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 °C. 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 a number of 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 steam generators high pressure. 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.
2.1. Heating surfaces.
The most typical damage to heating surface pipes are: cracks on the surface of screen and boiler pipes, corrosion attacks on the outer and inner surfaces of pipes, ruptures, thinning of pipe walls, cracks and destruction of bells.
Causes of cracks, ruptures and fistulas: deposits in boiler pipes of salts, corrosion products, welding beads that slow down circulation and cause overheating of the metal, external mechanical damage, disruption of the water chemistry regime.
Corrosion of the outer surface of pipes is divided into low-temperature and high-temperature. Low-temperature corrosion occurs in places where blowers are installed, when, as a result of improper operation, condensation is allowed to form on soot-covered heating surfaces. High temperature corrosion can occur in the second stage of the superheater when burning sour fuel oil.
The most common corrosion of the inner surface of pipes occurs when corrosive gases (oxygen, carbon dioxide) or salts (chlorides and sulfates) contained in boiler water interact with the metal of the pipes. Corrosion of the inner surface of pipes manifests itself in the formation of pockmarks, ulcers, cavities and cracks.
Corrosion of the inner surface of pipes also includes: oxygen stagnation corrosion, sub-sludge alkaline corrosion of boiler and screen pipes, corrosion fatigue, which manifests itself in the form of cracks in boiler and screen pipes.
Pipe damage due to creep is characterized by an increase in diameter and the formation of longitudinal cracks. Deformations in places where pipes are bent and welded joints may have different directions.
Burnouts and scale formation in pipes occur due to their overheating to temperatures exceeding the design temperature.
The main types of damage to welds made by manual arc welding are fistulas that arise due to lack of penetration, slag inclusions, gas pores, and lack of fusion along the edges of pipes.
The main defects and damage to the surface of the superheater are: corrosion and scaling on the outer and inner surfaces of pipes, cracks, risks and delamination of pipe metal, fistulas and ruptures of pipes, defects in welded pipe joints, residual deformation as a result of creep.
Damage to the fillet welds of welding coils and fittings to the collectors, caused by a violation of the welding technology, has the form of annular cracks along the fusion line from the side of the coil or fittings.
Typical malfunctions that arise during the operation of the surface desuperheater of the DE-25-24-380GM boiler are: internal and external corrosion of pipes, cracks and fistulas in welded
seams and pipe bends, cavities that may occur during repairs, risks on the surface of flanges, leaks of flange connections due to flange misalignment. During a hydraulic test of the boiler, you can
determine only the presence of leaks in the desuperheater. To identify hidden defects, an individual hydraulic test of the desuperheater should be carried out.
2.2. Boiler drums.
Typical damage to boiler drums are: cracks-tears on the inner and outer surfaces of the shells and bottoms, cracks-tears around the pipe holes on the inner surface of the drums and on the cylindrical surface of the pipe holes, intercrystalline corrosion of the shells and bottoms, corrosion separation of the surfaces of the shells and bottoms, drum ovality Oddulins (bulges) on the surfaces of the drums facing the furnace, caused by the temperature effect of the torch in cases of destruction (or loss) of individual parts of the lining.
2.3. Metal structures and boiler lining.
Depending on the quality of preventive work, as well as on the modes and periods of operation of the boiler, its metal structures may have the following defects and damage: breaks and bends of racks and links, cracks, corrosion damage to the metal surface.
As a result of prolonged exposure to temperatures, cracking and damage to the integrity of the shaped bricks fixed on pins to the upper drum from the side of the firebox occur, as well as cracks in the brickwork along the lower drum and the hearth of the firebox.
Particularly common is the destruction of the brick embrasure of the burner and violation of the geometric dimensions due to the melting of the brick.
3. Checking the condition of the boiler elements.
The condition of boiler elements taken out for repair is checked based on the results of a hydraulic test, external and internal inspection, as well as other types of control carried out in the scope and in accordance with the boiler expert inspection program (section “Boiler Expert Inspection Program”).
3.1. Checking heating surfaces.
Inspection of the outer surfaces of pipe elements must be carried out especially carefully in places where pipes pass through lining, casing, in areas of maximum thermal stress - in the area of burners, hatches, manholes, as well as in places where screen pipes are bent and at welds.
To prevent accidents associated with thinning of pipe walls due to sulfur and static corrosion, it is necessary, during annual technical inspections carried out by the enterprise administration, to inspect the pipes of the heating surfaces of boilers that have been in operation for more than two years.
Control is carried out by external inspection with tapping the pre-cleaned outer surfaces of the pipes with a hammer weighing no more than 0.5 kg and measuring the thickness of the pipe walls. In this case, you should select the sections of pipes that have undergone the greatest wear and corrosion (horizontal sections, areas in soot deposits and covered with coke deposits).
The thickness of pipe walls is measured using ultrasonic thickness gauges. It is possible to cut out sections of pipes on two or three pipes of the combustion screens and pipes of the convective beam located at the gas inlet and outlet. The remaining thickness of the pipe walls must be no less than the calculated one according to the strength calculation (attached to the Boiler Certificate), taking into account an increase for corrosion for the period of further operation until the next inspection and an increase in the margin of 0.5 mm.
The calculated wall thickness of screen and boiler pipes for a working pressure of 1.3 MPa (13 kgf/cm2) is 0.8 mm, for 2.3 MPa (23 kgf/cm2) – 1.1 mm. The corrosion allowance is taken based on the measurement results obtained and taking into account the duration of operation between surveys.
At enterprises where, as a result of long-term operation, intensive wear of heating surface pipes has not been observed, pipe wall thickness can be monitored during major repairs, but at least once every 4 years.
The collector, superheater and rear screen are subject to internal inspection. The hatches of the upper manifold of the rear screen must be subjected to mandatory opening and inspection.
The outer diameter of the pipes should be measured in the maximum temperature zone. For measurements, use special templates (staples) or calipers. Dents with smooth transitions with a depth of no more than 4 mm are allowed on the surface of the pipes, if they do not take the wall thickness beyond the limits of minus deviations.
The permissible difference in pipe wall thickness is 10%.
The results of inspection and measurements are recorded in the repair form.
3.2. Checking the drum.
When areas of the drum damaged by corrosion are identified, it is necessary to inspect the surface before internal cleaning In order to determine the intensity of corrosion, measure the depth of metal corrosion.
Measure uniform corrosion along the thickness of the wall, in which a hole with a diameter of 8 mm is drilled for this purpose. After measuring, install a plug in the hole and scald on both sides or, in extreme cases, only from the inside of the drum. The measurement can also be made with an ultrasonic thickness gauge.
Measure the main corrosion and ulcers using impressions. For this purpose, clean the damaged area of the metal surface from deposits and lightly lubricate it with technical petroleum jelly. The most accurate imprint is obtained if the damaged area is located on a horizontal surface, and in this case it is possible to fill it with molten metal with a low melting point. The hardened metal forms an exact impression of the damaged surface.
To obtain prints, use a tertiary, babbitt, tin, and, if possible, use plaster.
Impressions of damage located on vertical ceiling surfaces can be obtained using wax and plasticine.
Inspection of pipe holes and drums is carried out in the following order.
After removing the flared pipes, check the diameter of the holes using a template. If the template enters the hole up to the stop protrusion, this means that the diameter of the hole is increased beyond the norm. The exact diameter is measured using a caliper and noted in the repair form.
When inspecting drum welds, it is necessary to check the adjacent base metal to a width of 20-25 mm on both sides of the seam.
The out-of-roundness of the drum is measured at least every 500 mm along the length of the drum, and more often in doubtful cases.
Measuring the drum deflection is carried out by stretching the string along the surface of the drum and measuring the gaps along the length of the string.
Control of the surface of the drum, pipe holes and welded joints is carried out by external inspection, methods, magnetic particle, color and ultrasonic flaw detection.
Dents and dents outside the area of seams and holes are allowed (do not require straightening), provided that their height (deflection), as a percentage of the smallest size of their base, will not be more than:
towards atmospheric pressure (outward) - 2%;
towards steam pressure (dents) - 5%.
The permissible reduction in the thickness of the bottom wall is 15%.
The permissible increase in the diameter of holes for pipes (for welding) is 10%.
MINISTRY OF ENERGY AND ELECTRIFICATION OF THE USSR
MAIN SCIENTIFIC AND TECHNICAL DIRECTORATE OF ENERGY AND ELECTRIFICATION
METHODOLOGICAL INSTRUCTIONS
BY WARNING
LOW TEMPERATURE
SURFACE CORROSION
HEATING AND GAS FLOW OF BOILERS
RD 34.26.105-84
SOYUZTEKHENERGO
Moscow 1986
DEVELOPED by the All-Union Twice Order of the Red Banner of Labor Thermal Engineering Research Institute named after F.E. Dzerzhinsky
PERFORMERS R.A. PETROSYAN, I.I. NADIROV
APPROVED by the Main Technical Directorate for the Operation of Power Systems on April 22, 1984.
Deputy Chief D.Ya. SHAMARAKOV
|
METHODOLOGICAL INSTRUCTIONS FOR PREVENTION OF LOW TEMPERATURE CORROSION OF HEATING SURFACES AND GAS FLUES OF BOILERS |
RD 34.26.105-84 |
Expiration date set
from 07/01/85
until 07/01/2005
These Guidelines apply to low-temperature heating surfaces of steam and hot water boilers (economizers, gas evaporators, air heaters various types etc.), as well as on the gas path behind the air heaters (gas ducts, ash collectors, smoke exhausters, chimneys) and establish methods for protecting heating surfaces from low-temperature corrosion.
The guidelines are intended for thermal power plants operating on sulfur fuels and organizations designing boiler equipment.
1. Low-temperature corrosion is the corrosion of the tail heating surfaces, gas ducts and chimneys of boilers under the influence of condensing on them flue gases sulfuric acid vapor.
2. Condensation of sulfuric acid vapor, the volumetric content of which in flue gases when burning sulfurous fuels is only a few thousandths of a percent, occurs at temperatures significantly (50 - 100 °C) higher than the condensation temperature of water vapor.
4. To prevent corrosion of heating surfaces during operation, the temperature of their walls must exceed the dew point temperature of the flue gases at all boiler loads.
For heating surfaces cooled by a medium with a high heat transfer coefficient (economizers, gas evaporators, etc.), the temperature of the medium at their inlet should exceed the dew point temperature by approximately 10 °C.
5. For the heating surfaces of hot water boilers when operating on sulfur fuel oil, the conditions for completely eliminating low-temperature corrosion cannot be realized. To reduce it, it is necessary to ensure that the water temperature at the boiler inlet is 105 - 110 °C. When using water heating boilers as peak boilers, this mode can be ensured with full use of network water heaters. When using hot water boilers in the main mode, increasing the temperature of the water entering the boiler can be achieved by recirculating hot water.
In installations using the scheme for connecting water heating boilers to the heating network through water heat exchangers, the conditions for reducing low-temperature corrosion of heating surfaces are fully ensured.
6. For air heaters of steam boilers, complete exclusion of low-temperature corrosion is ensured when the design temperature of the wall of the coldest section exceeds the dew point temperature at all boiler loads by 5 - 10 °C (the minimum value refers to the minimum load).
7. Calculation of the wall temperature of tubular (TVP) and regenerative (RVP) air heaters is carried out according to the recommendations “ Thermal calculation boiler units. Normative method" (Moscow: Energy, 1973).
8. When using replaceable cold cubes or cubes made from pipes with an acid-resistant coating (enameled, etc.), as well as those made from corrosion-resistant materials, as the first (air) stroke in tubular air heaters, the following are checked for the conditions of complete exclusion of low-temperature corrosion (by air) metal cubes of the air heater. In this case, the choice of the wall temperature of cold metal cubes, replaceable, as well as corrosion-resistant cubes, should exclude intense contamination of the pipes, for which their minimum wall temperature when burning sulfur fuel oil should be below the dew point of the flue gases by no more than 30 - 40 ° C. When burning solid sulfur fuels, the minimum temperature of the pipe wall, in order to prevent intensive pollution, should be taken to be at least 80 °C.
9. In RVP, under the conditions of complete exclusion of low-temperature corrosion, their hot part is calculated. The cold part of the RVP is corrosion-resistant (enamelled, ceramic, low-alloy steel, etc.) or replaceable from flat metal sheets 1.0 - 1.2 mm thick, made of low-carbon steel. The conditions for preventing intense contamination of the packing are met when the requirements of paragraphs of this document are met.
10. Enameled packing is made from metal sheets with a thickness of 0.6 mm. The service life of enamel packing manufactured in accordance with TU 34-38-10336-89 is 4 years.
Porcelain tubes can be used as ceramic filling, ceramic blocks, or porcelain plates with projections.
Considering the reduction in fuel oil consumption by thermal power plants, it is advisable to use packing made of low-alloy steel 10KhNDP or 10KhSND for the cold part of the RVP, the corrosion resistance of which is 2 - 2.5 times higher than that of low-carbon steel.
11. To protect air heaters from low-temperature corrosion during the startup period, the measures set out in the “Guidelines for the design and operation of energy heaters with wire fins” (M.: SPO Soyuztekhenergo, 1981) should be carried out.
Ignition of a boiler using sulfur fuel oil should be carried out with the air heating system previously turned on. The air temperature in front of the air heater during the initial period of kindling should be, as a rule, 90 °C.
11a. To protect air heaters from low-temperature (“parking”) corrosion when the boiler is stopped, the level of which is approximately twice the corrosion rate during operation, before stopping the boiler, the air heaters should be thoroughly cleaned of external deposits. In this case, before stopping the boiler, it is recommended to maintain the air temperature at the inlet to the air heater at its value at the rated load of the boiler.
Cleaning of TVP is carried out with shot with a feed density of at least 0.4 kg/m.s (clause of this document).
For solid fuels Taking into account the significant risk of corrosion of ash collectors, the temperature of the flue gases should be selected above the dew point of the flue gases by 15 - 20 °C.
For sulfur fuel oils, the temperature of the flue gases must exceed the dew point temperature at the rated boiler load by approximately 10 °C.
Depending on the sulfur content in the fuel oil, the calculated value of the flue gas temperature at the rated boiler load, indicated below, should be taken:
Flue gas temperature, ºС...... 140 150 160 165
When burning sulfur fuel oil with extremely low excess air (α ≤ 1.02), the temperature of the flue gases can be taken lower, taking into account the results of dew point measurements. On average, the transition from small to extremely small excess air reduces the dew point temperature by 15 - 20 °C.
The conditions for ensuring reliable operation of the chimney and preventing moisture loss on its walls are affected not only by the temperature of the flue gases, but also by their flow rate. Operating a pipe under load conditions significantly lower than design increases the likelihood of low-temperature corrosion.
When burning natural gas, it is recommended that the flue gas temperature be no lower than 80 °C.
13. When reducing the boiler load in the range of 100 - 50% of the nominal one, one should strive to stabilize the flue gas temperature, not allowing it to decrease by more than 10 °C from the nominal one.
The most economical way to stabilize the flue gas temperature is to increase the air preheating temperature in the air heaters as the load decreases.
The minimum permissible temperatures for air preheating before the RAH are adopted in accordance with clause 4.3.28 of the “Rules for the technical operation of power plants and networks” (M.: Energoatomizdat, 1989).
In cases where optimal temperatures flue gases cannot be provided due to the insufficient heating surface of the RAH, air preheating temperatures must be adopted at which the temperature of the flue gases will not exceed the values given in paragraphs of these Guidelines.
16. Due to the lack of reliable acid-resistant coatings to protect metal flue ducts from low-temperature corrosion, their reliable operation can be ensured by careful insulation, ensuring a temperature difference between the flue gases and the wall of no more than 5 °C.
The insulating materials and structures currently used are not reliable enough for long-term operation, so it is necessary to periodically, at least once a year, monitor their condition and, if necessary, carry out repair and restoration work.
17. When using various coatings on a trial basis to protect gas ducts from low-temperature corrosion, it should be taken into account that the latter must provide heat resistance and gas tightness at temperatures exceeding the temperature of flue gases by at least 10 ° C, resistance to sulfuric acid concentrations of 50 - 80% in the temperature range, respectively, 60 - 150 ° C and the possibility of their repair and restoration.
18. For low-temperature surfaces, structural elements of RVP and boiler flues, it is advisable to use low-alloy steels 10KhNDP and 10KhSND, which are 2 - 2.5 times superior in corrosion resistance to carbon steel.
Only very scarce and expensive high-alloy steels have absolute corrosion resistance (for example, EI943 steel, containing up to 25% chromium and up to 30% nickel).
Application
1. Theoretically, the dew point temperature of flue gases with a given content of sulfuric acid and water vapor can be determined as the boiling point of a sulfuric acid solution of such a concentration at which the same content of water vapor and sulfuric acid exists above the solution.
The measured value of the dew point temperature, depending on the measurement technique, may not coincide with the theoretical one. In these recommendations for the flue gas dew point temperature tr The temperature of the surface of a standard glass sensor with 7 mm long platinum electrodes soldered at a distance of 7 mm from one another is assumed, at which the resistance of the dew film between the electrodes in a steady state is 107 Ohms. The electrode measuring circuit uses low voltage alternating current (6 - 12 V).
2. When burning sulfur fuel oils with excess air of 3 - 5%, the dew point temperature of the flue gases depends on the sulfur content in the fuel Sp(rice.).
When burning sulfur fuel oils with extremely low excess air (α ≤ 1.02), the flue gas dew point temperature should be taken based on the results of special measurements. The conditions for transferring boilers to a mode with α ≤ 1.02 are set out in the “Guidelines for transferring boilers operating on sulfur fuels to a combustion mode with extremely low excess air” (M.: SPO Soyuztekhenergo, 1980).
3. When burning sulfurous solid fuels in a dusty state, the dew point temperature of the flue gases tp can be calculated based on the given content of sulfur and ash in the fuel Sppr, Arpr and water vapor condensation temperature tcon according to the formula
Where aun- the proportion of ash in the carryover (usually taken to be 0.85).
Rice. 1. Dependence of flue gas dew point temperature on sulfur content in burned fuel oil
The value of the first term of this formula at aun= 0.85 can be determined from Fig. .
Rice. 2. Temperature differences between the dew point of flue gases and the condensation of water vapor in them, depending on the given sulfur content ( Sppr) and ash ( Arpr) in fuel
4. When burning gaseous sulfur fuels, the dew point of the flue gases can be determined from Fig. provided that the sulfur content in the gas is calculated as given, that is, as a percentage by weight per 4186.8 kJ/kg (1000 kcal/kg) of the calorific value of the gas.
For gas fuel the given sulfur content as a percentage by mass can be determined by the formula
Where m- the number of sulfur atoms in the molecule of the sulfur-containing component;
q- volume percentage of sulfur (sulfur-containing component);
Qn- heat of combustion of gas in kJ/m3 (kcal/Nm3);
WITH- coefficient equal to 4.187, if Qn expressed in kJ/m3 and 1.0 if in kcal/m3.
5. The rate of corrosion of the replaceable metal packing of air heaters when burning fuel oil depends on the temperature of the metal and the degree of corrosiveness of the flue gases.
When burning sulfur fuel oil with an excess of air of 3 - 5% and blowing the surface with steam, the corrosion rate (on both sides in mm/year) of the RVP packing can be approximately estimated from the data in Table. .
Table 1
|
Corrosion rate (mm/year) at wall temperature, ºС |
||||||||
|
0.5More than 2 0.20 |
||||||||
|
St. 0.11 to 0.4 incl. |
||||||||
|
St. 0.41 to 1.0 incl. |
||||||||
6. For coals with a high content of calcium oxide in the ash, the dew point temperatures are lower than those calculated according to paragraphs of these Guidelines. For such fuels, it is recommended to use the results of direct measurements.
n1.doc
3.4. Corrosion of steam generator elements3.4.1. 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, the inlet sections of water economizers, drums and downpipes of circulation circuits may be subject to oxygen corrosion. 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 akh includes two stages: the initial electrochemical and the final chemical. According to this corrosion mechanism, ferrous ions diffuse through the oxide film to the surface in 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. If sodium nitrite is present in the feed water, corrosion of the steam generator metal is observed, which has appearance 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 that enters the steam generators in cases where feed water, containing an increased amount of ammonia, oxygen and free carbon dioxide, aggressively affects the brass and copper pipes of 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, are also precipitated in the form of sludge-like copper oxides under alkaline conditions. 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 the 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 a value of?t s = 7 °C the concentration of NaOH in the film concentrated water is 10%, and when
?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 continuous occurrence of the 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 in 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 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 intergranular fractures of boiler metal, it is not essential absolute value alkalinity, and the proportion of caustic soda in the total salt composition of boiler water. Installed empirically, that if this proportion, i.e. the relative concentration of caustic soda in the boiler water, is less than 10–15% of the sum 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 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 to thermal stresses of variable sign and magnitude simultaneously with the corrosive environment, 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 nature, 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, being 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 materials. stainless steels(chrome-nickel, chrome-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 oxygen-saturated water during downtime. 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 are absorbed 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. The saline solution formed during turbine downtime 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 with inside, washed by cooling water, and from the outside. The internal surfaces of condenser tubes, cooled by highly mineralized, salty lake waters containing large amounts of chlorides, or circulating water, corrode intensively. circulating waters with increased mineralization and contaminated suspended particles.
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 brass corrosion 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-hazardous 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 cooling water losses in the circulating water supply systems of thermal power plants, fresh waters, with increased mineralization, or contaminated with corrosive industrial and domestic wastewater.
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. The service life of the tubes is also reduced by contamination of their surface with corrosion products and other deposits, leading to the formation of ulcers under the deposits. 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.
Average term The 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 for heating, cold water supply and sewerage systems at 20–25 years, then for hot water supply systems at closed scheme heat supply 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 supply pipelines without protective coatings are susceptible to internal corrosion and significant contamination with its products. This leads to a decrease bandwidth communications, increased hydraulic losses and disruptions in the supply of hot water, especially in upper floors buildings with insufficient pressure from 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 with 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 trend towards consolidating the capacity of individual installations leads to a branching network of hot water supply pipelines, 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 effect 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). For negative values of the saturation index, the depth 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 permeability of corrosion 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/dm3 | 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 causes their high corrosive activity.
When assessing the corrosive activity of surface waters, it is necessary to take into account the variability of their composition throughout the year. For a more reliable assessment, you should use data from not just a single, but as many as possible 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 of drinking water in one city, the intensity and 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 new residential buildings basements suitable for placing hot water supply equipment; inadmissibility of installing conventional (non-silent) circulation pumps in individual heating points; expected reduction service personnel as a result of replacing 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. In recent years, the construction of new series of houses with basements and the 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 metal corrosion internal surfaces carried out during regime shutdowns and withdrawal to reserve for a definite and indefinite period: withdrawal - to the current, average, major renovation; emergency shutdowns, for long-term reserve or repair, for reconstruction for a period exceeding 6 months.
Based on the 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 conservation methods 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 chemical cleaning equipment, tank facilities of the power plant.
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 on 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, should be taken additional measures safety related to the properties of the used chemical reagents.
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 in the absence of rolling pipe-to-drum connections.
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 heat accumulated by 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 pressure in the boiler above atmospheric pressure 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. In addition to the above preservation methods, the following are used on drum boilers:
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. When in contact with metal, its stability protective film forms 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 on the metal surface in the form of the Fe 3 O 4 ·FeSiO 3 compound. 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 moist air from entering the internal cavities and causing corrosion processes. Moisture ingress on the surfaces of the turbine flow path 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 make-up water 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 a given heating temperature of the network water, taking into account the boiler pipes of 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 a sodium silicate solution, then heating networks in the summer 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 ingress of porous substances and organic compounds into them.
Hoses must be connected to the places where hydrazine solutions are prepared and stored to wash off spilled solutions from 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, use 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
it is necessary to rinse them with a stream of water, and then with a solution of boric acid and go to a medical center.
Sodium silicate (sodium liquid glass)
Commercial liquid glass is a thick solution of yellow or gray, 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. 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). The maximum permissible concentration in the air of the working area for the inhibitor should not exceed 10 mg/dm 3 .
The inhibitor is chemically stable and does not form toxic compounds in 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-preservation, 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.
Security questions
Types of corrosion processes.
Describe chemical and electrochemical corrosion.
The influence of external and internal factors on metal corrosion.
Corrosion of the condensate-feed tract of boiler units and heating networks.
Corrosion of steam turbines.
Corrosion of equipment in the make-up and network tracts of the heating network.
Basic methods of water treatment to reduce the intensity of corrosion of heating systems.
The purpose of conservation of thermal power equipment.
List the methods of preservation:
B) hot water boilers;
B) turbine units;
D) heating networks.
10. Give a brief description of the chemical reagents used.
Owners of patent RU 2503747:
TECHNICAL FIELD
The invention relates to heat power engineering and can be used to protect heating pipes of steam and hot water boilers, heat exchangers, boiler units, evaporators, heating mains, heating systems from scale residential buildings and industrial facilities in the process of current operation.
BACKGROUND OF THE ART
The operation of steam boilers is associated with simultaneous exposure to high temperatures, pressure, mechanical stress and an aggressive environment, which is boiler water. Boiler water and the metal of the boiler heating surfaces are separate phases of a complex system that is formed upon their contact. The result of the interaction of these phases is surface processes that occur at their interface. As a result, corrosion and scale formation occur in the metal of the heating surfaces, which leads to changes in the structure and mechanical properties of the metal, and which contributes to the development of various damages. Since the thermal conductivity of scale is fifty times lower than that of iron heating pipes, there are losses of thermal energy during heat transfer - with a scale thickness of 1 mm from 7 to 12%, and with 3 mm - 25%. Severe scale formation in the steam boiler system continuous action often causing production to stop for several days a year to remove scale.
The quality of feed water and, therefore, boiler water is determined by the presence of impurities that can cause various types of corrosion of the metal of internal heating surfaces, the formation of primary scale on them, as well as sludge as a source of secondary scale formation. In addition, the quality of boiler water also depends on the properties of substances formed as a result of surface phenomena during water transportation and condensate through pipelines during water treatment processes. Removing impurities from feed water is one of the ways to prevent the formation of scale and corrosion and is carried out by methods of preliminary (pre-boiler) water treatment, which are aimed at maximizing the removal of impurities found in the source water. However, the methods used do not allow us to completely eliminate the content of impurities in water, which is associated not only with technical difficulties, but also with the economic feasibility of using pre-boiler water treatment methods. In addition, since water treatment is complex technical system, it is redundant for boilers of low and medium productivity.
Known methods for removing already formed deposits mainly use mechanical and chemical cleaning methods. The disadvantage of these methods is that they cannot be produced during the operation of the boilers. In addition, chemical cleaning methods often require the use of expensive chemicals.
There are also known methods to prevent the formation of scale and corrosion, carried out during the operation of boilers.
US patent 1877389 proposes a method for removing scale and preventing its formation in hot water and steam boilers. In this method, the surface of the boiler is the cathode, and the anode is placed inside the pipeline. The method involves passing direct or alternating current through the system. The authors note that the mechanism of action of the method is that under the influence electric current Gas bubbles form on the surface of the boiler, which lead to the detachment of existing scale and prevent the formation of a new one. The disadvantage of this method is the need to constantly maintain the flow of electric current in the system.
US Pat. No. 5,667,677 proposes a method for treating a liquid, particularly water, in a pipeline to slow down the formation of scale. This method is based on creating in pipes electromagnetic field, which repels calcium and magnesium ions dissolved in water from the walls of pipes and equipment, preventing them from crystallizing in the form of scale, which allows the operation of boilers, boilers, heat exchangers, and cooling systems on hard water. The disadvantage of this method is the high cost and complexity of the equipment used.
Application WO 2004016833 proposes a method for reducing the formation of scale on a metal surface exposed to a supersaturated alkaline aqueous solution which is capable of forming scale after a period of exposure, comprising applying a cathodic potential to said surface.
This method can be used in various technological processes, in which the metal is in contact with an aqueous solution, in particular in heat exchangers. The disadvantage of this method is that it does not protect the metal surface from corrosion after removing the cathode potential.
Thus, there is currently a need to develop an improved method for preventing scale formation of heating pipes, hot water boilers and steam boilers, which would be economical and highly effective and provide anti-corrosion protection to the surface for a long period of time after exposure.
In the present invention, this problem is solved using a method according to which a current-carrying electric potential is created on a metal surface, sufficient to neutralize the electrostatic component of the adhesion force of colloidal particles and ions to the metal surface.
BRIEF DESCRIPTION OF THE INVENTION
An object of the present invention is to provide an improved method for preventing the formation of scale in heating pipes of hot water and steam boilers.
Another objective of the present invention is to provide the possibility of eliminating or significantly reducing the need for descaling during operation of hot water and steam boilers.
Another objective of the present invention is to eliminate the need to use consumable reagents to prevent the formation of scale and corrosion of heating pipes of water heating and steam boilers.
Another object of the present invention is to enable work to begin to prevent the formation of scale and corrosion of heating pipes of hot water and steam boilers on contaminated boiler pipes.
The present invention relates to a method for preventing the formation of scale and corrosion on a metal surface made of an iron-containing alloy and in contact with a steam-water environment from which scale is capable of forming. This method consists in applying to the specified metal surface a current-carrying electric potential sufficient to neutralize the electrostatic component of the adhesion force of colloidal particles and ions to the metal surface.
According to some private embodiments of the claimed method, the current-carrying potential is set in the range of 61-150 V. According to some private embodiments of the claimed method, the above iron-containing alloy is steel. In some embodiments, the metal surface is the interior surface of the heating tubes of a hot water or steam boiler.
The method disclosed herein has the following advantages. One advantage of the method is reduced scale formation. Another advantage of the present invention is the ability to use a working electrophysical apparatus once purchased without the need to use consumable synthetic reagents. Another advantage is the possibility of starting work on dirty boiler tubes.
The technical result of the present invention, therefore, is to increase the operating efficiency of hot water and steam boilers, increase productivity, increase heat transfer efficiency, reduce fuel consumption for heating the boiler, save energy, etc.
Other technical results and advantages of the present invention include providing the possibility of layer-by-layer destruction and removal of already formed scale, as well as preventing its new formation.
BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 shows the distribution of deposits on the internal surfaces of the boiler as a result of applying the method according to the present invention.
DETAILED DESCRIPTION OF THE INVENTION
The method of the present invention involves applying to a metal surface subject to scale formation a current-carrying electrical potential sufficient to neutralize the electrostatic component of the adhesion force of colloidal particles and scale-forming ions to the metal surface.
The term “conducting electrical potential” as used in this application means an alternating potential that neutralizes the electrical double layer at the interface of the metal and the water-steam medium containing salts that lead to scale formation.
As is known to a person skilled in the art, the carriers of electric charge in a metal, slow compared to the main charge carriers - electrons, are dislocations of its crystal structure, which carry an electric charge and form dislocation currents. Coming to the surface of the heating pipes of the boiler, these currents become part of the double electrical layer during the formation of scale. The current-carrying, electric, pulsating (i.e., alternating) potential initiates the removal of the electrical charge of dislocations from the metal surface to the ground. In this respect, it is a conductor of dislocation currents. As a result of the action of this current-carrying electrical potential, the electrical double layer is destroyed, and the scale gradually disintegrates and passes into the boiler water in the form of sludge, which is removed from the boiler during periodic purging.
Thus, the term “current-carrying potential” is understandable to a person skilled in the art and, in addition, is known from the prior art (see, for example, patent RU 2128804 C1).
As a device for creating a current-carrying electrical potential, for example, a device described in RU 2100492 C1 can be used, which includes a converter with a frequency converter and a pulsating potential regulator, as well as a pulse shape regulator. Detailed Description of this device is given in RU 2100492 C1. Any other similar device may also be used, as will be appreciated by one skilled in the art.
The conductive electrical potential according to the present invention can be applied to any part of the metal surface remote from the base of the boiler. The place of application is determined by the convenience and/or effectiveness of using the claimed method. One skilled in the art, using the information disclosed herein and using standard testing techniques, will be able to determine optimal place applications of current-carrying electrical potential.
In some embodiments of the present invention, the current-sinking electrical potential is variable.
The current-sinking electric potential according to the present invention can be applied for various periods of time. The time of application of the potential is determined by the nature and degree of contamination of the metal surface, the composition of the water used, temperature conditions and the operating features of the heating device and other factors known to specialists in this field of technology. One skilled in the art, using the information disclosed herein and using standard test procedures, will be able to determine the optimal time to apply the current-sinking electrical potential based on the objectives, conditions, and condition of the thermal device.
The magnitude of the current-carrying potential required to neutralize the electrostatic component of the adhesion force can be determined by a specialist in the field of colloid chemistry based on information known from the prior art, for example from the book B.V. Deryagin, N.V. Churaev, V.M. Muller. "Surface Forces", Moscow, "Nauka", 1985. According to some embodiments, the magnitude of the current-carrying electrical potential is in the range from 10 V to 200 V, more preferably from 60 V to 150 V, even more preferably from 61 V to 150 V. Values of the current-carrying electrical potential in the range from 61 V to 150 V lead to the discharge of the double electrical layer, which is the basis of the electrostatic component of the adhesion forces in scale and, as a consequence, destruction of scale. Values of the current-carrying potential below 61 V are insufficient to destroy scale, and at values of the current-carrying potential above 150 V, unwanted electrical erosion destruction of the metal of the heating tubes is likely to begin.
The metal surface to which the method according to the present invention can be applied can be part of the following thermal devices: heating pipes of steam and hot water boilers, heat exchangers, boiler units, evaporators, heating mains, heating systems of residential buildings and industrial facilities during ongoing operation. This list is illustrative and does not limit the list of devices to which the method according to the present invention can be applied.
In some embodiments, the iron-containing alloy from which the metal surface is made to which the method of the present invention can be applied may be steel or other iron-containing material such as cast iron, kovar, fechral, transformer steel, alsifer, magneto, alnico, chromium steel, invar, etc. This list is illustrative and does not limit the list of iron-containing alloys to which the method according to the present invention can be applied. One skilled in the art, based on knowledge known in the art, will be able to identify such iron-containing alloys that can be used according to the present invention.
The aqueous environment from which scale is capable of forming, according to some embodiments of the present invention, is tap water. The aqueous medium may also be water containing dissolved metal compounds. The dissolved metal compounds may be iron and/or alkaline earth metal compounds. The aqueous medium may also be an aqueous suspension of colloidal particles of iron and/or alkaline earth metal compounds.
The method according to the present invention removes previously formed deposits and serves as a reagent-free means of cleaning internal surfaces during operation of a heating device, subsequently ensuring its scale-free operation. In this case, the size of the zone within which the prevention of scale and corrosion is achieved significantly exceeds the size of the zone of effective scale destruction.
The method according to the present invention has the following advantages:
Does not require the use of reagents, i.e. environmentally friendly;
Easy to implement, does not require special devices;
Allows you to increase the heat transfer coefficient and increase the efficiency of boilers, which significantly affects the economic indicators of its operation;
Can be used as an addition to the applied methods of pre-boiler water treatment, or separately;
Allows you to abandon the processes of water softening and deaeration, which greatly simplifies technological scheme boiler rooms and makes it possible to significantly reduce costs during construction and operation.
Possible objects of the method can be hot water boilers, waste heat boilers, closed systems heat supply, installations for thermal desalination of sea water, steam conversion plants, etc.
The absence of corrosion damage and scale formation on internal surfaces opens up the possibility of developing fundamentally new design and layout solutions for low- and medium-power steam boilers. This will allow, due to the intensification of thermal processes, to achieve a significant reduction in the weight and dimensions of steam boilers. Ensure the specified temperature level of heating surfaces and, consequently, reduce fuel consumption, the volume of flue gases and reduce their emissions into the atmosphere.
EXAMPLE OF IMPLEMENTATION
The method claimed in the present invention was tested at the Admiralty Shipyards and Krasny Khimik boiler plants. The method according to the present invention has been shown to effectively clean the internal surfaces of boiler units from deposits. In the course of these works, fuel equivalent savings of 3-10% were obtained, while the variation in savings values is associated with varying degrees of contamination of the internal surfaces of the boiler units. The purpose of the work was to evaluate the effectiveness of the claimed method for ensuring reagent-free, scale-free operation of medium-power steam boilers under conditions of high-quality water treatment, compliance with the water chemical regime and high professional level equipment operation.
Testing of the method claimed in the present invention was carried out on steam boiler unit No. 3 DKVR 20/13 of the 4th Krasnoselskaya boiler house of the South-Western branch of the State Unitary Enterprise "TEK SPb". The operation of the boiler unit was carried out in strict accordance with the requirements of regulatory documents. Everything is installed on the boiler necessary funds control of its operating parameters (pressure and flow rate of generated steam, temperature and flow rate of feed water, pressure of blast air and fuel on the burners, vacuum in the main sections of the gas path of the boiler unit). The steam output of the boiler was maintained at 18 t/hour, the steam pressure in the boiler drum was 8.1…8.3 kg/cm 2 . The economizer operated in heating mode. City water supply water was used as the source water, which met the requirements of GOST 2874-82 “Drinking water”. It should be noted that the number of iron compounds entering the specified boiler room, as a rule, exceeds regulatory requirements(0.3 mg/l) and amounts to 0.3-0.5 mg/l, which leads to intensive overgrowing of internal surfaces with ferrous compounds.
The effectiveness of the method was assessed based on the condition of the internal surfaces of the boiler unit.
Assessment of the influence of the method according to the present invention on the condition of the internal heating surfaces of the boiler unit.
Before the start of the tests, an internal inspection of the boiler unit was carried out and the initial condition of the internal surfaces was recorded. A preliminary inspection of the boiler was carried out at the beginning heating season, a month after its chemical cleaning. As a result of the inspection, it was revealed: on the surface of the drums there are continuous solid deposits of a dark brown color, possessing paramagnetic properties and presumably consisting of iron oxides. The thickness of the deposits was up to 0.4 mm visually. In the visible part of the boiling pipes, mainly on the side facing the furnace, not continuous solid deposits were found (up to five spots per 100 mm of pipe length with a size of 2 to 15 mm and a visual thickness of up to 0.5 mm).
The device for creating a current-carrying potential, described in RU 2100492 C1, was connected at point (1) to the hatch (2) of the upper drum on the back side of the boiler (see Fig. 1). The current-carrying electric potential was equal to 100 V. The current-carrying electric potential was maintained continuously for 1.5 months. At the end of this period, the boiler unit was opened. As a result of an internal inspection of the boiler unit, an almost complete absence of deposits (no more than 0.1 mm visually) was established on the surface (3) of the upper and lower drums within 2-2.5 meters (zone (4)) from the drum hatches (device connection points to create a current-carrying potential (1)). At a distance of 2.5-3.0 m (zone (5)) from the hatches, sediments (6) were preserved in the form of individual tubercles (spots) up to 0.3 mm thick (see Figure 1). Further, as you move towards the front, (at a distance of 3.0-3.5 m from the hatches) continuous deposits (7) begin, up to 0.4 mm visually, i.e. At this distance from the connection point of the device, the effect of the cleaning method according to the present invention was practically not evident. The current-carrying electric potential was equal to 100 V. The current-carrying electric potential was maintained continuously for 1.5 months. At the end of this period, the boiler unit was opened. As a result of an internal inspection of the boiler unit, an almost complete absence of deposits (no more than 0.1 mm visually) was established on the surface of the upper and lower drums within 2-2.5 meters from the drum hatches (attachment points of the device for creating current-carrying potential). At a distance of 2.5-3.0 m from the hatches, the deposits were preserved in the form of individual tubercles (spots) up to 0.3 mm thick (see Fig. 1). Further, as you move towards the front (at a distance of 3.0-3.5 m from the hatches), continuous deposits of up to 0.4 mm visually begin, i.e. At this distance from the connection point of the device, the effect of the cleaning method according to the present invention was practically not evident.
In the visible part of the boiling pipes, within 3.5-4.0 m from the drum hatches, an almost complete absence of deposits was observed. Further, as we move towards the front, non-continuous solid deposits are found (up to five spots per 100 l.mm with a size from 2 to 15 mm and a visual thickness of up to 0.5 mm).
As a result of this stage of testing, it was concluded that the method according to the present invention, without the use of any reagents, can effectively destroy previously formed deposits and ensure scale-free operation of the boiler unit.
At the next stage of testing, the device for creating a current-carrying potential was connected at point “B” and the tests continued for another 30-45 days.
The next opening of the boiler unit was carried out after 3.5 months of continuous operation of the device.
An inspection of the boiler unit showed that the previously remaining deposits were completely destroyed and only a small amount remained in the lower sections of the boiler pipes.
This allowed us to draw the following conclusions:
The size of the zone within which scale-free operation of the boiler unit is ensured significantly exceeds the size of the zone of effective destruction of deposits, which allows subsequent transfer of the point of connection of the current-carrying potential to clean the entire internal surface of the boiler unit and further maintain its scale-free operation mode;
The destruction of previously formed deposits and the prevention of the formation of new ones is ensured by processes of different nature.
Based on the results of the inspection, it was decided to continue testing until the end of the heating period in order to finally clean the drums and boiling pipes and determine the reliability of ensuring scale-free operation of the boiler. The next opening of the boiler unit was carried out after 210 days.
The results of the internal inspection of the boiler showed that the process of cleaning the internal surfaces of the boiler within the upper and lower drums and boiling pipes resulted in almost complete removal of deposits. A thin, dense coating formed on the entire surface of the metal, black in color with a blue tarnish, the thickness of which, even in a moistened state (almost immediately after opening the boiler), did not visually exceed 0.1 mm.
At the same time, the reliability of ensuring scale-free operation of the boiler unit when using the method of the present invention was confirmed.
The protective effect of the magnetite film lasted up to 2 months after disconnecting the device, which is quite enough to ensure the preservation of the boiler unit using the dry method when transferring it to reserve or for repairs.
Although the present invention has been described with respect to various specific examples and embodiments, it is to be understood that the invention is not limited thereto and that it may be practiced within the scope of the following claims.
1. A method for preventing the formation of scale on a metal surface made of an iron-containing alloy and in contact with a steam-water environment from which scale can form, comprising applying a current-carrying electric potential to said metal surface in the range from 61 V to 150 V to neutralize the electrostatic component of the force adhesion between the specified metal surface and colloidal particles and ions that form scale.
The invention relates to heat power engineering and can be used to protect against scale and corrosion heating pipes of steam and hot water boilers, heat exchangers, boiler units, evaporators, heating mains, heating systems of residential buildings and industrial facilities during operation. A method for preventing the formation of scale on a metal surface made of an iron-containing alloy and in contact with a steam-water environment from which scale is capable of forming involves applying to said metal surface a current-carrying electric potential in the range from 61 V to 150 V to neutralize the electrostatic component of the adhesion force between the specified metal surface and colloidal particles and ions forming scale. The technical result is increasing the efficiency and productivity of hot water and steam boilers, increasing the efficiency of heat transfer, ensuring layer-by-layer destruction and removal of formed scale, as well as preventing its new formation. 2 salary f-ly, 1 ave., 1 ill.
