This corrosion in size and intensity is often more significant and dangerous than the corrosion of boilers during their operation.
When leaving water in systems, depending on its temperature and air access, a wide variety of cases of parking corrosion can occur. First of all, it should be noted the extreme undesirability of the presence of water in the pipes of the units when they are in reserve.
If water remains in the system for one reason or another, then severe parking corrosion can occur in the steam and especially in the water space of the tank (mainly along the waterline) at a water temperature of 60-70 ° C. Therefore, in practice, parking corrosion of different intensity is quite often observed, despite the same shutdown modes of the system and the quality of the water contained in them; devices with significant thermal accumulation are subject to more severe corrosion than devices that have the dimensions of a furnace and a heating surface, since the boiler water in them cools faster; its temperature falls below 60-70°C.
At a water temperature above 85–90°C (for example, during short-term shutdowns of the apparatus), the overall corrosion decreases, and the corrosion of the metal of the vapor space, in which increased vapor condensation is observed in this case, can exceed the corrosion of the metal of the water space. Parking corrosion in the steam space is in all cases more uniform than in the water space of the boiler.
The development of parking corrosion is greatly facilitated by the sludge that accumulates on the surfaces of the boiler, which usually retains moisture. In this regard, significant corrosion holes are often found in aggregates and pipes along the lower generatrix and at their ends, i.e., in areas of the greatest accumulation of sludge.
Methods of conservation of equipment in reserve
The following methods can be used to preserve equipment:
a) drying - removal of water and moisture from aggregates;
b) filling them with solutions of caustic soda, phosphate, silicate, sodium nitrite, hydrazine;
c) filling the technological system with nitrogen.
The method of conservation should be chosen depending on the nature and duration of downtime, as well as on the type and design features equipment.
Equipment downtime can be divided into two groups by duration: short-term - no more than 3 days and long-term - more than 3 days.
There are two types of short-term downtime:
a) scheduled, associated with the withdrawal to the reserve on weekends due to a drop in load or withdrawal to the reserve at night;
b) forced - due to failure of pipes or damage to other equipment components, the elimination of which does not require a longer shutdown.
Depending on the purpose, long-term downtime can be divided into the following groups: a) putting equipment into reserve; b) current repairs; c) capital repairs.
In case of short-term downtime of the equipment, it is necessary to use conservation by filling with deaerated water with the maintenance of excess pressure or the gas (nitrogen) method. If an emergency shutdown is required, then the only acceptable method is conservation with nitrogen.
When the system is placed on standby or when it is idle for a long time without performing repair work conservation is advisable to carry out by filling with a solution of nitrite or sodium silicate. In these cases, nitrogen conservation can also be used, necessarily taking measures to create a tightness of the system in order to prevent excessive gas consumption and unproductive operation of the nitrogen plant, as well as to create safe conditions for equipment maintenance.
Preservation methods by creating excess pressure, filling with nitrogen can be used regardless of the design features of the heating surfaces of the equipment.
To prevent parking corrosion of metal during major and current repairs only conservation methods are applicable that make it possible to create a protective film on the metal surface that retains its properties for at least 1–2 months after draining the preservative solution, since emptying and depressurization of the system are inevitable. The duration of the protective film on the metal surface after treatment with sodium nitrite can reach 3 months.
Preservation methods using water and reagent solutions are practically unacceptable for protection against parking corrosion of intermediate superheaters of boilers due to the difficulties associated with their filling and subsequent cleaning.
Methods for the conservation of hot water and low-pressure steam boilers, as well as other equipment of closed technological circuits of heat and water supply, differ in many respects from the methods currently used to prevent parking corrosion at thermal power plants. The following describes the main methods for preventing corrosion in the idle mode of equipment of apparatuses of such circulation systems, taking into account the specifics of their operation.
Simplified preservation methods
These methods are useful for small boilers. They consist in the complete removal of water from the boilers and the placement of desiccants in them: calcined calcium chloride, quicklime, silica gel at the rate of 1-2 kg per 1 m 3 of volume.
This preservation method is suitable for room temperatures below and above zero. In rooms heated in winter, one of the contact methods of conservation can be implemented. It comes down to filling the entire internal volume of the unit with an alkaline solution (NaOH, Na 3 P0 4, etc.), which ensures the complete stability of the protective film on the metal surface even when the liquid is saturated with oxygen.
Usually used solutions containing from 1.5-2 to 10 kg/m 3 NaOH or 5-20 kg/m 3 Na 3 P0 4 depending on the content of neutral salts in the source water. Smaller values refer to condensate, larger ones to water containing up to 3000 mg/l of neutral salts.
Corrosion can also be prevented by the overpressure method, in which the steam pressure in the stopped unit is constantly maintained at a level above atmospheric pressure, and the water temperature remains above 100 ° C, which prevents the access of the main corrosive agent, oxygen.
An important condition for the effectiveness and economy of any method of protection is the maximum possible tightness of the steam-water fittings in order to avoid too rapid a decrease in pressure, loss of a protective solution (or gas) or moisture ingress. In addition, in many cases, preliminary cleaning of surfaces from various deposits (salts, sludge, scale) is useful.
When implementing various ways protection against parking corrosion, the following should be kept in mind.
1. For all types of conservation, preliminary removal (washing) of deposits of easily soluble salts (see above) is necessary in order to avoid increased parking corrosion in certain areas of the protected unit. It is mandatory to carry out this measure during contact conservation, otherwise intense local corrosion is possible.
2. For similar reasons, it is desirable to remove all types of insoluble deposits (sludge, scale, iron oxides) before long-term conservation.
3. If the fittings are unreliable, it is necessary to disconnect the standby equipment from the operating units using plugs.
Leakage of steam and water is less dangerous in contact preservation, but unacceptable in dry and gas methods protection.
The choice of desiccants is determined by the relative availability of the reagent and the desirability of obtaining the highest possible specific moisture content. The best desiccant is granular calcium chloride. Quicklime much worse than calcium chloride, not only due to lower moisture capacity, but also the rapid loss of its activity. Lime absorbs not only moisture from the air, but also carbon dioxide, as a result of which it is covered with a layer of calcium carbonate, which prevents further absorption of moisture.
MINISTRY OF ENERGY AND ELECTRIFICATION OF THE USSR
MAIN SCIENTIFIC AND TECHNICAL DEPARTMENT OF ENERGY AND ELECTRIFICATION
METHODOLOGICAL INSTRUCTIONS
BY WARNING
LOW TEMPERATURE
SURFACE CORROSION
HEATING AND GAS FLUES 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. NADYROV
APPROVED by Chief technical management for the operation of power systems 22.04.84
Deputy Head D.Ya. SHAMARAKOV
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METHODOLOGICAL INSTRUCTIONS FOR THE PREVENTION OF LOW-TEMPERATURE CORROSION OF HEATING SURFACES AND GAS DUTS OF BOILERS |
RD 34.26.105-84 |
Expiry date set
from 01.07.85
until 01.07.2005
These Guidelines apply to low-temperature heating surfaces of steam and hot water boilers (economizers, gas evaporators, air heaters of various types, etc.), as well as to the gas path behind air heaters (gas ducts, ash collectors, smoke exhausters, chimneys) and establish methods for protecting surfaces heating from low temperature corrosion.
The Guidelines are intended for thermal power plants operating on sour fuels and organizations designing boiler equipment.
1. Low-temperature corrosion is the corrosion of tail heating surfaces, gas ducts and chimneys of boilers under the action of sulfuric acid vapors condensing on them from flue gases.
2. Condensation of sulfuric acid vapors, the volume content of which in flue gases during the combustion of sulfurous fuels is only a few thousandths of a percent, occurs at temperatures that are significantly (by 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 flue gas dew point temperature at all boiler loads.
For heating surfaces cooled by a medium with a high heat transfer coefficient (economizers, gas evaporators, etc.), the temperatures of the medium at their inlet must exceed the dew point temperature by about 10 °C.
5. For the heating surfaces of hot water boilers when they are operated on sulphurous fuel oil, the conditions for the complete exclusion of low-temperature corrosion cannot be realized. To reduce it, it is necessary to ensure the temperature of the water at the inlet to the boiler, equal to 105 - 110 °C. When using hot water boilers as peak boilers, this mode can be provided with full use of network water heaters. When using hot water boilers in the main mode, an increase in the temperature of the water entering the boiler can be achieved by recirculating hot water.
In installations using the scheme for connecting hot water boilers to the heating network through water heat exchangers, the conditions for reducing low-temperature corrosion of heating surfaces are provided in full.
6. For air heaters of steam boilers, the complete exclusion of low-temperature corrosion is ensured at the design temperature of the wall of the coldest section, which exceeds the dew point temperature at all boiler loads by 5–10 °С ( minimum value refers to the minimum load).
7. The calculation of the wall temperature of tubular (TVP) and regenerative (RAH) air heaters is carried out according to the recommendations of the “Thermal calculation of boiler units. Normative method” (M.: Energy, 1973).
8. When used in tubular air heaters as the first (by air) pass of replaceable cold cubes or cubes made of pipes with an acid-resistant coating (enamelled, etc.), as well as those made of corrosion-resistant materials, the following are checked for conditions for the 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 of replaceable, as well as corrosion-resistant cubes, should exclude intensive contamination of pipes, for which their minimum wall temperature during the combustion of sulfurous fuel oils should be below the dew point of flue gases by no more than 30 - 40 ° C. When burning solid sulfur fuels, the minimum temperature of the pipe wall, according to the conditions for preventing its intensive pollution, should be taken at least 80 °C.
9. In RAH, under conditions of complete exclusion of low-temperature corrosion, their hot part is calculated. The cold part of the RAH is made corrosion-resistant (enamelled, ceramic, low-alloy steel, etc.) or replaceable from flat metal sheets with a thickness of 1.0 - 1.2 mm, made of low-carbon steel. The conditions for preventing intense contamination of the packing are observed when fulfilling the requirements of clause of this document.
10. As an enameled packing, metal sheets with a thickness of 0.6 mm are used. The service life of enamelled packing, manufactured in accordance with TU 34-38-10336-89, is 4 years.
Porcelain tubes, ceramic blocks, or porcelain plates with protrusions can be used as ceramic packing.
Given the reduction in fuel oil consumption by thermal power plants, it is advisable to use for the cold part of the RAH a packing made of low-alloy steel 10KhNDP or 10KhSND, 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 start-up period, it is necessary to carry out the measures set forth in the “Guidelines for the design and operation of power heaters with wire fins” (M.: SPO Soyuztekhenergo, 1981).
Kindling of the boiler on sulphurous fuel oil should be carried out with the air heating system turned on beforehand. The temperature of the air in front of the air heater in the initial period of kindling should, as a rule, be 90 °C.
11a. To protect the air heaters from low-temperature ("station") corrosion on a stopped boiler, the level of which is approximately twice as high as the corrosion rate during operation, thoroughly clean the air heaters from external deposits before stopping the boiler. At the same time, before shutting down the boiler, it is recommended to maintain the air temperature at the inlet to the air heater at the level of 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 (p. 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 sulphurous fuel oils, the flue gas temperature must exceed the dew point temperature at the rated load of the boiler by about 10 °C.
Depending on the sulfur content in the fuel oil, the calculated flue gas temperature at nominal boiler load should be taken as follows:
Flue gas temperature, ºС...... 140 150 160 165
When burning sulphurous fuel oil with extremely small excesses of air (α ≤ 1.02), the flue gas temperature can be taken lower, taking into account the results of dew point measurements. On average, the transition from small excesses of air to extremely small ones reduces the dew point temperature by 15 - 20 °C.
To ensure reliable operation chimney and prevention of moisture loss on its walls is affected not only by the temperature of the exhaust gases, but also by their consumption. The operation of the pipe with load conditions significantly lower than the design ones increases the likelihood of low-temperature corrosion.
When burning natural gas, the flue gas temperature is recommended to be at least 80 °C.
13. When the boiler load is reduced 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 heaters as the load decreases.
The minimum allowable temperatures for air preheating before the RAH are taken 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 insufficient RAH heating surface, air preheating temperatures must be taken at which the flue gas temperature does not exceed the values given in clauses of these Guidelines.
16. Due to the lack of reliable acid-resistant coatings to protect against low-temperature corrosion of metal gas ducts, their reliable operation can be ensured by thorough insulation, ensuring the temperature difference between the flue gases and the wall is not more than 5 °C.
Currently applied insulating materials and structures are not sufficiently reliable in long-term operation, therefore it is necessary to periodically, at least once a year, monitor their condition and, if necessary, perform repair and restoration work.
17. When using on a trial basis to protect gas ducts from low-temperature corrosion of various coatings, it should be taken into account that the latter must provide heat resistance and gas tightness at temperatures exceeding the flue gas temperature by at least 10 ° C, resistance to sulfuric acid concentrations of 50 - 80% in the temperature range of 60 - 150 °C, respectively, and the possibility of their repair and restoration.
18. For low-temperature surfaces, structural elements of the RAH and flues of boilers, it is advisable to use low-alloy steels 10KhNDP and 10KhSND, which are 2–2.5 times superior in corrosion resistance to carbon steel.
Absolute corrosion resistance is possessed only by very scarce and expensive high-alloy steels (for example, steel EI943, 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 vapor and water can be defined as the boiling point of a solution of sulfuric acid of such a concentration at which the same content of water vapor and sulfuric acid is present above the solution.
The measured dew point temperature may differ from the theoretical value depending on the measurement technique. In these recommendations for flue gas dew point temperature t p the surface temperature of a standard glass sensor with 7 mm long platinum electrodes soldered at a distance of 7 mm from one another, at which the resistance of the dew film between for electrodes in steady state is equal to 10 7 Ohm. The measuring circuit of the electrodes uses low voltage alternating current (6 - 12 V).
2. When burning sulfurous fuel oils with excess air of 3 - 5%, the dew point temperature of flue gases depends on the sulfur content in the fuel Sp(rice.).
When burning sulphurous fuel oils with extremely low air excesses (α ≤ 1.02), the flue gas dew point temperature should be taken from the results of special measurements. The conditions for transferring boilers to the mode with α ≤ 1.02 are set out in the “Guidelines for the transfer of boilers operating on sulfurous fuels to the combustion mode with extremely small excess air” (M.: SPO Soyuztekhenergo, 1980).
3. When burning sulphurous solid fuels in a pulverized state, the dew point temperature of flue gases tp can be calculated from the reduced content of sulfur and ash in the fuel S p pr, A r pr and water vapor condensation temperature t con according to the formula
where a un- the proportion of ash in the fly away (usually taken 0.85).
Rice. 1. Dependence of flue gas dew point temperature on sulfur content in combusted fuel oil
The value of the first term of this formula at a un= 0.85 can be determined from Fig. .
Rice. 2. Differences in temperatures of the dew point of flue gases and condensation of water vapor in them, depending on the reduced sulfur content ( S p pr) and ash ( A r pr) in fuel
4. When burning gaseous sulphurous fuels, the flue gas dew point can be determined from fig. provided that the sulfur content in the gas is calculated as reduced, i.e. as a percentage by mass per 4186.8 kJ/kg (1000 kcal/kg) of the calorific value of the gas.
For gas fuel the reduced 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 (sulphur-containing component);
Q n- heat of combustion of gas in kJ / m 3 (kcal / nm 3);
FROM- coefficient equal to 4.187 if Q n expressed in kJ/m 3 and 1.0 if in kcal/m 3 .
5. The corrosion rate of the replaceable metal packing of air heaters during fuel oil combustion depends on the temperature of the metal and the degree of corrosivity of flue gases.
When burning sulphurous 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 RAH packing can be tentatively estimated from the data in Table. .
Table 1
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Table 2
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. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The iron-water vapor system is thermodynamically unstable. The interaction of these substances can proceed with the formation of magnetite Fe 3 O 4 or wustite FeO:
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;An analysis of reactions (2.1) - (2.3) indicates a peculiar decomposition of water vapor when interacting with a metal with the formation of molecular hydrogen, which is not a consequence of the actual thermal dissociation of water vapor. From equations (2.1) - (2.3) it follows that during the corrosion of steels in superheated steam in the absence of oxygen, only Fe 3 O 4 or FeO can form on the surface.
In the presence of oxygen in the superheated steam (for example, in neutral water regimes, with dosing of oxygen into the condensate), hematite Fe 2 O 3 may form in the superheated zone due to the additional oxidation of magnetite.
It is believed that corrosion in steam, starting from a temperature of 570 ° C, is chemical. At present, the limiting superheat temperature for all boilers has been reduced to 545 °C, and, consequently, electrochemical corrosion occurs in superheaters. The outlet sections of the primary superheaters are made of corrosion-resistant austenitic stainless steel, the outlet sections of the intermediate superheaters, which have the same final superheat temperature (545 °C), are made of pearlitic steels. Therefore, corrosion of intermediate superheaters usually manifests itself to a large extent.
As a result of the action of steam on steel, on its initially clean surface, gradually a so-called topotactic layer is formed, tightly bonded to the metal itself and therefore protecting it from corrosion. Over time, a second so-called epitactic layer grows on this layer. Both of these layers for steam temperatures up to 545 °C are magnetite, but their structure is not the same - the epitactic layer is coarse-grained and does not protect against corrosion.
Steam decomposition rate
mgN 2 /(cm 2 h)
Rice. 2.1. The dependence of the decomposition rate of superheated steam
on wall temperature
It is not possible to influence the corrosion of overheating surfaces by water regime methods. Therefore, the main task of the water-chemical regime of the superheaters proper is to systematically monitor the state of the metal of the superheaters in order to prevent the destruction of the topotactic layer. This can occur due to the ingress of individual impurities into the superheaters and the deposition in them, especially salts, which is possible, for example, as a result of a sharp increase in the level in the boiler drum high pressure. The salt deposits associated with this in the superheater can lead both to an increase in the wall temperature and to the destruction of the protective oxide topotactic film, which can be judged by a sharp increase in the rate of steam decomposition (Fig. 2.1).
3.3. Corrosion of the feed water path and condensate lines
A significant part of the corrosion damage to the equipment of thermal power plants falls on the feed water path, where the metal is in the most difficult conditions, the cause of which is the corrosive aggressiveness of the chemically treated water, condensate, distillate and their mixture in contact with it. At steam turbine power plants, the main source of feedwater contamination with copper compounds is ammonia corrosion of turbine condensers and low-pressure regenerative heaters, the pipe system of which is made of brass.
The feed water path of a steam turbine power plant can be divided into two main sections: before and after the thermal deaerator, and the flow conditions in their corrosion rates are sharply different. The elements of the first section of the feed water path, located before the deaerator, include pipelines, tanks, condensate pumps, condensate pipelines and other equipment. A characteristic feature of the corrosion of this part of the nutrient tract is the lack of the possibility of depletion of aggressive agents, i.e., carbonic acid and oxygen contained in the water. Due to the continuous inflow and movement of new portions of water along the tract, there is a constant replenishment of their loss. The continuous removal of part of the reaction products of iron with water and the influx of fresh portions of aggressive agents create favorable conditions for the intensive course of corrosion processes.
The source of oxygen in the turbine condensate is air suction in the tail section of the turbines and in the glands of the condensate pumps. Heating water containing O 2 and CO 2 in surface heaters located in the first section of the feed duct, up to 60–80 °С and above leads to serious corrosion damage to brass pipes. The latter become brittle, and often brass after several months of work acquires a spongy structure as a result of pronounced selective corrosion.
The elements of the second section of the feed water path - from the deaerator to the steam generator - include feed pumps and lines, regenerative heaters and economizers. The temperature of the water in this area as a result of the sequential heating of water in regenerative heaters and water economizers approaches the temperature of the boiler water. The cause of corrosion of the equipment related to this part of the tract is mainly the effect on the metal of free carbon dioxide dissolved in the feed water, the source of which is additional chemically treated water. At an increased concentration of hydrogen ions (pH< 7,0), обусловленной наличием растворенной углекислоты и значительным подогревом воды, процесс коррозии на этом участке питательного тракта развивается преимущественно с выделением водорода. Коррозия имеет сравнительно равномерный характер.
In the presence of equipment made of brass (low pressure heaters, condensers), the enrichment of water with copper compounds through the steam condensate path proceeds in the presence of oxygen and free ammonia. The increase in the solubility of hydrated copper oxide occurs due to the formation of copper-ammonia complexes, such as Сu(NH 3) 4 (OH) 2 . These corrosion products of brass tubes of low-pressure heaters begin to decompose in sections of the path of high-pressure regenerative heaters (p.h.p.) with the formation of less soluble copper oxides, partially deposited on the surface of p.p. tubes. e. Cuprous deposits on pipes a.e. contribute to their corrosion during operation and long-term parking of equipment without conservation.
With insufficiently deep thermal deaeration of the feed water, pitting corrosion is observed mainly at the inlet sections of the economizers, where oxygen is released due to a noticeable increase in the temperature of the feed water, as well as in stagnant sections of the feed tract.
The heat-using equipment of steam consumers and pipelines, through which the production condensate is returned to the CHPP, are subject to corrosion under the action of oxygen and carbonic acid contained in it. The appearance of oxygen is explained by the contact of condensate with air in open tanks (with an open condensate collection scheme) and suction through leaks in the equipment.
The main measures to prevent corrosion of equipment located in the first section of the feed water path (from the water treatment plant to the thermal deaerator) are:
1) the use of protective anti-corrosion coatings on the surfaces of water treatment equipment and tank facilities, which are washed with solutions of acidic reagents or corrosive waters using rubber, epoxy resins, perchlorovinyl-based varnishes, liquid nayrite and silicone;
2) the use of acid-resistant pipes and fittings made of polymeric materials (polyethylene, polyisobutylene, polypropylene, etc.) or steel pipes and fittings lined inside with protective coatings applied by flame spraying;
3) the use of pipes of heat exchangers made of corrosion-resistant metals (red copper, stainless steel);
4) removal of free carbon dioxide from additional chemically treated water;
5) constant removal of non-condensable gases (oxygen and carbonic acid) from the steam chambers of low-pressure regenerative heaters, coolers and heaters of network water and rapid removal of the condensate formed in them;
6) careful sealing of glands of condensate pumps, fittings and flange connections of supply pipelines under vacuum;
7) ensuring sufficient tightness of turbine condensers from the side of cooling water and air and monitoring air suction with the help of recording oxygen meters;
8) equipping condensers with special degassing devices to remove oxygen from the condensate.
To successfully combat corrosion of equipment and pipelines located in the second section of the feedwater path (from thermal deaerators to steam generators), the following measures are taken:
1) equipping thermal power plants with thermal deaerators, which, under any operating conditions, produce deaerated water with a residual content of oxygen and carbon dioxide that does not exceed permissible standards;
2) maximum removal of non-condensable gases from the steam chambers of high-pressure regenerative heaters;
3) the use of corrosion-resistant metals for the manufacture of elements of feed pumps in contact with water;
4) anti-corrosion protection of nutrient and drainage tanks by applying non-metallic coatings that are resistant at temperatures up to 80–100 ° C, for example, asbovinyl (a mixture of lacquer ethinol with asbestos) or paints and varnishes based on epoxy resins;
5) selection of corrosion-resistant structural metals suitable for the manufacture of pipes for high-pressure regenerative heaters;
6) continuous treatment of feed water with alkaline reagents in order to maintain the specified optimal value pH of the feed water, which suppresses carbon dioxide corrosion and ensures sufficient strength of the protective film;
7) continuous treatment of feed water with hydrazine to bind residual oxygen after thermal deaerators and create an inhibitory effect of inhibition of the transfer of iron compounds from the equipment surface to feed water;
8) sealing the feed water tanks by organizing a so-called closed system to prevent oxygen from entering the economizers of the steam generators with the feed water;
9) implementation of reliable conservation of the equipment of the feedwater tract during its downtime in reserve.
An effective method for reducing the concentration of corrosion products in the condensate returned to the CHPP by steam consumers is the introduction of film-forming amines - octadecylamine or its substitutes into the selective steam of turbines sent to consumers. At a concentration of these substances in a vapor equal to 2–3 mg / dm 3 , it is possible to reduce the content of iron oxides in the production condensate by 10–15 times. The dosing of an aqueous emulsion of polyamines using a dosing pump does not depend on the concentration of carbonic acid in the condensate, since their action is not associated with neutralizing properties, but is based on the ability of these amines to form insoluble and water-resistant films on the surface of steel, brass and other metals.
A number of power plants use river and tap waters with a low pH value and low hardness to feed heating networks. Additional processing of river water at a waterworks usually leads to a decrease in pH, a decrease in alkalinity and an increase in the content of corrosive carbon dioxide. The appearance of aggressive carbon dioxide is also possible in acidification schemes used for large heat supply systems with direct hot water intake (2000–3000 t/h). Water softening 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 subject to internal corrosion.
It is known that an increase in temperature contributes to 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 under-sludge corrosion occurs under conditions of a low content of residual oxygen (when the PTE standards are met) and when the amount of iron oxides is more than 400 μg/dm 3 (in terms of Fe). This type of corrosion, previously known in the practice of operating steam boilers, was found under conditions of relatively weak heating and the absence of thermal loads. In this case, loose corrosion products, consisting mainly of hydrated trivalent iron oxides, are active depolarizers of the cathode process.
During the operation of heating equipment, crevice corrosion is often observed, i.e., selective, intense corrosion destruction of the metal in the crack (gap). A feature of the processes taking place in narrow gaps is the reduced oxygen concentration compared to the concentration in the volume of the solution and the 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.
With constant replenishment of a heat network with open water intake with deaerated water, the possibility of the formation of through holes in pipelines is completely excluded only in normal hydraulic mode, when at all points of the heat supply system it is constantly maintained overpressure above atmospheric.
Causes of pitting corrosion of pipes of hot water boilers and other equipment are as follows: poor-quality 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 products oxygen corrosion iron (Fe 2 O 3) on heat transfer surfaces. Increased content iron oxides in the network water contributes to the drift of the heating surfaces of the boiler with iron oxide deposits.
A number of researchers recognize an important role in the occurrence of under-sludge corrosion of the process of rusting of pipes of water-heating boilers during their downtime, when proper measures are not taken to prevent parking corrosion. The centers of corrosion that occur under the influence of atmospheric air on the wet surfaces of the boilers continue to function during the operation of the boilers.
Corrosion of steel in steam boilers, proceeding under the action of water vapor, is reduced mainly to the following reaction:
3Fe + 4H20 = Fe2O3 + 4H2
We can assume that the inner surface of the boiler is a thin film of magnetic iron oxide. During the operation of the boiler, the oxide film is continuously destroyed and re-formed, and hydrogen is released. Since the surface film of magnetic iron oxide is the main protection for steel, it should be maintained in a state of least water permeability.
For boilers, fittings, water and steam pipelines, mainly simple carbon or low alloy steels are used. The corrosive medium in all cases is water or water vapor of varying degrees of purity.
The temperature at which the corrosion process can proceed varies from the temperature of the room where the boiler is inactive to the boiling point of saturated solutions during boiler operation, sometimes reaching 700 °. The solution may have a temperature much higher than the critical temperature of pure water (374°). However, high salt concentrations in boilers are rare.
The mechanism by which physical and chemical causes can lead to film failure in steam boilers is essentially not different from that explored at more low temperatures on less critical equipment. The difference is that the corrosion rate in boilers is much higher due to the high temperature and pressure. The high rate of heat transfer from the boiler walls to the medium, reaching 15 cal/cm2sec, also enhances corrosion.
PITTING CORROSION
The shape of corrosion pits and their distribution on the metal surface can vary over a wide range. Corrosion pits sometimes form inside pre-existing pits and are often so close together that the surface becomes extremely uneven.Recognition of pitting
Elucidation of the cause of the formation of corrosion damage certain type often very difficult, since several causes can act simultaneously; in addition, a number of changes that occur when the boiler is cooled from high temperature and when the water is drained, sometimes masks the phenomena that occurred during operation. However, experience greatly helps to recognize pitting in boilers. For example, it has been observed that the presence of black magnetic iron oxide in a corrosive cavity or on the surface of a tubercle indicates that an active process was taking place in the boiler. Such observations are often used in the verification of measures taken to protect against corrosion.
Do not mix the iron oxide that forms in areas of active corrosion with black magnetic iron oxide, which is sometimes present as a suspension in boiler water. It must be remembered that neither the total amount of finely dispersed magnetic iron oxide, nor the amount of hydrogen released in the boiler can serve as a reliable indicator of the degree and extent of the ongoing corrosion. Ferrous oxide hydrate entering the boiler from outside sources, such as condensate tanks or pipelines feeding the boiler, may partly explain the presence of both iron oxide and hydrogen in the boiler. Ferrous oxide hydrate, supplied with feed water, interacts in the boiler according to the reaction.
ZFe (OH) 2 \u003d Fe3O4 + 2H2O + H2.
Causes affecting the development of pitting corrosion
Foreign impurities and stresses. Non-metallic inclusions in steel, as well as stresses, are capable of creating anodic areas on a metal surface. Typically, corrosive shells come in various sizes and are scattered over the surface in a disorderly manner. In the presence of stresses, the location of the shells obeys the direction of the applied stress. Typical examples are fin tubes where the fins are cracked, and where the fins are flared.
dissolved oxygen.
It is possible that the most powerful pitting corrosion activator is oxygen dissolved in water. At all temperatures, even in an alkaline solution, oxygen serves as an active depolarizer. In addition, oxygen concentration elements can easily form in boilers, especially under scale or contamination, where stagnant areas are created. The usual measure to combat this kind of corrosion is deaeration.
Dissolved carbonic anhydride.
Since solutions of carbonic anhydride have a slightly acidic reaction, it accelerates corrosion in boilers. Alkaline boiler water reduces the corrosiveness of dissolved carbonic anhydride, but the resulting benefit does not extend to steam-flushed surfaces or condensate piping. Removal of carbonic anhydride along with dissolved oxygen by mechanical deaeration is a common practice.
Recently, attempts have been made to use cyclohexylamine to eliminate corrosion in steam and condensate pipes in heating systems.
Deposits on the walls of the boiler.
Very often, corrosion pits can be found along outer surface(or below the surface) deposits such as mill scale, boiler sludge, boiler scale, corrosion products, oil films. Once started, pitting will continue to develop if corrosion products are not removed. This type of localized corrosion is exacerbated by the cathodic (relative to boiler steel) nature of precipitation or depletion of oxygen under the deposits.
Copper in boiler water.
Considering the large quantities of copper alloys used for auxiliary equipment (capacitors, pumps, etc.), it is not surprising that most boiler deposits contain copper. It is usually present in the metallic state, sometimes in the form of an oxide. The amount of copper in deposits varies from fractions of a percent to almost pure copper.
The question of the significance of copper deposits in boiler corrosion cannot be considered resolved. Some argue that copper is only present in corrosion process and does not affect it in any way, others, on the contrary, believe that copper, being a cathode in relation to steel, can contribute to pitting. None of these points of view is confirmed by direct experiments.
In many cases, little or no corrosion was observed, despite the fact that deposits throughout the boiler contained significant amounts of metallic copper. There is also evidence that when copper comes into contact with mild steel in alkaline boiler water, at elevated temperatures, copper is destroyed faster than steel. Copper rings pressing the ends of flared pipes, copper rivets and screens of auxiliary equipment through which boiler water passes are almost completely destroyed even at relatively low temperatures. In view of this, it is believed that metallic copper does not increase the corrosion of boiler steel. The deposited copper can be regarded simply as the end product of the reduction of copper oxide with hydrogen at the time of its formation.
On the contrary, very strong corrosion pitting of boiler metal is often observed in the vicinity of deposits that are especially rich in copper. These observations led to the suggestion that copper, because it is cathodic with respect to steel, promotes pitting.
The surface of the cauldrons rarely presents exposed metallic iron. Most often it has protective layer, consisting mainly of iron oxide. It is possible that where cracks form in this layer, a surface is exposed that is anodic with respect to copper. In such places, the formation of corrosion shells is enhanced. This may also explain the accelerated corrosion in some cases where the shell has formed, as well as the severe pitting sometimes observed after cleaning the boilers with acids.
Improper maintenance of inactive boilers.
One of the most common causes of corrosion pits is the lack of proper maintenance of idle boilers. The inactive boiler must be kept either completely dry or filled with water treated in such a way that corrosion is not possible.
The water remaining on the inner surface of the inactive boiler dissolves oxygen from the air, which leads to the formation of shells, which later become centers around which the corrosion process will develop.
The usual instructions for keeping inactive boilers from rusting are as follows:
1) draining water from the still hot boiler (about 90°); blowing the boiler with air until it is completely drained and kept in a dry state;
2) filling the boiler with alkaline water (pH = 11), containing an excess of SO3" ions (about 0.01%), and storing under a water or steam lock;
3) filling the boiler with an alkaline solution containing salts of chromic acid (0.02-0.03% CrO4").
During chemical cleaning of boilers, the protective layer of iron oxide will be removed in many places. Subsequently, these places may not be covered with a newly formed continuous layer, and shells will appear on them, even in the absence of copper. Therefore, it is recommended immediately after chemical cleaning renew the layer of iron oxide by treatment with a boiling alkaline solution (similar to how it is done for new boilers coming into operation).
Corrosion of economizers
General provisions concerning boiler corrosion apply equally to economizers. However, the economizer, which heats the feed water and is located in front of the boiler, is especially sensitive to the formation of corrosion pits. It represents the first high temperature surface to be exposed to the damaging effects of oxygen dissolved in the feed water. In addition, the water passing through the economizer generally has a low pH and does not contain chemical retarders.
The fight against corrosion of economizers consists in deaeration of water and the addition of alkali and chemical retarders.
Sometimes the treatment of boiler water is carried out by passing part of it through an economizer. In this case, deposits of sludge in the economizer should be avoided. The effect of such boiler water recirculation on steam quality must also be taken into account.
BOILER WATER TREATMENT
When treating boiler water for corrosion protection, the formation and maintenance of a protective film on the metal surfaces. The combination of substances added to the water depends on the operating conditions, especially on pressure, temperature, thermal stress of the quality of the feed water. However, in all cases, three rules must be observed: boiler water must be alkaline, must not contain dissolved oxygen and pollute the heating surface.Caustic soda provides protection best at pH = 11-12. In practice, with complex boiler water composition, the best results are obtained at pH = 11. For boilers operating at pressures below 17.5 kg/cm2, pH is usually maintained between 11.0 and 11.5. For higher pressures, due to the possibility of metal destruction due to improper circulation and local increase in the concentration of the alkali solution, pH is usually taken equal to 10.5 - 11.0.
To remove residual oxygen, chemical reducing agents are widely used: salts of sulfurous acid, ferrous oxide hydrate and organic reducing agents. Ferrous compounds are very good at removing oxygen but form sludge which has an undesirable effect on heat transfer. Organic reducing agents, due to their instability at high temperatures, are generally not recommended for boilers operating at pressures above 35 kg/cm2. There are data on the decomposition of sulphurous salts at elevated temperatures. However, their use in small concentrations in boilers operating under pressure up to 98 kg/cm2 is widely practiced. Many high pressure plants operate without any chemical deaeration at all.
The cost of special equipment for deaeration, despite its undoubted usefulness, is not always justified for small installations operating at relatively low pressures. At pressures below 14 kg/cm2, partial deaeration in the feed water heaters can bring the dissolved oxygen content to approximately 0.00007%. The addition of chemical reducing agents gives good results, especially when the pH of the water is above 11, and oxygen scavengers are added before the water enters the boiler, which ensures that oxygen is taken up outside the boiler.
CORROSION IN CONCENTRATED BOILER WATER
Low concentrations of caustic soda (of the order of 0.01%) contribute to the preservation of the oxide layer on the steel in a state that reliably provides protection against corrosion. A local increase in concentration causes severe corrosion.Areas of the boiler surface, where the concentration of alkali reaches a dangerous value, are usually characterized by excess, in relation to the circulating water, heat supply. Alkali-enriched zones near the metal surface can occur in different places in the boiler. Corrosion pits are arranged in strips or elongated sections, sometimes smooth, and sometimes filled with hard and dense magnetic oxide.
Tubes located horizontally or slightly inclined and exposed to intense radiation from above are corroded inside, along the upper generatrix. Similar cases were observed in large-capacity boilers, and were also reproduced in specially designed experiments.
Pipes in which the water circulation is uneven or broken when the boiler is heavily loaded may be subject to destruction along the lower generatrix. Sometimes corrosion is more pronounced along the variable water level on the side surfaces. Often one can observe abundant accumulations of magnetic iron oxide, sometimes loose, sometimes representing dense masses.
Overheating steel often increases the destruction. This can happen as a result of the formation of a layer of steam at the top of the inclined tube. The formation of a steam jacket is also possible in vertical tubes with an increased heat supply, as indicated by temperature measurements in various places of the tubes during the operation of the boiler. Characteristic data obtained during these measurements are shown in Figs. 7. Limited areas of overheating in vertical tubes with normal temperature above and below the "hot spot" are possibly the result of film boiling of water.
Every time a steam bubble forms on the surface of the boiler tube, the temperature of the metal underneath rises.
An increase in the concentration of alkali in water should occur at the interface: steam bubble - water - heating surface. On fig. it has been shown that even a slight increase in the temperature of the water film in contact with the metal and with the expanding vapor bubble leads to the concentration of caustic soda, already measured in percent and not in parts per million. The film of water enriched with alkali, formed as a result of the appearance of each vapor bubble, affects a small area of the metal and for a very short time. However, the total effect of steam on the heating surface can be likened to the continuous action of a concentrated alkali solution, despite the fact that the total mass of water contains only millionths of caustic soda. Several attempts have been made to find a solution to the problem associated with a local increase in the concentration of caustic soda on heating surfaces. So it was proposed to add neutral salts (for example, metal chlorides) to water in a higher concentration than caustic soda. However, it is best to completely exclude the addition of caustic soda and provide the required pH value by introducing hydrolyzable salts of phosphoric acid. The relationship between the pH of the solution and the concentration of sodium phosphorus salt is shown in fig. Although water containing sodium phosphorus has a high pH value, it can be evaporated without a significant increase in the concentration of hydroxyl ions.
However, it should be remembered that the exclusion of the action of caustic soda only means that one factor accelerating corrosion has been removed. If a steam jacket forms in the tubes, then even though the water does not contain alkali, corrosion is still possible, although to a lesser extent than in the presence of caustic soda. The solution to the problem should also be sought by changing the design, taking into account at the same time the tendency to a constant increase in the energy intensity of the heating surfaces, which, in turn, certainly increases corrosion. If the temperature of a thin layer of water, directly at the heating surface of the tube, exceeds the average temperature of the water in the coarse, even by a small amount, the concentration of caustic soda can increase relatively strongly in such a layer. The curve approximately shows the equilibrium conditions in a solution containing only caustic soda. The exact data depends, to some extent, on the pressure in the boiler.
ALKALINE FRITABILITY OF STEEL
Alkali brittleness can be defined as the appearance of cracks in the area of rivet seams or in other joints where a concentrated alkali solution can accumulate and where there are high mechanical stresses.The most serious damage almost always occurs in the area of rivet seams. Sometimes they cause the boiler to explode; more often it is necessary to make expensive repairs even of relatively new boilers. One American railroad recorded cracks in 40 locomotive boilers in a year, requiring about $60,000 worth of repairs. The appearance of brittleness was also found on tubes in the places of flaring, on connections, manifolds and in places of threaded connections.
Stress required for alkali embrittlement to occur
Practice shows a low probability of brittle fracture of conventional boiler steel if the stresses do not exceed the yield strength. Stresses generated by steam pressure or evenly distributed load from the own weight of the structure, cannot lead to the formation of cracks. However, stresses generated by rolling the sheet material intended for the manufacture of boilers, deformation during riveting, or any cold working involving permanent deformation, can cause cracking.
The presence of externally applied stresses is not necessary for the formation of cracks. A sample of boiler steel, previously held at a constant bending stress and then released, can crack in an alkaline solution, the concentration of which is equal to the increased concentration of alkali in the boiler water.
Alkali concentration
The normal concentration of alkali in the boiler drum cannot cause cracking, because it does not exceed 0.1% NaOH, and the lowest concentration at which alkali embrittlement is observed is approximately 100 times higher than normal.
Such high concentrations can result from the extremely slow infiltration of water through the rivet seam or some other gap. This explains the appearance of hard salts on the outside of most rivet joints in steam boilers. The most dangerous leak is one that is difficult to detect. It leaves a solid deposit inside the rivet joint where there are high residual stresses. The combined action of stress and concentrated solution can cause alkali brittle cracks to appear.
Alkaline embrittlement device
A special device for controlling the composition of water reproduces the process of evaporation of water with an increase in the concentration of alkali on a stressed steel sample under the same conditions in which this occurs in the area of the rivet seam. Cracking of the test sample indicates that boiler water of this composition is capable of causing alkaline embrittlement. Therefore, in this case, water treatment is necessary to eliminate its dangerous properties. However, the cracking of the control sample does not mean that cracks have already appeared or will appear in the boiler. In rivet seams or in other joints, there is not necessarily both a leak (steaming), a stress, and an increase in the concentration of alkali, as in the control sample.
The control device is installed directly on the steam boiler and makes it possible to judge the quality of the boiler water.
The test lasts 30 or more days with constant circulation of water through the control device.
Recognition of alkali embrittlement cracks
Alkali brittle cracks in conventional boiler steel are of a different nature than fatigue cracks or cracks formed due to high stresses. This is illustrated in Fig. I9, which shows the intergranular nature of such cracks forming a fine network. The difference between intergranular alkali brittle cracks and intragranular cracks caused by corrosion fatigue can be seen by comparison.
In alloy steels (for example, nickel or silicon-manganese) used for locomotive boilers, cracks are also arranged in a grid, but do not always pass between the crystallites, as in the case of ordinary boiler steel.
Theory of alkali embrittlement
The atoms in the crystal lattice of the metal, located at the boundaries of the crystallites, experience a less symmetrical effect of their neighbors than the atoms in the rest of the grain mass. Therefore, they leave the crystal lattice more easily. One might think that with a careful selection of an aggressive medium, such a selective removal of atoms from the boundaries of crystallites will be possible. Indeed, experiments show that in acidic, neutral (with the help of a weak electric current that creates conditions favorable for corrosion) and concentrated alkali solutions, intergranular cracking can be obtained. If the general corrosion solution is changed by the addition of some substance that forms a protective film on the surface of the crystallites, the corrosion is concentrated at the boundaries between the crystallites.
Aggressive solution in this case is a solution of caustic soda. Silicon sodium salt can protect the surfaces of crystallites without affecting the boundaries between them. The result of a joint protective and aggressive action depends on many circumstances: concentration, temperature, stress state of the metal and composition of the solution.
There is also a colloidal theory of alkali embrittlement and a theory of the effect of hydrogen dissolving in steel.
Ways to combat alkali embrittlement
One of the ways to combat alkaline brittleness is to replace the riveting of the boilers with welding, which eliminates the possibility of leakage. Brittleness can also be eliminated by using steel resistant to intergranular corrosion or by chemically treating the boiler water. In the riveted boilers currently used, the latter method is the only acceptable one.
Preliminary tests using a control sample represent the best way determining the effectiveness of certain protective additives to water. Sodium sulfide salt does not prevent cracking. Nitrogen-sodium salt is successfully used to prevent cracking at pressures up to 52.5 kg/cm2. Concentrated sodium nitrogen salt solutions boiling at atmospheric pressure can cause stress corrosion cracks in mild steel.
At present, sodium nitrogen salt is widely used in stationary boilers. The concentration of sodium nitrogen salt corresponds to 20-30% of the alkali concentration.
CORROSION OF STEAM SUPERHEATERS
Corrosion on the inner surfaces of superheater tubes is primarily due to the interaction between metal and steam at high temperature and, to a lesser extent, to entrainment of boiler water salts by steam. In the latter case, films of solutions with a high concentration of caustic soda can form on the metal walls, directly corroding the steel or giving deposits that sinter on the tube wall, which can lead to the formation of bulges. In idle boilers and in cases of steam condensation in relatively cold superheaters, pitting can develop under the influence of oxygen and carbonic anhydride.Hydrogen as a measure of corrosion rate
The steam temperature in modern boilers approaches the temperatures used in the industrial production of hydrogen by a direct reaction between steam and iron.
The rate of corrosion of pipes made of carbon and alloy steels under the action of steam, at temperatures up to 650 °, can be judged by the volume of hydrogen released. Hydrogen evolution is sometimes used as a measure of general corrosion.
AT recent times Three types of miniature gas and air removal units are used in US power plants. They provide complete removal of gases, and the degassed condensate is suitable for the determination of salts carried away by steam from the boiler. An approximate value of the general corrosion of the superheater during the operation of the boiler can be obtained by determining the difference in hydrogen concentrations in steam samples taken before and after its passage through the superheater.
Corrosion caused by impurities in steam
The saturated steam entering the superheater carries with it small but measurable quantities of gases and salts from the boiler water. The most common gases are oxygen, ammonia and carbon dioxide. When steam passes through the superheater, no noticeable change in the concentration of these gases is observed. Only minor corrosion of the metal superheater can be attributed to these gases. So far, it has not been proven that salts dissolved in water, in dry form or deposited on superheater elements, can contribute to corrosion. However, caustic soda, being the main integral part salts entrained in boiler water can contribute to the corrosion of a very hot tube, especially if the alkali sticks to the metal wall.
Increasing the purity of saturated steam is achieved by preliminary careful removal of gases from the feed water. Reduction of the amount of salt entrained in the steam is achieved by thorough cleaning in the upper header, by the use of mechanical separators, by flushing the saturated steam with feed water, or by suitable chemical treatment of the water.
Determination of the concentration and nature of gases entrained in saturated steam is carried out using the above devices and chemical analysis. It is convenient to determine the concentration of salts in saturated steam by measuring the electrical conductivity of water or by evaporating a large amount of condensate.
An improved method for measuring electrical conductivity is proposed, and appropriate corrections for some dissolved gases are given. The condensate in the miniature degassers mentioned above can also be used to measure electrical conductivity.
When the boiler is idle, the superheater is a refrigerator in which condensate accumulates; in this case, normal underwater pitting is possible if the steam contained oxygen or carbon dioxide.
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