Suction cups in the vacuum system of turbines. Determining the places of air suction in the turbine vacuum system. Surface Capacitor Designs

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Ministry of Education and Science of the Russian Federation

Federal Agency for Education

GOUVPO "Udmurt State University"

Department of Thermal Power Engineering

Lab #1

AIR DENSITY DETERMINATION

STEAM TURBINE VACUUM SYSTEM

Fulfilled

student group 34-41

checked

Associate Professor of the Department of TES

Izhevsk, 2006

1. The purpose of the work

To acquaint students with the method for determining the air density of a vacuum system on an operating steam turbine of the T-I00-130TMZ type.

2. Introduction

Air suction through leaks in the vacuum system has an extremely negative effect on

the operation of the steam turbine plant, as this leads to a deterioration in the vacuum, an increase in the temperature of the spent turbine, a decrease in the generated power of the turbine and, ultimately, to a decrease in the thermal efficiency of the turbine plant.

When the pressure in the vapor space of the condenser changes by 1 kPa, the efficiency of the turbine plant changes by about 1%, and for NPP turbines operating on saturated steam,- up to 1.5. Increasing the efficiency of the turbine with the deepening of the vacuum occurs due to an increase in the magnitude of the generated heat drop. Air suction into the vacuum system cannot be completely eliminated, therefore“ Rules for the technical operation of power plants and networks” (PTE) establish the norms of air suction depending on the electric power of the turbine plant (see Table 1).

Table #1

3. Scheme of the experiment and conduct of the experiment

Figure 1 shows the scheme of the experiment for the ongoing laboratory work.

Rice. 1. Scheme of the experiment.

The scheme of the steam pipe installation includes:

1.Main live steam lineÆ 24545mm, made of steel I2X1M1F and designed for P 0 = 13.8 MPa,t 0 =570 0 C, steam pass 500 t/h.

2. Turbine unit type T-100-130TMZ with a capacity ofNemail=100MW.

3. Electric current generator type ТГВ-100 with powerNemail=100MW.

4. Turbine condenser type KG-6200-2 R k = 3.5 kPa,Wcoolant\u003d 1600m 3 / h,tcoolant=10 0 C.

5. Condensate pump type KsV500-220. InningsV\u003d 500m 3 / h, head H \u003d 220m.w.st.

6. Circulation pump type 0p2-87V= m 3 / h, N \u003d m.

7. Cooling tower for cooling circulating water type BG-1200-70. Irrigation area 1200m 2 , tower height 48.4m; upper diameter 26.0 m, lower 40.0 m.

8. Pressure circular conduitÆ 1200mm.

9. Drain circular conduitÆ 1200mm.

10. Steam jet ejector type EP-3-700-1 with an air capacity of 70 kg/h.

11. Air suction pipeline from the condenserÆ 2502mm, st.Z.

12. Technical glass mercury thermometer with a scale from 0 to 100 0 C for measuring the temperature of the vapor-air mixture.

13. Steam pipeline for supplying steam to the main ejectorÆ 502mm st.10,t= 0 C.

14. Air meter type VDM-63-1.

15. Funnel drainage drain of the main ejector.

16. Measuring block with a diaphragm BK 591079 of the MPa pressure difference transducer.

17. Exhaust pipe of the steam jet ejector.

The vacuum plant (system) of a steam turbine includes:

1. Condenser and its piping.

2. Condensate pumps and their suction lines.

3. Low pressure cylinder (LPC) of the turbine and its end seals.

4. Pipelines for suction of the steam-air mixture to the main ejectors.

5. All heaters (HDPE) operating under steam pressure below atmospheric pressure.

In practice, the term is widely used“ vacuum” or“ vacuum” , i.e. difference between atmospheric pressure and absolute pressure in the condenser:

here and are expressed in millimeters of mercury. The absolute pressure in the condenser (kPa) is defined as:

,(kPa)

here the readings of the barometer and vacuum gauge and, respectively, are expressed in millimeters of mercury and are given to 0 0 C. The following unit is also used to measure vacuum:

In this formula- the vacuum value according to the standard mercury vacuum gauge of the turbine, and- atmospheric pressure (barometric) in mm Hg. Art.

There are two methods for determining the air density of a steam turbine vacuum system:

1. According to the rate of fall (reduction) of vacuum in the turbine condenser after turning off the main ejector, which is measured with a stopwatch. Further, according to a special graph of the dependence of the rate of vacuum drop on the size of suction cups, the amount of suction air [kg/h] is determined.

2. By direct measurement of the amount of air (steam-air mixture) sucked out by the ejector of the turbine condenser.

The first method, due to the threat of vacuum loss and emergency shutdown of the turbine, as well as due to insufficient measurement accuracy, is practically not used.

When carrying out tests, the necessary measurements of the calculated values ​​are carried out using standard instruments or portable instruments with an accuracy class of at least 1.0.

When processing measurement data, it is necessary to use a special table of temperature corrections for the readings of an air meter of the VDM-63-1 type.

3.1. The order of the experiment.

Using standard turbine instruments, measure and record the following values ​​in the observation protocol:

1. Electric load of the turbine unitNemail[MW] by megawatt meter;

2. Steam flow to the turbineD 0 by flow meter [t/h];

3. Vacuum in the turbine condenser according to the vacuum gauge [%];

4. Barometric pressure [mm. Hg];

5. Readings of air meter VDM-63-1 [kg/h] on the main ejectorAand B. The rate of air suction for the turbine according to PTE should not exceed 10 kg/h. AtG>10 kg/h, measures must be taken to seal the vacuum system.

Observation protocol

Power turbines Nemail[MW]

Consumption pair D 0 [t/h]

Vacuum in the turbine condenser

preventive measures to prevent contamination of the condenser (treatment of cooling water by chemical and physical methods, the use of ball cleaning plants, etc.);
periodic cleaning of condensers with an increase in exhaust steam pressure compared to normative values by 0.005 kgf/cm2 (0.5 kPa) due to contamination of cooling surfaces;
control over the cleanliness of the cooling surface and tube plates of the condenser;
cooling water flow control (by direct flow measurement or by condenser heat balance), optimization of cooling water flow in accordance with its temperature and condenser steam load;
checking the density of the vacuum system and sealing it; air suction (kg / h) in the range of condenser steam load change of 40-100% should not exceed the values ​​determined by the formula
Sv \u003d 8 + 0.065 N,
where N is the rated electric power of the turbine plant in the condensing mode, MW;

• checking the water density of the condenser by

systematic control of salinity of condensate;

• checking the oxygen content in the condensate

after condensate pumps.
Methods for monitoring the operation of the condensing unit, its frequency are determined by local instructions, depending on the specific operating conditions.
Fulfillment of these requirements ensures the reliability and efficiency of the turbine plant.
Contamination of the surface of the condenser tubes with salt or biological deposits (usually from the side of the cooling water) increases the temperature difference in the condenser and, accordingly, the pressure from
working steam. Deterioration of vacuum in comparison with holes. a negative value corresponding to the clean surface of the tubes leads to a significant reduction in the efficiency of the turbine plant, and sometimes to a limitation of the turbine power. For example, for turbines with live steam parameters of 240 kgf/cm2, 540°C, a vacuum deterioration of 1% leads to an increase specific consumption heat by about 0.9-1.5% at the rated load of the turbine unit. In this regard, during the operation of the turbine, careful monitoring of the cleanliness of the surface of the condensers should be carried out and timely measures should be taken to clean it.
Contamination of the condenser tube sheets increases its hydraulic resistance, which reduces the cooling water flow and worsens the vacuum. Therefore, the hydraulic resistance should be controlled by the pressure drop at the inlet to and outlet of the condenser at a certain flow rate of cooling water. If the standard resistance is exceeded, cleaning should be carried out.
It should be borne in mind that periodic cleaning of the condenser tubes does not completely solve the problem of maintaining the highest possible efficiency. The gradual increase in tube deposits that form between two cleanings will cause the turbine to operate at a somewhat lower vacuum than a clean condenser. In addition, high-quality tube cleaning requires a turbine shutdown or reduction in load and significant labor costs. Therefore, it is very important to carry out preventive measures to prevent contamination of the condenser tubes and the resulting deterioration of the vacuum.
These activities are determined depending on the nature and composition of the deposits.
With organic contamination of the pipes, microorganisms and algae contained in the circulating water taken from natural or artificial reservoirs settle on the surface of the pipe system from the water side. Under the influence of favorable temperature conditions in the condenser, microorganisms fixed on the surface of the tubes begin to grow gradually, forming over time a significant layer of slimy deposits that impairs heat transfer from steam to water (increase in temperature difference). In addition, the cross section of the tubes decreases, which leads to an increase in the hydraulic resistance of the condenser and a decrease in the flow of water through it.
An effective means of combating organic deposits is the treatment of circulating water with chlorine or copper sulphate. In this case, the surface of the tubes is activated by chlorine or vitriol and becomes toxic to microorganisms. Before proceeding to the systematic treatment of circulating water with reagents, it is necessary to perform a thorough mechanical or hydromechanical cleaning of the tubes, since in this case the effectiveness of preventive measures will be higher.
Dense inorganic deposits (scale) appear in the condenser with an increased content of Ca(HCO3)2 and Mg(HCO3)2 hardness salts in the circulating water. Similar conditions are often created in circulating water supply systems, where, due to the evaporation of water and feeding the system with water containing salts, the salinity of the circulating water increases and when limit value carbonate hardness, the decomposition of bicarbonates begins with the deposition of salts on the surface of the condenser tubes.
Preventive measures against the formation of inorganic deposits are the organization of a rational regime for purging and replenishing water recycling systems, as well as chemical water treatment - phosphating or acidification. The use of chemical methods to improve the quality of circulating water leads to the need to treat large amounts of water and requires significant costs, therefore, at present, the method of continuous mechanical cleaning of condenser tubes with rubber balls is becoming more common. The experience of operation of power plants with introduced installations for ball cleaning of condenser tubes has shown high efficiency this method for the prevention of pollution, both inorganic and organic.
The vacuum deterioration limit set by the PTE by 0.5% compared to the standard one, after reaching which the condenser should be cleaned, is conditional to a certain extent, however, it should be followed in order to prevent an excessive decrease in the efficiency of the turbine plant and to establish the frequency of condenser cleaning at the power plant.
The cooling water flow rate is controlled by direct measurement using segment diaphragms used for large diameter water conduits, or is determined from the heat balance of the condenser for water heating and exhaust steam flow rate. Measuring the flow of cooling water also allows you to control the condition of the circulation pumps according to their characteristics.
Air suction through leaks in the condenser and the vacuum system of the turbine plant affects the process of heat transfer from the steam side of the condenser tubes, increasing the temperature difference, as well as the oxygen content in the exhaust steam condensate.
Creating the absolute density of the condenser and the vacuum system of the turbine plant is impossible. Air suction occurs through various leaks in the joints of mating parts, the LPC flange connector, flanged connections of pipelines under vacuum, in fittings, through the end seals of the turbine in case of their unsatisfactory operation. In this case, the amount of suction air depends on the load of the turbine. With a reduction in the passage of steam into the condenser by half compared to the nominal mode, air suction can increase by 30–40% due to an increase in the number of turbine units operating under vacuum (regenerative heaters, etc.).
In the case of using steam jet ejectors, they can switch to overload mode when the amount of sucked air exceeds the working capacity of the ejector. This worsens the vacuum in the condenser and increases the oxygen content in the condensate. When using water jet ejectors, the pressure increase in the condenser is less than when using steam jet ejectors, since with large suction cups they do not break off, but continue to work steadily in accordance with their characteristics in dry air.
The maximum allowable air suction values ​​prescribed by the PTE are based on the values ​​practically achieved in operation. The density of the vacuum system is estimated by directly measuring the amount of air sucked off by the steam jet ejector using a throttle flow meter. For installations with water jet ejectors, in which direct measurement of the exhaust air flow is not possible, the ejector characteristic is used - the dependence of the pressure on the suction side of the ejector on the air flow. If large air suctions are detected, all leaks should be identified and eliminated as soon as possible. Identification of suction spots is carried out on a running machine using halogen leak detectors, on a stopped one - by flooding the vacuum system with water and visual inspection. A highly effective way to find leaks in a vacuum system is steam pressure testing.
One of important tasks maintenance of the required quality of the condensate is to ensure the reliability of operation. The source of condensate contamination can be leaks in the condenser pipe system, through which cooling water, the pressure of which is much higher than the pressure in the condenser vapor space, enters the condensate. The amount of sucked circulating water may be insignificant, but even a small amount of it is enough to bring the turbine condensate in terms of hardness beyond the limits allowed by the PTE. So, for the K-300-240 turbine, the suction of circulating water having a hardness of, for example, 300 mg/l (clean river, lake water), in the amount of 8-10 l/h is already unacceptable. Control of suction cups of circulating water is carried out by chemical analysis hardness condensate.
Leaks in the pipe system can occur in the places of expansion of tubes in tube sheets due to expansion defects, cracks and ulceration of the material may appear in the tubes themselves as a result of the aggressive action of water.
To ensure the density of rolling joints, sealing coatings (bituminous coating, gumming) are applied to the tube sheets of condensers. Reducing the likelihood of metal damage along the length of the tubes is ensured by the choice of tube material in accordance with the quality of the cooling water.
If there are corrosive gases in the condensate, in particular oxygen, pipelines and equipment located in the area from the condenser to the deaerator are subject to corrosion. Corrosion products carried to the deaerator, and from there to the boiler, being deposited on the heating surfaces, create the prerequisites for severe accidents due to pipe burnout,
As a rule, condensers have a satisfactory deaerating capacity and provide the oxygen content in the condensate after the condenser within the limits prescribed by the PTE. However, if the path under vacuum to the condensate pumps is not tight, air suction and oxygen absorption by the condensate deaerated in the condenser are possible. Air suction in condensate pipelines, i.e. directly into the water are the most dangerous, since even a small amount of sucked air is enough to infect the entire condensate stream.
Constant monitoring of the oxygen content in the condensate provides the possibility of taking timely measures to prevent corrosion of the metal along the condensate path. The control of the oxygen content in the condensate is carried out by chemical analysis of the sample taken. The condensate sample is taken after the condensate pumps, so that the entire suction path under vacuum from the condenser to the pump is under control.
Air suction in the suction path of the condensate pump can occur in welded joints with their poor quality performance, through leaks flange connections pipelines, valve stem seals. Leaks must be eliminated by re-welding the joints, installing gaskets in flange joints, organizing hydraulic seals for valve stems, using vacuum fittings, etc.

Steam turbine design

Structurally, a modern steam turbine (Fig. 3.4) consists of one or more cylinders in which the process of converting steam energy takes place, and a number of devices that ensure the organization of its working process.

Cylinder. The main node of the steam turbine, in which the internal energy of the steam is converted into the kinetic energy of the steam flow and then into the mechanical energy of the rotor, is the cylinder. It consists of a fixed body (a turbine stator in two parts, divided by a horizontal split; guide (nozzle) vanes, labyrinth seals, inlet and exhaust pipes, bearing supports, etc.) and a rotor rotating in this body (shaft, disks, rotor blades and etc.). The main task of the nozzle blades is to convert the potential energy of the steam expanding in the nozzle arrays with a decrease in pressure and a simultaneous decrease in temperature into the kinetic energy of an organized steam flow and direct it to the rotor blades. The main purpose of the rotor blades and the turbine rotor is to convert the kinetic energy of the steam flow into the mechanical energy of the rotating rotor, which in turn is converted into electrical energy in the generator. The rotor of a powerful steam turbine is shown in Figure 3.5.

The number of crowns of nozzle blades in each cylinder of a steam turbine is equal to the number of crowns of the working blades of the corresponding rotor. In modern powerful steam turbines there are cylinders of low, medium, high and ultra-high pressure (Fig. 3.6.). Usually, an ultra-high pressure cylinder is a cylinder, the steam pressure at the inlet to which exceeds 30.0 MPa, a high-pressure cylinder is a turbine section, the steam pressure at the inlet to which varies between 23.5 - 9.0 MPa, a medium-pressure cylinder is a turbine section , the steam pressure at the inlet to which is about 3.0 MPa, the low-pressure cylinder is the section, the vapor pressure at the inlet to which does not exceed 0.2 MPa. In modern high-power turbine units, the number of low-pressure cylinders can reach 4 in order to ensure the length of the working blades of the last stages of the turbine that is acceptable in terms of strength.

Bodies of steam distribution. The amount of steam entering the turbine cylinder is limited by the opening of valves, which together with the control stage are called steam distribution units. In the practice of turbine construction, two types of steam distribution are distinguished - throttle and nozzle. Throttle steam distribution provides for steam supply after the valve is opened evenly around the entire circumference of the crown of the nozzle blades. This means that the function of changing the flow rate is performed by the annular gap between the valve, which moves, and its seat, which is fixed. The process of changing the flow rate in this design is associated with throttling. The less the valve is open, the greater the loss of steam pressure from throttling and the lower its flow rate per cylinder.

Nozzle steam distribution involves sectioning the guide vanes around the circumference into several segments (groups of nozzles), each of which has a separate steam supply, equipped with its own valve, which is either closed or fully open. When the valve is open, the pressure loss on it is minimal, and the steam flow rate is proportional to the fraction of the circle through which this steam enters the turbine. Thus, with nozzle steam distribution, there is no throttling process, and pressure losses are minimized.

In the case of high and ultra-high initial pressure in the steam inlet system, so-called unloaders are used, which are designed to reduce the initial pressure drop across the valve and reduce the force that must be applied to the valve when it is opened.

In some cases, throttling is also called qualitative regulation of the steam flow to the turbine, and nozzle steam distribution is called quantitative.

Regulatory system. This system makes it possible to synchronize the turbogenerator with the network, set the specified load when working in the general network, and ensure the transfer of the turbine to idling when the electrical load is removed. circuit diagram indirect control systems with a centrifugal speed controller is shown in Figure 3.7.

With an increase in the speed of the turbine rotor and the governor clutch, the centrifugal force of the loads increases, the speed controller clutch1 rises, compressing the governor spring and turning the lever AB around point B. The spool2 connected to the lever at point C moves from the middle position upwards and communicates the upper cavity of the hydraulic servomotor line4 through windowa, and the bottom line with drain line5 through windowb. Under the influence of the pressure difference, the servomotor piston moves down, closing the control valve6 and reducing the passage of steam into the turbine7, which will cause a decrease in the rotor speed. Simultaneously with the displacement of the servomotor rod, the lever AB rotates relative to point A, moving the spool down and stopping the flow of fluid to the servomotor. The spool returns to the middle position, which stabilizes the transient at a new (reduced) rotor speed. If the turbine load increases and the rotor speed drops, then the regulator elements are displaced in the opposite direction to the considered direction and the regulation process proceeds similarly, but with an increase in steam flow into the turbine. This leads to an increase in the speed of rotation of the rotor and the restoration of the frequency of the generated current.

The control systems of steam turbines used, for example, in nuclear power plants, as a rule, use turbine oil as a working fluid. A distinctive feature of the turbine control systems K-300240-2 and K-500-240-2 is the use of steam condensate instead of turbine oil in the control system. On all turbines of NPO "Turboatom", in addition to traditional hydraulic control systems, electro-hydraulic control systems (EGSR) with a higher speed are used.

Barring. In turbine units, a "low-speed" - several revolutions per minute - barring is traditionally used. The turning device is designed for slow rotation of the rotor when starting and stopping the turbine to prevent thermal distortion of the rotor. One of the designs of the turning device is shown in Fig. 3.8. It includes an electric motor with a worm engaged with a worm wheel1 located on the intermediate shaft. On the helical key of this shaft, a driving spur gear is installed, which, when the barring device is turned on, engages with the driven spur gear sitting on the turbine shaft. After steam is supplied to the turbine, the rotor speed increases and the drive gear automatically disengages.

Bearings and supports. Steam turbine units are located, as a rule, horizontally in the engine room of the power plant. This arrangement determines the use in the turbine, along with thrust bearings, as well as thrust or support-thrust bearings 3 (see Fig. 3.8). For support bearings, the most common in the energy sector is their paired number - there are two support bearings for each rotor. For heavy rotors (low-pressure rotors of high-speed turbines with a speed of 3000 rpm and all rotors of “low-speed” turbines with a speed of 1500 rpm without exception), sleeve bearings traditional for power turbine building can be used. In such a bearing, the lower half of the liner acts as a bearing surface, and the upper half acts as a damper for any disturbances that occur during operation. Such perturbations include the residual dynamic imbalance of the rotor, perturbations that occur during the passage of critical speeds, perturbations due to variable forces from the impact of the steam flow. The weight force of heavy rotors, directed downward, is able to suppress, as a rule, all these perturbations, which ensures a smooth running of the turbine. And for relatively light rotors (rotors of high and medium pressure), all of the listed perturbations can be significant compared to the weight of the rotor, especially in a high density steam flow. To suppress these perturbations, so-called segment bearings have been developed. In these bearings, each segment has an increased damping capacity compared to a sleeve bearing.

Naturally, the design of a segment support bearing, where each segment is supplied with oil individually, is much more complicated than a sleeve bearing. However, the sharply increased reliability pays for this complication.

As for the thrust bearing, its design was comprehensively considered by Stodola and has practically not undergone any changes over the past century. The supports, in which the thrust and thrust bearings are located, are made sliding with a “fixpoint” in the area of ​​the thrust bearing. This ensures the minimization of axial clearances in the region of maximum steam pressure, i.e. in the area of ​​the shortest blades, which in turn allows minimizing leakage losses in this zone.

A typical design of a 50 MW single-cylinder condensing turbine with initial steam parameters of 8.8 MPa, 535°C is shown in fig. 3.8. This turbine uses a combined rotor. The first 19 discs operating in the high temperature zone are forged as one piece with the turbine shaft, the last three discs are mounted.

A fixed nozzle array, fixed in nozzle boxes or diaphragms with a corresponding rotating working grate, fixed on the next disk in the course of the steam, is called turbine stage. The flow path of the single-cylinder turbine under consideration consists of 22 stages, of which the first is called regulating. In each nozzle array, the steam flow accelerates and acquires the direction of shockless entry into the channels of the working blades. The forces developed by the steam flow on the rotor blades rotate the disks and the shaft associated with them. As the steam pressure decreases during the passage from the first to the last stage, the specific volume of steam increases, which requires an increase in the flow sections of the nozzle and working grates and, accordingly, the height of the blades and the average diameter of the stages.

An attached shaft end is attached to the front end of the rotor, on which safety switch strikers (sensors of the automatic safety device) are installed, which act on the stop and control valves and stop steam from entering the turbine when the rotor speed is exceeded by 10–12% compared to the calculated one.

The turbine stator consists of a housing into which nozzle boxes are welded, connected by welding to valve boxes, end seal holders, diaphragm holders, diaphragms themselves and their seals are installed. The body of this turbine, in addition to the usual horizontal connector, has two vertical connectors dividing it into a front part, a middle part and an outlet pipe. The front part of the body is cast, the middle part of the body and the outlet pipe are welded.

The thrust bearing is located in the front crankcase, and the thrust bearings of the turbine and generator rotors are located in the rear crankcase. The front crankcase is mounted on a foundation plate and, with thermal expansion of the turbine casing, can move freely along this plate. The rear crankcase is made in one piece with the turbine exhaust pipe, which remains stationary during thermal expansion due to its fixation by the intersection of the transverse and longitudinal keys, forming the so-called turbine fix point, or dead point. A turning device is located in the rear crankcase of the turbine.

The K-50-90 turbine uses a nozzle steam distribution system, i.e. quantitative regulation of steam flow. The automatic turbine control device consists of four control valves, a camshaft connected by a gear rack to a servomotor. The servomotor receives an impulse from the speed controller and adjusts the position of the valves. The cam profiles are designed so that the control valves open one after the other in turn. Sequential opening or closing of valves eliminates the throttling of steam passing through fully open valves at reduced turbine loads.

Condenser and vacuum system.

The vast majority of turbines used in the global energy sector for the production of electrical energy are condensing. This means that the process of expansion of the working fluid (water vapor) continues up to pressures much lower than atmospheric pressure. As a result of such an expansion, additionally generated energy can be several tens of percent of the total generation.

The condenser is a heat exchanger designed to convert the steam exhausted in the turbine into a liquid state (condensate). Steam condensation occurs when it comes into contact with the surface of a body that has a lower temperature than the saturation temperature of the steam at a given pressure in the condenser. The condensation of steam is accompanied by the release of heat, which was previously expended on the evaporation of the liquid, which is removed with the help of a cooling medium. Depending on the type of cooling medium, condensers are divided into water and air. Modern steam turbine plants are usually equipped with water condensers. Air condensers have a more complex design compared to water condensers and are not currently widely used.

The condensing unit of a steam turbine consists of the condenser itself and additional devices that ensure its operation. Cooling water is supplied to the condenser by a circulation pump. Condensate pumps are used to pump condensate from the lower part of the condenser and supply it to the regenerative feed water heating system. Air suction devices are designed to remove air entering the turbine and condenser along with steam, as well as through leaks in flange connections, end seals and other places.

A diagram of the simplest water-type surface capacitor is shown in fig. 3.9.

It consists of a body, the end sides of which are closed with tube plates with condenser tubes, with their ends leading into the water chambers. The chambers are separated by a partition, which divides all the condenser tubes into two sections, forming the so-called "passages" of water (in this case, two passages). Water enters the water chamber through a pipe and passes through pipes located below the partition. AT rotary chamber water passes into the second section of tubes, located in height above the partition. Through the tubes of this section, water flows in the opposite direction, making the second “pass”, enters the chamber and is directed to the drain through the outlet pipe.

The steam coming from the turbine into the steam space condenses on the surface of the condenser tubes, inside which the cooling water flows. Due to a sharp decrease in the specific volume of steam, a low pressure (vacuum) is created in the condenser. The lower the temperature and the greater the flow rate of the cooling medium, the deeper the vacuum can be obtained in the condenser. The resulting condensate flows into the lower part of the condenser housing, and then into the condensate trap.

Removal of air (more precisely, a vapor-air mixture) from the condenser is carried out by an air-exhausting device through a pipe8. In order to reduce the volume of the sucked-off steam-air mixture, it is cooled in a condenser compartment specially allocated with the help of a partition - an air cooler.

To suck air from the air cooler, a three-stage steam jet ejector is installed - the main one. In addition to the main ejector, which is constantly in operation, the turbine unit is provided with a starting condenser ejector (water jet) and an ejector for the starting circulation system. The starting capacitor ejector is designed to quickly deepen the vacuum when starting the turbine. The ejector of the starting circulation system is used to suck the vapor-air mixture from the condenser circulation system. The condenser of the turbine plant is also equipped with two condensate collectors, from which the resulting condensate is continuously pumped out by condensate pumps.

On the transition pipe of the condenser there are receiving and discharge devices, the purpose of which is to ensure the discharge of steam from the boiler to the condenser bypassing the turbine in case of a sudden full load shedding or in starting modes. Discharged steam flow rates can reach 60% of the total steam flow to the turbine. The design of the intake and discharge device provides, in addition to pressure reduction, a decrease in the temperature of the steam discharged into the condenser with its corresponding regulation. It must be maintained 10–20°C above saturation temperature at a given condenser pressure.

Intermediate overheating and regeneration in turbine installations. In a thermal power plant with reheating, the steam after expansion in the high pressure cylinder (HPC) of the turbine is sent to the boiler for reheating, where its temperature rises to almost the same level as before the HPC. After intermediate superheating, the steam is sent to the low pressure cylinder, where it expands to the pressure in the condenser.

The efficiency of an ideal heat cycle with reheat depends on the parameters of the steam removed for reheat. The optimal temperature of steam T 1op t , at which it should be discharged for reheating, can be approximately estimated as 1.02–1.04 of the feed water temperature. The steam pressure before reheating is usually chosen to be 0.15-0.3 of the live steam pressure. As a result of reheating, the overall economy of the cycle will increase. At the same time, due to a decrease in steam moisture in the last stages of the low-pressure turbine, the relative internal efficiency will increase. these steps, and consequently, the efficiency will also increase. the entire turbine. The pressure loss Δ p pp in the reheat path (in the steam pipeline from the turbine to the boiler, the superheater and the steam pipeline from the boiler to the turbine) reduces the effect of steam reheating and therefore no more than 10% of the absolute pressure loss in the reheater is allowed.

The regeneration system in turbine installations involves heating the condensate formed in the condenser with steam, which is taken from the flow path of the turbine. To do this, the main flow of condensate is passed through the heaters, into the pipe system of which condensate enters, and steam from the turbine bleeds is supplied to the casing. To heat the main condensate, low-pressure heaters (LPH), high-pressure heaters (HPV) and a deaerator (D) are used between them. The deaerator is designed to remove the remaining air dissolved in the condensate from the main condensate.

The idea of ​​regeneration in the PTU arose in connection with the need to reduce heat losses in the condenser. It is known that heat losses with cooling water in the turbine condenser are directly proportional to the amount of exhaust steam entering the condenser. Steam consumption in the condenser can be significantly reduced (by 30-40%) by taking it for heating the feed water behind the turbine stages after it has done work in the previous stages. This process is called regenerative feed water heating. The regenerative cycle has a higher average heat input temperature at a constant output temperature compared to the conventional cycle and therefore has a higher thermal efficiency. The increase in efficiency in a cycle with regeneration is proportional to the power generated from the heat demand, i.e. based on the heat transferred to the feed water in the regeneration system. By means of regenerative heating, the temperature of the feed water could be raised to a temperature close to the saturation temperature corresponding to the live steam pressure. However, this would greatly increase the heat loss with the exhaust gases of the boiler. Therefore, international norms for standard sizes of steam turbines recommend choosing a feed water temperature at the boiler inlet equal to 0.65–0.75 of the saturation temperature corresponding to the pressure in the boiler. In accordance with this, at supercritical steam parameters, in particular, at initial pressure eр0=23.5 MPa, the feed water temperature is assumed to be 265–275°C.

Regeneration has a positive effect on relative internal efficiency. the first stages due to the increased steam flow through the HPC and the corresponding increase in the height of the blades. The volumetric passage of steam through the last stages of the turbine during regeneration is reduced, which reduces losses with the output speed in the last stages of the turbine.

In modern steam turbine plants of medium and high power, in order to increase their efficiency, a widely developed regeneration system is used using steam end labyrinth seals, turbine control valve stem seals, etc. (Fig. 3.10).

Fresh steam from the boiler enters the turbine through the main steam pipeline with the parameter mi 0 ,t 0 . After expansion in the flow path of the turbine to a pressure of k, it is sent to the condenser. To maintain a deep vacuum, a vapor-air mixture is sucked off from the vapor space of the condenser by the main ejector (EA). The exhaust steam condensate flows into the condensate collector, then it is supplied by condensate pumps (KN) through the ejector cooler (OE), the steam cooler of the seal suction ejector (OS), stuffing box heater (SP) and low-pressure regenerative heaters P1, P2 to the deaerator D. The deaerator is designed for removal of aggressive gases (О2 and СО2) dissolved in the condensate, which cause corrosion of metal surfaces. Oxygen and free carbon dioxide get into the condensate due to air suction through leaks in the vacuum system of the turbine plant and with additional water. In the deaerator, aggressive gases are removed by heating the condensate and make-up water with steam to the saturation temperature of the heating steam. In modern steam turbine plants, high-pressure deaerators of 0.6–0.7 MPa with a saturation temperature of 158–165°C are installed. Steam condensate in the section from the condenser to the deaerator is called condensate, and in the section from the deaerator to the boiler - feed water.

Feed water from the deaerator is taken by the feed pump (PN) and under high pressure (on units with supercritical and super-supercritical steam parameters up to 35 MPa) is fed through high-pressure heaters ПЗ, П4 to the boiler.

The steam of the end labyrinth seals of the turbine is sucked out from the extreme seal chambers, where the pressure is maintained at 95-97 kPa, by a special ejector and sent to the cooler of the suction ejector, through which the main condensate is pumped. Part of the pressurized steam from the end labyrinth seals is sent to the first and third regenerative extractions. In order to prevent air suction into the vacuum system through the turbine end seals, a slight overpressure (110–120 kPa) is maintained in each penultimate chamber of the end seals using a special regulator installed on the supply of sealing steam to this chamber from the deaerator.

Feeding plant. The feed plant of the turbine unit consists of a main feed pump with a turbine drive, a start-up feed pump

electrically driven pump and electrically driven booster pumps. The feed plant is designed to supply feed water from the deaerator through the high pressure heaters to the boiler. The pump starts when the unit is loaded at 50–60% and is designed to operate in the range of 30–100%. The PEN start-up feed pump is driven by an asynchronous electric motor.

The determining factor for the reliable and efficient operation of steam turbines in power plants is the optimal operation of condensing units. The main purpose of the condensing unit of a steam turbine unit is the condensation of the exhaust steam of the turbine, which contains an admixture of non-condensable gases, mainly air, penetrating through leaks in the vacuum system of the turbine unit. To maintain a vacuum in the condenser vapor space, non-condensable gases must be constantly removed. For this purpose, regular ejector-type vacuum systems have been used at Russian power plants for more than 50 years.
In today's market realities, the process of reducing the costs of electricity and heat production is a key factor for survival in the face of fierce market competition for generating companies. The main disadvantage of the operation of steam ejectors for pumping out the steam-air mixture is the burning of fuel to generate steam. The disadvantages of operating water-jet ejectors are the high consumption of technical water, the consumption of electricity spent on the operation of lifting pumps, and the loss of chemically desalted water.
The vacuum systems offered by our company for pumping out the steam-air mixture from the condenser of steam turbines of power plants consist of two-stage liquid ring vacuum pumps with a system for condensing steam by injecting water before it enters the pump, a heat exchanger with a closed cooling loop for the liquid ring of the system and a separator for separating air and water. The principle of operation of a liquid-ring vacuum system is based on the pumping of non-condensable gases (air) with a residual vapor content, which compresses the vapor-air mixture and releases it into the atmosphere. These vacuum systems have been operating reliably for many decades and are the industry standard in the energy industry in European countries and the USA, and in last years is being actively implemented in Asian countries, such as India, China, Korea and Japan, etc.
Payback calculations show that the maximum payback rates for equipment are at power plants using a direct-flow water intake system from reservoirs.
The scheme of power plants with a once-through cycle of technical water supply is shown in scheme No. 1.

In connection with the existing problem of water use, the main electricity generating companies in Russia are looking for ways to reduce the consumption of water taken from water bodies. This is due to the adoption on December 26, 2014 of Decree of the Government of the Russian Federation N 1509 “On the rates of payment for the use of water bodies owned by the federal government, and amendments to section I of the rates of payment for the use of water bodies owned by the federal government”. As a result, the annual coefficient for the use of water bodies of the Russian Federation is rapidly growing by 15% per year. This resolution leads to a significant reduction in the competitive level of thermal power plants (TPPs) with direct-flow systems, where the average share of costs for water supply of TPPs with direct-flow systems technical water supply of the total cost of energy production in 2013 amounted to 3.4%, and by 2017 it will grow to 8.2%, and at some thermal power plants - up to 12%.

One of the solutions to reduce water use fees is to replace water jet ejectors with vacuum systems based on liquid ring pumps. On average, with such replacements, the payback period will be from 3 to 6 years, and will allow:
- reduce the power consumption of the vacuum unit by ~ 7 times;
- to reduce the consumption of process water for the vacuum plant by ~ 50 times or more;
- eliminate the loss of chemically desalinated water.

Ultimately operating costs liquid ring vacuum systems are 60-80% lower compared to ejector systems.
The scheme of power plants with vacuum liquid ring plants is shown in scheme No. 2.

We carry out the optimal selection of equipment, ensuring a balance between the performance of the vacuum system and the efficiency of the turbine. Thanks to a wide range of vacuum pumps, each vacuum system is designed individually, in accordance with all customer requirements, balancing the performance of the vacuum system and the efficiency of the turbine, and also taking into account the following factors:

• Practical operating conditions for power plants with normal and emergency suction;
• In line with foreign and domestic energy industry standards;
• Practical Summer and Winter conditions;
• The main advantages of the vacuum system:
• two-stage liquid ring vacuum pump optimized specifically for power generation applications;
• Optimum pumping speed for any turbine power up to 1500 MW and above;
• Designed for permanent job under vacuum close to saturated vapor pressure;
• Reliable and stable operation in different modes, not sensitive to sudden changes in load;
• Minimum required power consumption
• No loss of condensate/chem. demineralized water.
• tests according to HEI standards;

To calculate and provide the TCH to your address, please send technical task or fill out our Questionnaire.

Air suction into the vacuum system is the main cause of vacuum deterioration and has a decisive influence on the reduction in the available power and efficiency of the turbine plant: each percentage of vacuum reduction reduces the efficiency and generated power by ~ 0.85% of the nominal value. Every 20 kg/h of air reduces the vacuum by 0.1%, which reduces power and efficiency by ~0.08% (see Fig. 1).

According to the operating experience, the following places of air suction in turbine plants are the most probable and significant:

• labyrinths of end seals, especially low pressure cylinders (up to 60% of suction cups);
• flanged connections of housings under vacuum, especially in the presence of heat cycles and temperature differences of the connected elements;
• welded seams of housings and pipelines under vacuum, especially near flat walls and lens compensators.

When the turbine is not working, the following methods for detecting suction spots are used:

• hydraulic crimping (in this case, water is poured up to the bores of the LPC seals);
• air pressing with different ways visualization of leaks;
• steam pressure testing of vacuum cavities with saturated steam;
• pneumohydraulic pressure testing, know-how (at the same time, the entire low-pressure cylinder is filled with water up to the receiver, and to increase the internal pressure, compressed air is supplied to the upper part of the turbine).

On a working turbine, other methods are used to detect suction spots:

• searches with light fibers or a candle flame (contraindicated in hydrogen-cooled generators);
• blowing probable places of suction with fluorine-containing gases (halogens) with their indication at the outlet of the ejector.

The method using halogen (halogen) leak detectors has advantages, because allows you to quickly and accurately indicate the place of suction. In doubtful cases of close proximity of several places of suction, measures are taken to exclude one of them. So, for example, with a temporary increase in steam pressure in the end seal supply manifold until visible steaming, suction through the labyrinths is excluded and suction is possible only between the fireplace flanges.

The easiest way to use halogen leak detectors produced by the industry, in the presence of steam ejectors to suck air from the condenser. In this case, the sensor is placed on the air outlet from the ejector to the turbine hall.

For cases of using water jet ejectors, the use of halogen leak detectors encounters some difficulties, overcoming which, however, pays off, however, with the accuracy of the result.

"Rus-Turbo" offers power plants and energy systems to conclude an agreement for joint inspection of vacuum systems of power units with determination of air suction points before and after overhaul. For each of the detected sources of air suction, an appropriate method for its elimination is recommended. Technical documentation for measures to eliminate air suction is transferred under additional agreements.