combined effect is most pronounced when 87% V2O5 and 13% Na2SO4 are present in the sediments, which corresponds to the content of vanadium and sodium in fuel oil in a ratio of 13/1.
In winter, when heating fuel oil with steam in containers (to facilitate draining), water in the amount of 0.5-5.0% additionally enters it. Consequence: the amount of deposits on the low-temperature surfaces of the boiler increases, and, obviously, the corrosion of fuel oil lines and fuel oil tanks increases.

In addition to the above-described scheme of destruction of boiler screen pipes, corrosion of steam superheaters, festoon pipes, boiler bundles, economizers has some peculiarities due to increased - in some sections - gas velocities, especially those containing unburned fuel oil particles and exfoliated slag particles.

Corrosion identification
The outer surface of the pipes is covered with a dense enamel-like layer of gray and dark gray deposits. On the side facing the firebox, there is a thinning of the pipe: flat areas and shallow cracks in the form of “scores” are clearly visible if the surface is cleaned of deposits and oxide films.
If the pipe is accidentally destroyed, then a through longitudinal narrow crack is visible.

Corrosion of pulverized coal boilers
In corrosion caused by the action of coal combustion products, sulfur and its compounds are of decisive importance. In addition, the course of corrosion processes is affected by chlorides (mainly NaCl) and alkali metal compounds. Corrosion is most likely when coal contains more than 3.5% sulfur and 0.25% chlorine.
Fly ash, containing alkaline compounds and sulfur oxides, is deposited on the metal surface at a temperature of 560-730 oC. In this case, as a result of the reactions that occur, alkali sulfates are formed, for example K3Fe(SO4)3 and Na3Fe(SO4)3. This molten slag, in turn, destroys (melts) the protective oxide layer on the metal - magnetite (Fe3O4).
The corrosion rate is maximum at a metal temperature of 680-730 °C; as it increases, the rate decreases due to the thermal decomposition of corrosive substances.
The greatest corrosion occurs in the outlet pipes of the superheater, where the steam temperature is highest.

Corrosion identification
On screen pipes, you can observe flat areas on both sides of the pipe that are subject to corrosion damage. These areas are located at an angle of 30-45°C to each other and are covered with a layer of sediment. Between them is a relatively “clean” area exposed to the “frontal” influence of the gas flow.
The deposits consist of three layers: an outer layer of porous fly ash, an intermediate layer of whitish water-soluble alkali sulfates, and an inner layer of shiny black iron oxides (Fe3O4) and sulfides (FeS).
On low-temperature parts of boilers - economizer, air heater, exhaust fan - the metal temperature drops below the “dew point” of sulfuric acid.
When burning solid fuel, the gas temperature decreases from 1650 °C in the torch to 120 °C or less in the chimney.
Due to the cooling of gases, sulfuric acid is formed in the vapor phase, and upon contact with more cold surface metal vapors condense to form liquid sulfuric acid. The “dew point” of sulfuric acid is 115-170 °C (it can be more - it depends on the content of water vapor and sulfur oxide (SO3) in the gas flow).
The process is described by the reactions:
S + O2 = SO2 (8)
SO3 + H2O = H2SO4 (9)
H2SO4 + Fe = FeSO4 + H2 (10)
In the presence of iron and vanadium oxides, catalytic oxidation of SO3 is possible:
2SO2 + O2 = 2SO3 (11)
In some cases, sulfuric acid corrosion when burning coal is less significant than when burning brown, shale, peat and even natural gas- due to the relatively greater release of water vapor from them.

Corrosion identification
This type of corrosion causes uniform destruction of the metal. Typically the surface is rough, with a slight coating of rust, and is similar to a non-corrosive surface. With prolonged exposure, the metal may become covered with deposits of corrosion products, which must be carefully removed during inspection.

Corrosion during breaks in operation
This type of corrosion occurs on the economizer and in those areas of the boiler where the outer surfaces are coated with sulfur compounds. As the boiler cools, the metal temperature drops below the “dew point” and, as described above, if there are sulfur deposits, sulfuric acid is formed. A possible intermediate is sulfurous acid (H2SO3), but it is very unstable and immediately turns into sulfuric acid.

Corrosion identification
Metal surfaces are usually coated with coatings. If you remove them, you will find areas of metal destruction where there were sulfur deposits and areas of uncorroded metal. This appearance distinguishes corrosion on a stopped boiler from the above-described corrosion of the economizer metal and other “cold” parts of a running boiler.
When washing the boiler, corrosion phenomena are distributed more or less evenly over the metal surface due to the erosion of sulfur deposits and insufficient drying of surfaces. With insufficient cleaning, corrosion is localized where sulfur compounds were.

Metal erosion
Under certain conditions, metal is subjected to erosive destruction different systems boiler both from the inside and outside of the heated metal, and where turbulent flows occur at high speed.
Only turbine erosion is discussed below.
Turbines are subject to erosion from impacts from solid particles and steam condensate droplets. Solid particles (oxides) flake off the internal surfaces of superheaters and steam lines, especially during thermal transient conditions.

Droplets of steam condensate mainly destroy the surfaces of the blades of the last stage of the turbine and drainage pipelines. Erosion-corrosive effects of steam condensate are possible if the condensate is “acidic” - the pH is below five units. Corrosion is also dangerous in the presence of chloride vapor (up to 12% of the mass of deposits) and caustic soda in water droplets.

Erosion identification
Metal destruction from impacts of condensate drops is most noticeable at the leading edges of turbine blades. The edges are covered with thin transverse teeth and grooves (grooves); there may be inclined conical projections directed towards the impacts. There are protrusions on the leading edges of the blades and are almost absent on their posterior planes.
Damage from solid particles takes the form of tears, microdents and nicks on the leading edges of the blades. There are no grooves or inclined cones.