Turbine monitoring system and turbine monitoring method

Abstract

To provide a turbine monitoring system and a turbine monitoring method capable of appropriately evaluating erosion amount of a moving blade of a steam turbine.SOLUTION: A turbine monitoring system in one embodiment includes a temperature measuring instrument that detects a temperature of steam to be introduced to a steam turbine and outputs a detection result of the temperature. The system further includes an electric output measuring instrument that detects electric output of a power generator driven by the steam turbine and outputs a detection result of the electric output. The system further includes a calculation section that calculates an amount of erosion due to water droplets of a moving blade of the steam turbine on the basis of the temperature detection result output from the temperature measuring instrument and the electric output detection result output from the electric output measuring instrument. The system further includes an output section that outputs information based on the erosion amount calculated by the calculation section.SELECTED DRAWING: Figure 1

Description

Technical Field

[0001] Embodiments of the present invention relate to a turbine monitoring system and a turbine monitoring method.

Background Art

[0002] In the low-pressure stage of a steam turbine used in a power plant, as the steam, which is the working fluid, expands, the temperature and pressure of the steam decrease. Therefore, a part of the steam condenses in the steam flow path and becomes moisture.

[0003] FIG. 5 is a cross-sectional view for explaining the problems of a conventional steam turbine. This steam turbine is, for example, a low-pressure turbine. FIGS. 5(a) and 5(b) show different cross-sections of the low-pressure turbine.

[0004] FIGS. 5(a) and 5(b) show the final stage of the low-pressure turbine, which is composed of a pair of a stationary blade 1 and a moving blade 2 arranged downstream of the stationary blade 1, and the stationary blade 3 and the moving blade 4 of the stage preceding the final stage having the same configuration. FIGS. 5(a) and 5(b) schematically show the trajectories of steam and droplets (water droplets) in the region including these stationary blades 1, 3 and moving blades 2, 4.

[0005] In FIG. 5(a), the steam, which is the working fluid, follows a trajectory as shown by streamline L1, while the moisture generated by the time it reaches the stage preceding the final stage takes the form of water droplets and scatters from the trailing edge end 5 of the moving blade 4 to the diaphragm outer ring 6 side of the stationary blade 1 like streamline L2 by centrifugal force.

[0006] When these water droplets adhere to the stationary blade 1, they flow on the surface toward the trailing edge while forming a water film DL on the surface of the stationary blade 1, and scatter again as water droplets when they reach the trailing edge end 7 of the turbine nozzle. After that, the water droplets collide around the leading edge end 8 of the moving blade 2.

[0007] Figure 5(b) shows the absolute velocity V1 of the water droplet, the relative velocity V2 of the water droplet, and the peripheral velocity U of the steam. As shown in Figure 5(b), the absolute velocity V1 of the water droplet scattered from the trailing edge 7 of the stator blade 1 is slower than the peripheral velocity U of the steam, and it is not sufficiently accelerated to reach the rotor blade 2. Therefore, the water droplet collides with the dorsal side of the leading edge 8 of the rotor blade 2 at a relative velocity V2 that is close to the peripheral velocity U. This collision between the water droplet and the rotor blade 2 causes erosion of the leading edge 8 of the rotor blade 2.

[0008] Figure 6 is a graph illustrating the problems of conventional steam turbines. Figure 6 shows the relationship between a typical erosion rate (dE / dt) and elapsed time (t).

[0009] The period during which the erosion rate changes can be broadly classified into four phases: the latency period, the acceleration period, the deceleration period, and the stabilization period. During the latency period, no significant weight loss occurs in the material (e.g., rotor blade 2), but fatigue damage accumulates near the impact surface due to the impact of many water droplets, leading to the formation of fatigue cracks. During the acceleration period, the fatigue accumulated inside the material during the latency period manifests as fracture phenomena, and the erosion rate increases rapidly. During the deceleration period, the erosion rate decreases rapidly, and during the stabilization period, the erosion rate reaches a certain value.

[0010] The erosion rate E during the stable period is a characteristic that changes linearly with respect to time t, and can be expressed, for example, by the following equation (1). E = a + bt ... (1)

[0011] Here, a is a material property. By differentiating equation (1) with respect to time, the erosion rate dE / dt, which is the amount of erosion E per unit time, is expressed by the following equation (2). dE / dt=b ···(2)

[0012] Here, b is typically a function of the water droplet collision velocity, droplet diameter, water volume (number of droplets), and material properties, and can be expressed, for example, by the following equation (3). b = C1 × V p1 ×d q1 ×N ···(3)

[0013] Here, C1, p1, and q1 are material constants, V represents the collision velocity, d represents the droplet diameter, and N represents the number of droplets.

[0014] Since erosion in the final paragraph negatively impacts the reliability of the steam turbine, it is desirable to predict the amount of erosion in advance. Therefore, during the design phase of a steam turbine, it is common practice to predict the amount of erosion based on the theory described above, while considering the operating conditions of the steam turbine. [Prior art documents] [Patent Documents]

[0015] [Patent Document 1] Japanese Patent Application Publication No. 61-207804 [Patent Document 2] Japanese Patent Publication No. 2021-92175 [Patent Document 3] Japanese Patent Publication No. 2016-70272 [Non-patent literature]

[0016] [Non-Patent Document 1] Transactions of the Japan Society of Mechanical Engineers (Series A), Vol. 59, No. 567 (1993-11), pp. 264-269, Evaluation of droplet erosion in "metallic" materials. [Overview of the project] [Problems that the invention aims to solve]

[0017] With the recent expansion of renewable energy use, steam turbines are increasingly being used as regulatory thermal power plants, requiring diversified operation (partial load operation and start-up / shutdown). This diversification of operation means that the state variables at the inlet of the final stage blades of the steam turbine will fluctuate under various conditions. Therefore, the aforementioned impact velocity and number of water droplets are expected to change moment by moment depending on the plant's operation. Consequently, predicting the amount of erosion during the steam turbine design phase is considered difficult.

[0018] For example, it is conceivable to emit light into a steam turbine containing water droplets, receive the scattered light from the water droplets, and calculate the erosion amount caused by the water droplets based on the received light result of the scattered light. However, exposing a delicate optical device to high-temperature steam may cause the optical device to deteriorate over time.

[0019] In addition, it is conceivable to detect the physical quantities (such as temperature, pressure, flow rate, etc.) of the steam flowing upstream or downstream of the steam turbine or the water obtained from this steam, and calculate the erosion amount caused by the water droplets based on the detection result of the physical quantity. However, when steam is extracted from this steam turbine or another steam turbine, there is a possibility that an accurate erosion amount cannot be calculated.

[0020] Therefore, an embodiment of the present invention aims to provide a turbine monitoring system and a turbine monitoring method capable of appropriately evaluating the erosion amount of the moving blades of a steam turbine.

Means for Solving the Problems

[0021] According to one embodiment, a turbine monitoring system includes a thermometer that detects the temperature of the steam introduced into the steam turbine and outputs the detection result of the temperature. The system further includes an electrical output measuring device that detects the electrical output of a generator driven by the steam turbine and outputs the detection result of the electrical output. The system further includes a calculation unit that calculates the erosion amount caused by water droplets on the moving blades of the steam turbine based on the detection result of the temperature output from the thermometer and the detection result of the electrical output output from the electrical output measuring device. The system further includes an output unit that outputs information based on the erosion amount calculated by the calculation unit.

Brief Description of the Drawings

[0022] [Figure 1] It is a schematic diagram showing the configuration of a steam turbine plant according to the first embodiment. [Figure 2] It is a flowchart for explaining the operation of the turbine monitoring system according to the first embodiment. [Figure 3]This is a schematic diagram showing the configuration of a steam turbine plant according to the second embodiment. [Figure 4] This is a flowchart illustrating the operation of the turbine monitoring system according to the second embodiment. [Figure 5] This is a cross-sectional view illustrating the problems of conventional steam turbines. [Figure 6] This graph illustrates the problems with conventional steam turbines. [Modes for carrying out the invention]

[0023] Embodiments of the present invention will now be described with reference to the drawings. In Figures 1 to 4 and the aforementioned Figures 5 and 6, the same components are denoted by the same reference numerals, and redundant explanations are omitted.

[0024] (First Embodiment) Figure 1 is a schematic diagram showing the configuration of a steam turbine plant according to the first embodiment.

[0025] The steam turbine plant in Figure 1 is a reheat plant and comprises a boiler 11, a high-pressure (HP) turbine 12, a reheater 13, an intermediate-pressure (IP) turbine 14, a low-pressure (LP) turbine 15, a generator 16, a condenser 17, a Boiler Feed Pump (BFP) 18, a Boiler Feed Pump Turbine (BFPT) 19, a BFPT inlet valve 20, steam passages P1-P5, extraction passages P6-P7, and a feedwater passage P8. The low-pressure turbine 15 is an example of a “steam turbine” in this disclosure, the high-pressure turbine 12 and the intermediate-pressure turbine 14 are examples of “another steam turbine” in this disclosure, and the BFPT 19 is an example of a “turbine” in this disclosure.

[0026] The steam turbine plant in Figure 1 further includes a turbine monitoring system for monitoring the operation of the steam turbine, comprising a turbine monitoring device 21, an inlet temperature measuring instrument 22, and an electrical output measuring instrument 23. The turbine monitoring device 21 comprises a storage unit 21a, a calculation unit 21b, and an output unit 21c. The inlet temperature measuring instrument 24, shown by a dotted line in Figure 1, will be described later.

[0027] The boiler 11 heats water to generate steam and discharges the steam into the steam channel P1. The high-pressure turbine 12 is driven by the steam introduced from the steam channel P1 and discharges this steam into the steam channel P2. The reheater 13 heats (reheats) the steam introduced from the steam channel P2 and discharges this steam into the steam channel P3. The intermediate-pressure turbine 14 is driven by the steam introduced from the steam channel P3 and discharges this steam into the steam channel P4. The low-pressure turbine 15 is driven by the steam introduced from the steam channel P4 and discharges this steam into the steam channel P5. The generator 16 generates electricity by being driven by the high-pressure turbine 12, the intermediate-pressure turbine 14, and the low-pressure turbine 15.

[0028] The condenser 17 cools the steam introduced from the steam channel P5 and returns it to water, then discharges this water (condensate) into the feedwater channel P8. The BFP 18 (boiler supply pump) is located in the feedwater channel P8. The BFP 18 pressurizes the water in the feedwater channel P8 and transfers the pressurized water to the boiler 11. The boiler 11 heats the water (feedwater) introduced from the feedwater channel P8 to generate steam, and discharges this steam into the steam channel P1 as described above. In this way, steam and water circulate within the steam turbine plant.

[0029] The BFP18 can be driven by an electric motor (not shown) and also by the BFPT19. Therefore, the BFP18 can be connected to both an electric motor and the BFPT19. When the electrical output of the generator 16 is less than a specified value, the BFP18 is driven by the electric motor. When the electrical output of the generator 16 is greater than a specified value, the BFP18 is driven by the BFPT19. When the BFP18 is driven by the BFPT19, the amount of energy consumed in the steam turbine plant can be reduced and the efficiency of the steam turbine plant can be increased compared to when the BFP18 is driven by an electric motor.

[0030] The BFPT 19 is located between the extraction flow path P6 and the extraction flow path P7. The BFPT inlet valve 20 is located in the extraction flow path P6. When the electrical output of the generator 16 exceeds a specified value, the BFPT inlet valve 20 opens, and steam extracted from the intermediate pressure turbine 14 flows into the extraction flow path P6. The BFPT 19 is driven by the steam introduced from the extraction flow path P6 and discharges this steam into the extraction flow path P7. The condenser 17 cools the steam introduced from the extraction flow path P7 back into water and discharges this water (condensate) into the feedwater flow path P8. The extraction flow path P7 merges with the steam flow path P5 within the condenser 17. Therefore, the amount of water discharged from the condenser 17 is the sum of the amount of water obtained from the steam discharged from the steam flow path P5 to the condenser 17 and the amount of water obtained from the steam discharged from the extraction flow path P7 to the condenser 17.

[0031] The turbine monitoring device 21 is a device for monitoring the operation of the steam turbine. Examples of the turbine monitoring device 21 include a computer such as a PC (Personal Computer) and a control device such as a control panel. For example, the turbine monitoring device 21 controls whether the BFP 18 is driven by an electric motor or by the BFPT 19 by comparing the electrical output of the generator 16 with a specified value. Details of the turbine monitoring device 21 will be described later.

[0032] The inlet temperature measuring instrument 22 detects the temperature of the steam introduced into the intermediate-pressure turbine 14 and outputs the temperature detection result to the turbine monitoring device 21. Specifically, the inlet temperature measuring instrument 22 is installed in the inlet piping (steam flow path P3) located upstream of the first stage stator blades of the intermediate-pressure turbine 14, and detects the temperature of the steam at the inlet of the intermediate-pressure turbine 14. After being discharged from the intermediate-pressure turbine 14, this steam is also introduced into the low-pressure turbine 15. The inlet temperature measuring instrument 22 is equipped with, for example, a thermocouple, and outputs the thermoelectric current from the hot junction of the thermocouple installed in the flow field where the temperature is measured to the storage unit 21a via wiring (for example, a compensating conductor). Note that the inlet of the intermediate-pressure turbine 14 refers to the inlet of the first stage turbine stage.

[0033] The electrical output meter 23 detects the electrical output of the generator 16 and outputs the detected electrical output to the turbine monitoring device 21. As will be described later, the turbine monitoring device 21 calculates the amount of erosion caused by water droplets on the rotor blades of the low-pressure turbine 15 based on the temperature detection result and the electrical output detection result. The turbine monitoring device 21 also controls whether to drive the BFP 18 with an electric motor or with the BFPT 19 based on the electrical output detection result. In the latter case, the electrical output detection result is used to compare the electrical output with a specified value.

[0034] The memory unit 21a stores the detection result of the inlet steam temperature output from the inlet temperature measuring instrument 22 and the detection result of the electrical output output from the electrical output measuring instrument 23. In this embodiment, when the low-pressure turbine 15 is in operation, the memory unit 21a receives the output signal (thermoelectric current) from the inlet temperature measuring instrument 22 and the output signal from the electrical output measuring instrument 23 via the input / output unit of the turbine monitoring device 21, averages these output signals over a certain operating time, and outputs them to the calculation unit 21b.

[0035] The calculation unit 21b calculates the amount of erosion caused by water droplets on the rotor blades of the low-pressure turbine 15 based on the detection result of the inlet steam temperature output from the inlet temperature measuring instrument 22 and the detection result of the electrical output output from the electrical output measuring instrument 23. In this embodiment, the calculation unit 21b calculates the amount of erosion caused by water droplets on the rotor blades 2 (see Figure 5) of the final stage of the low-pressure turbine 15 based on the signal output from the storage unit 21a. The calculation unit 21b is implemented, for example, by a processor and a computer program, and the computer program executed by the processor calculates the amount of erosion based on the signal from the storage unit 21b and various data.

[0036] The output unit 21c outputs information based on the amount of erosion calculated by the calculation unit 21b. The output unit 21c displays this information on a display such as an LCD (Liquid Crystal Display) or an indicator such as a lamp. The output unit 21c may display the information on the display or indicator of the turbine monitoring device 21, or on the display or indicator of another device connected to the turbine monitoring device 21 by wire or wireless.

[0037] In this embodiment, the output unit 21c displays the amount of erosion or an alarm based on the amount of erosion as the information. When displaying the amount of erosion, the output unit 21c may display the amount of erosion calculated by the calculation unit 21b as a numerical value, or it may display the amount of erosion calculated by the calculation unit 21b as a graph or table. In this case, the output unit 21c may display this amount of erosion together with a reference value of the amount of erosion that has been stored in advance in the turbine monitoring device 21 or another device. This can, for example, prompt the administrator of the turbine monitoring system to repair or replace the rotor blades. In addition, if the amount of erosion exceeds the reference value, the output unit 21c may display an alarm on the display or indicator to prompt the administrator of the turbine monitoring system to repair or replace the rotor blades. Examples of alarms include a message displayed on the display or the illumination of a red lamp on the indicator.

[0038] The output unit 21c may output the information in various forms other than display. For example, the information may be stored in storage, delivered as email, or transmitted over a network.

[0039] The turbine monitoring system of this embodiment monitors the low-pressure turbine 15 as the steam turbine. This is because, in the low-pressure turbine 15, the steam conditions in the downstream turbine stages generally become wet steam, which poses a problem for erosion. However, the turbine monitoring system of this embodiment may also monitor steam turbines other than the low-pressure turbine 15.

[0040] The low-pressure turbine 15 receives steam from the steam passage P4. The steam that has done expansion work in the turbine stages of the low-pressure turbine 15 passes through an exhaust chamber located downstream of the rotor blades 2 of the final stage of the low-pressure turbine 15 and is discharged into the steam passage P5. The steam discharged into the steam passage P5 is introduced into the condenser 17 and returned to water. The low-pressure turbine 15 is connected to the generator 16 by a rotating shaft along with the high-pressure turbine 12 and the intermediate-pressure turbine 14, and the expansion work of the steam in these turbines is taken out as electrical output from the generator 16.

[0041] Figure 2 is a flowchart illustrating the operation of the turbine monitoring system according to the first embodiment. Figure 2 shows the calculation flow by the calculation unit 21b.

[0042] First, based on the generator electrical output and turbine inlet temperature (S1) input from the memory unit 21a, the flow rate, moisture content, pressure, and velocity (S2) of the steam at the final stage blade inlet of the low-pressure turbine 15 are calculated. In this embodiment, a fluid analysis or one-dimensional steam calculation program may be stored in the calculation unit 21b, and the flow rate, moisture content, pressure, and velocity at the final stage blade inlet may be calculated using the electrical output and inlet temperature as input. In this embodiment, in order to reduce the calculation capacity and load of the calculation unit 21b, a comprehensive fluid analysis or one-dimensional steam calculation under conditions expected in actual operation may be performed in advance, and the relationship between the above input and output may be stored as an approximate function.

[0043] Next, the amount of water (number of droplets), droplet diameter, and droplet impact velocity (S3) in the steam at the final stage rotor blade inlet are calculated from the flow rate, moisture content, pressure, and flow velocity. The amount of water is calculated based on the flow rate and moisture content mentioned above. The droplet diameter D is calculated using the following equation (4) with pressure ρ, flow velocity W, and Weber number Weσ. D = Weσ / (ρW) 2 ) ···(4)

[0044] The Weber number Weσ is a dimensionless number that represents the ratio of the inertial force of vapor to the surface tension of a water droplet. As the pressure ρ increases, the water droplet diameter D decreases.

[0045] The collision velocity of a water droplet is calculated by calculating the trajectory of the water droplet from the flow velocity and water droplet diameter mentioned above. The larger the water droplet diameter, the less the water droplet is accelerated by the steam, and the greater the velocity difference between the steam and the water droplet, resulting in a higher collision velocity of the water droplet with the rotor blade. In this embodiment, the trajectory analysis program for the water droplet may be stored in the calculation unit 21b to calculate the collision velocity of the water droplet. Also in this embodiment, in order to reduce the computational capacity and load of the calculation unit 21b, the trajectory calculation may be performed comprehensively under conditions expected in actual operation, and the relationship between the above input and output may be stored in the calculation unit 21b as an approximate function.

[0046] Meanwhile, the material properties and correction coefficient (S4) of the final stage rotor blade are stored in advance in the calculation unit 21b. Based on the water droplet impact velocity, water volume, water droplet diameter, rotor blade material properties, and correction coefficient, the erosion rate dE / dt (S5) of the final stage rotor blade, shown in equation (2), is evaluated, and the amount of erosion ΔE over a certain time range Δt is calculated using the following equation (5). ΔE = dE / dt × Δt ... (5)

[0047] The erosion rate E(S6) is calculated based on the erosion rate dE / dt. Specifically, the erosion rate E is calculated by accumulating ΔE, which is calculated using equation (5), over the operating time of the steam turbine plant. In other words, the erosion rate E is calculated by accumulating the erosion rate dE / dt. This makes it possible to evaluate the erosion rate E of the final stage, which reflects the operation of the low-pressure turbine 15 to date. Note that the erosion rate dE / dt varies greatly depending on the electrical output of the generator 16 and the inlet steam temperature of the low-pressure turbine 15. Therefore, by appropriately setting Δt according to the frequency of state changes of the generator 16 and the low-pressure turbine 15, the accuracy of the evaluation of the erosion rate E can be improved.

[0048] The advantages of the turbine monitoring system of this embodiment will now be described.

[0049] As mentioned above, with the recent expansion of renewable energy use, steam turbines are increasingly being used as regulatory thermal power plants, and diversification of their operation (partial load operation and start-up / stop-down) is required. Due to this diversification of operation, the state variables at the inlet of the final stage blades of the steam turbine will also fluctuate under various conditions. Therefore, it is expected that the aforementioned impact velocity and the number of water droplets will change moment by moment depending on the operation of the plant. Consequently, it is considered difficult to predict the amount of erosion at the steam turbine design stage.

[0050] Therefore, in this embodiment, in response to the ever-changing plant operations, the erosion rate of the final stage rotor blades is calculated in real time during turbine plant operation, and the amount of erosion is calculated by accumulating the erosion rate over the operating time. Thus, according to this embodiment, it is possible to evaluate the amount of erosion of the final stage rotor blades that reflects actual operations with high accuracy. As a result, it becomes possible to accurately detect and predict the replacement or repair timing of the final stage, thereby preventing blade scattering due to erosion and improving the reliability of the plant.

[0051] In this embodiment, the BFP18 is driven by an electric motor when the electrical output of the generator 16 is less than a specified value, and is driven by the BFPT19 when the electrical output of the generator 16 is greater than a specified value. In the former case, the BFPT inlet valve 20 is closed, and extraction from the intermediate-pressure turbine 14 is stopped. In the latter case, the BFPT inlet valve 20 is opened, and extraction from the intermediate-pressure turbine 14 is performed. Due to the diversification of operations, the electrical output of the generator 16 may vary over a wide range, and it is conceivable that switching between the former and latter states will occur frequently. Accordingly, it is conceivable that the flow rate of steam passing through the final stage blades of the low-pressure turbine 15 will also often change discontinuously depending on the operation of the plant.

[0052] For example, the erosion rate of the final stage rotor blades can be calculated based on the temperature of the steam introduced into the low-pressure turbine 15 and the flow rate of water obtained from the steam discharged from the low-pressure turbine 15. This makes it possible to estimate the flow rate of steam passing through the final stage rotor blades based on this water flow rate. In this case, the water flow rate can be measured by detecting the flow rate of water in the feedwater channel P8 using a flow meter. However, if steam extraction from the intermediate-pressure turbine 14 is performed, the water in the feedwater channel P8 includes not only the water obtained from the steam discharged from the low-pressure turbine 15 but also the water obtained from the steam extracted from the intermediate-pressure turbine 14. Therefore, in this case, it is not possible to accurately estimate the flow rate of steam passing through the final stage rotor blades, and thus the erosion rate cannot be calculated accurately.

[0053] Furthermore, the erosion rate of the final stage rotor blades can be calculated based on the temperature of the steam introduced into the low-pressure turbine 15 and the pressure of the steam introduced into the low-pressure turbine 15. This makes it possible to estimate the flow rate of the steam passing through the final stage rotor blades based on this steam pressure. However, even in this case, the accuracy of estimating the steam flow rate may deteriorate due to extraction, and as a result, the accuracy of calculating the erosion rate may deteriorate.

[0054] Therefore, in this embodiment, the erosion rate of the final stage rotor blades is calculated based on the temperature of the steam introduced into the low-pressure turbine 15 and the electrical output of the generator 16. This makes it possible to estimate the flow rate of steam passing through the final stage rotor blades based on this electrical output. In this case, if the amount of steam extracted from the intermediate-pressure turbine 14 changes, the electrical output of the generator 16 changes according to the amount of steam extracted. As a result, it becomes possible to estimate the flow rate of steam passing through the final stage rotor blades while taking the extraction into account. Thus, according to this embodiment, even when extraction is performed, it is possible to accurately estimate the flow rate of steam passing through the final stage rotor blades and to accurately calculate the erosion rate.

[0055] The following describes various modifications of the turbine monitoring system of this embodiment. The following description is also applicable to the second embodiment described later.

[0056] In this embodiment, the erosion rate E is calculated by integrating the erosion rates dE / dt, but the erosion rate E may be calculated by other methods. For example, the erosion rate E may be calculated from the erosion rate dE / dt using a method other than integration, or the erosion rate E may be calculated from the generator electrical output and turbine inlet temperature without calculating the erosion rate dE / dt.

[0057] Furthermore, the inlet temperature measuring instrument 22 in this embodiment may be replaced with the inlet temperature measuring instrument 24 shown in Figure 1. The inlet temperature measuring instrument 24 detects the temperature of the steam introduced into the low-pressure turbine 15 and outputs the temperature detection result to the turbine monitoring device 21. Specifically, the inlet temperature measuring instrument 24 is installed in the inlet piping (steam flow path P4) located upstream of the first stage stator blades of the low-pressure turbine 15, and detects the temperature of the steam at the inlet of the low-pressure turbine 15. The inlet temperature measuring instrument 24 is equipped with, for example, a thermocouple, and outputs the thermoelectric current from the hot junction of the thermocouple installed in the flow field where the temperature is measured to the storage unit 21a via wiring (for example, a compensating wire). Note that the inlet of the low-pressure turbine 15 refers to the inlet of the first stage turbine stage.

[0058] Furthermore, the extraction passage P6 in this embodiment may be connected to the low-pressure turbine 15 or the high-pressure turbine 12 instead of the intermediate-pressure turbine 14. In this case, the extraction passage P6 extracts steam from the low-pressure turbine 15 or the high-pressure turbine 12.

[0059] As described above, in this embodiment, the amount of erosion of the rotor blades of the low-pressure turbine 15 is calculated based on the detection results output from the inlet temperature measuring instrument 22 and the electrical output measuring instrument 23, and information based on the calculated amount of erosion is output. Therefore, according to this embodiment, it is possible to appropriately evaluate the amount of erosion of the rotor blades of the low-pressure turbine 15. For example, according to this embodiment, even when steam is extracted from one of the steam turbines, it is possible to accurately evaluate the amount of erosion of the final stage rotor blades of the low-pressure turbine 15.

[0060] The following describes the steam turbine plant of the second embodiment. In the following description, the differences from the steam turbine plant of the first embodiment will be explained, and the similarities with the steam turbine plant of the first embodiment will not be explained.

[0061] (Second Embodiment) Figure 3 is a schematic diagram showing the configuration of a steam turbine plant according to the second embodiment.

[0062] The steam turbine plant in Figure 3 is a reheat type plant and, in addition to the components shown in Figure 1, is equipped with an outlet pressure measuring instrument 25.

[0063] The outlet pressure measuring instrument 25 detects the pressure of the steam discharged from the low-pressure turbine 15 and outputs the detected pressure to the turbine monitoring device 21. Specifically, the outlet pressure measuring instrument 25 is installed in the outlet piping (steam flow path P5) located downstream of the final stage rotor blades of the low-pressure turbine 15, and detects the steam pressure at the outlet of the low-pressure turbine 15. The outlet pressure measuring instrument 25 is equipped with, for example, a pressure conduit and a pressure sensor. The pressure sensor detects the pressure from the pressure conduit installed in the flow field where the pressure is to be measured, and outputs an output signal indicating the detected pressure to the storage unit 21a. The outlet of the low-pressure turbine 15 refers to the outlet of the final stage turbine stage.

[0064] The memory unit 21a stores the detection result of the inlet steam temperature output from the inlet temperature measuring instrument 22, the detection result of the electrical output output from the electrical output measuring instrument 23, and the detection result of the outlet steam pressure output from the outlet pressure measuring instrument 25. In this embodiment, when the steam turbine is in operation, the memory unit 21a receives the output signal (thermoelectric current) from the inlet temperature measuring instrument 22, the output signal from the electrical output measuring instrument 23, and the output signal from the outlet pressure measuring instrument 25 via the input / output unit of the turbine monitoring device 21, averages these output signals over a certain operating time, and outputs them to the calculation unit 21b.

[0065] The calculation unit 21b calculates the amount of erosion caused by water droplets on the rotor blades of the low-pressure turbine 15 based on the detection result of the inlet steam temperature output from the inlet temperature measuring instrument 22, the detection result of the electrical output output from the electrical output measuring instrument 23, and the detection result of the outlet steam pressure output from the outlet pressure measuring instrument 25. In this embodiment, the calculation unit 21b calculates the amount of erosion caused by water droplets on the rotor blades 2 (see Figure 5) of the final stage of the low-pressure turbine 15 based on the signal output from the storage unit 21b. The calculation unit 21b is implemented, for example, by a processor and a computer program, and the computer program executed by the processor calculates the amount of erosion based on the signal from the storage unit 21b and various data.

[0066] The output unit 21c outputs information based on the amount of erosion calculated by the calculation unit 21b, similar to the case of the first embodiment.

[0067] Figure 4 is a flowchart illustrating the operation of the turbine monitoring system of the second embodiment. Figure 4 shows the calculation flow by the calculation unit 21b.

[0068] The calculation flow in Figure 4 is the same as the calculation flow in Figure 2. However, in this embodiment, the steam flow rate, moisture content, pressure, and velocity (S2) at the inlet of the final stage rotor blade of the low-pressure turbine 15 are calculated based on the generator electrical output, turbine inlet temperature, and turbine outlet pressure (S11) input from the memory unit 21a. In this embodiment, a fluid analysis or one-dimensional steam calculation program may be stored in the calculation unit 21b, and the flow rate, moisture content, pressure, and velocity at the inlet of the final stage rotor blade may be calculated using the electrical output, inlet temperature, and outlet pressure as inputs. In addition, in this embodiment, in order to reduce the calculation capacity and load of the calculation unit 21b, a comprehensive fluid analysis or one-dimensional steam calculation under conditions expected in actual operation may be performed in advance, and the relationship between the above inputs and outputs may be stored as an approximate function.

[0069] When the steam pressure at the outlet of the low-pressure turbine 15 (turbine outlet pressure) decreases, the expansion work of the steam in the low-pressure turbine 15 increases. Therefore, when the steam pressure at the outlet of the low-pressure turbine 15 decreases, the electrical output of the generator 16 (generator electrical output) increases even if the steam flow rate at the outlet of the low-pressure turbine 15 does not change. In other words, the steam flow rate required to obtain a certain generator electrical output decreases as the turbine outlet pressure decreases. According to this embodiment, by calculating the erosion rate while taking the turbine outlet pressure into consideration, it is possible to reflect such characteristics of generator electrical output in the calculation of the erosion rate.

[0070] As described above, in this embodiment, the amount of erosion of the rotor blades of the low-pressure turbine 15 is calculated based on the detection results output from the inlet temperature measuring instrument 22, the electrical output measuring instrument 23, and the outlet pressure measuring instrument 25, and information based on the calculated amount of erosion is output. Therefore, according to this embodiment, it is possible to appropriately evaluate the amount of erosion of the rotor blades of the low-pressure turbine 15. For example, according to this embodiment, even when steam is extracted from one of the steam turbines, it is possible to accurately evaluate the amount of erosion of the final stage rotor blades of the low-pressure turbine 15. Furthermore, according to this embodiment, by taking into account the detection results output from the outlet pressure measuring instrument 25 when calculating the amount of erosion, it is possible to improve the accuracy of the evaluation of the amount of erosion of the final stage rotor blades of the low-pressure turbine 15.

[0071] Although several embodiments have been described above, these embodiments are presented only as examples and are not intended to limit the scope of the invention. The novel systems and methods described herein can be implemented in a variety of other forms. Furthermore, various omissions, substitutions, and modifications can be made to the forms of systems and methods described herein, without departing from the spirit of the invention. The appended claims and equivalents are intended to include such forms and modifications that are included in the scope and spirit of the invention. [Explanation of Symbols]

[0072] 1: Stator blades of the final stage of the turbine, 2: Rotary blades of the final stage of the turbine 3: Stator blades preceding the final stage of the turbine, 4: Rotary blades preceding the final stage of the turbine 5: Trailing edge of the wing, 6: Outer diaphragm ring, 7: Trailing edge of the wing, 8: Leading edge of the wing 11: Boiler, 12: High-pressure turbine, 13: Reheater, 14: Medium-pressure turbine 15: Low-pressure turbine, 16: Generator, 17: Condenser, 18: BFP, 19: BFPT, 20: BFPT inlet valve, 21: Turbine monitoring device, 21a: Memory unit, 21b: Calculation unit, 21c: Output unit, 22: Inlet temperature measuring instrument, 23: Electrical output measuring instrument, 24: Inlet temperature measuring device, 25: Outlet pressure measuring device

Claims

1. A temperature measuring instrument that detects the temperature of steam introduced into a steam turbine and outputs the temperature detection result, An electrical output measuring instrument that detects the electrical output of a generator driven by the steam turbine and outputs the detected electrical output; A calculation unit calculates the properties of water droplets generated from the steam at the inlet of the final stage blade of the steam turbine based on the temperature detection result output from the temperature measuring instrument and the electrical output detection result output from the electrical output measuring instrument, and calculates the amount of erosion of the blade by the water droplets based on the properties of the water droplets. An output unit that outputs information based on the amount of erosion calculated by the calculation unit, A turbine monitoring system equipped with the following features.

2. The turbine monitoring system according to claim 1, wherein the calculation unit calculates the erosion rate, which is the amount of erosion per unit time caused by water droplets on the rotor blade, and calculates the amount of erosion based on the erosion rate.

3. The turbine monitoring system according to claim 2, wherein the calculation unit calculates the amount of erosion by accumulating the erosion rate over the operating time of the steam turbine.

4. The turbine monitoring system according to claim 1, wherein the properties of the water droplet include at least one of the water droplet impact velocity, water volume, and water droplet diameter.

5. The turbine monitoring system according to claim 1, wherein the output unit displays information based on the amount of erosion calculated by the calculation unit.

6. The turbine monitoring system according to claim 5, wherein the output unit displays the amount of erosion or an alarm based on the amount of erosion.

7. The system further includes a pressure measuring instrument for detecting the pressure of the steam discharged from the steam turbine, The turbine monitoring system according to claim 1, wherein the calculation unit calculates the amount of erosion based on the temperature detection result output from the temperature measuring instrument, the electrical output detection result output from the electrical output measuring instrument, and the pressure detection result output from the pressure measuring instrument.

8. The turbine monitoring system according to claim 1, wherein the steam turbine is installed in a plant that includes a high-pressure turbine, an intermediate-pressure turbine, and a low-pressure turbine that drive the generator, and the steam turbine is the low-pressure turbine.

9. The turbine monitoring system according to claim 8, wherein the temperature measuring instrument detects the temperature of steam in the steam flow path between the high-pressure turbine and the intermediate-pressure turbine.

10. The turbine monitoring system according to claim 8, wherein the temperature measuring instrument detects the temperature of steam in the steam flow path between the intermediate-pressure turbine and the low-pressure turbine.

11. The turbine monitoring system according to claim 1, further comprising an extraction channel for extracting steam from the steam turbine or from another steam turbine that drives the generator.

12. The turbine monitoring system according to claim 11, wherein the extraction channel discharges the extracted steam to a condenser.

13. A boiler that generates steam to be introduced into the steam turbine, A boiler feedwater pump is provided in the feedwater channel from the condenser to the boiler, Furthermore, The turbine monitoring system according to claim 12, wherein the extraction flow path is provided with a turbine that is driven by the extracted steam, operates the boiler feedwater pump to pressurize the water from the condenser, and supplies the pressurized water to the boiler.

14. The temperature of the steam introduced into the steam turbine is detected by a temperature measuring instrument, and the temperature detection result is output from the temperature measuring instrument. The electrical output of the generator driven by the steam turbine is detected by an electrical output measuring instrument, and the detected result of the electrical output is output from the electrical output measuring instrument. Based on the temperature detection result output from the temperature measuring instrument and the electrical output detection result output from the electrical output measuring instrument, the properties of the water droplets generated from the steam at the inlet of the final stage blade of the steam turbine are calculated, and based on the properties of the water droplets, the amount of erosion of the blade by the water droplets is calculated by the calculation unit. The output unit outputs information based on the amount of erosion calculated by the calculation unit. A turbine monitoring method that includes the following.

15. The method further includes detecting the pressure of the steam discharged from the steam turbine using a pressure measuring instrument. The turbine monitoring method according to claim 14, wherein the amount of erosion is calculated by the calculation unit based on the temperature detection result output from the temperature measuring instrument, the electrical output detection result output from the electrical output measuring instrument, and the pressure detection result output from the pressure measuring instrument.

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