JP2009264220A - Steam leakage detection device for steam injection gas turbine - Google Patents

Abstract

<P>PROBLEM TO BE SOLVED: To provide a steam leakage detecting device capable of detecting presence of leakage of steam in an early stage in a steam bypass system for supplying the steam to a combustor in a steam injection gas turbine. <P>SOLUTION: The steam leakage detecting device 7 is provided with a reading means 71 for successively reading a measured value by an injection steam pressure gauge 61 as pressure data P(i) and successively reading a measured value by an injection steam flowmeter 62 as flow rate data S(i), and a determination means 72 for calculating standard deviations Pd and Sd for a plurality of the pressure data P(i) and a plurality of the flow rate data S(i) successively read in a prescribed measurement time period T3 and determining that leakage of the steam S occurs in the steam bypass system 6 when a ratio Sd/Pd between the standard deviation Pd of the pressure data P(i) and the standard deviation Sd of the flow rate data S(i) is successively out of the prescribed normal range twice or more. <P>COPYRIGHT: (C)2010,JPO&INPIT

Description

  The present invention relates to a steam leak detection device capable of detecting whether or not water vapor has leaked in a steam bypass system from an exhaust gas steam boiler to a combustor in a steam injection gas turbine.

  2. Description of the Related Art Conventionally, a cogeneration system that generates power using a gas turbine and uses exhaust heat of exhaust gas exhausted from the gas turbine is known. For example, in the steam-injection gas turbine power generator disclosed in Patent Document 1, combustion is performed using air and fuel gas compressed by a compressor in the combustor, and the turbine is rotationally driven by the combustion gas. And driving the generator. Further, in the exhaust heat recovery boiler, a device is devised in which steam is generated using exhaust heat of the turbine, a part of the steam is injected into the combustor, and the remainder of the steam is used as process steam. For example, Patent Document 1 discloses a method for controlling a steam-injected gas turbine that can perform a stable operation while avoiding misfire of a combustor.

  However, in the conventional steam injection type gas turbine, when water vapor leaks in the path for supplying the injected steam to the combustor, this leakage cannot be detected at an early stage. In other words, the output of the gas turbine is constantly changing due to the influence of the air intake temperature, the fuel gas supply amount, the injection steam supply amount, and the like. Therefore, in the conventional steam injection type gas turbine, the slight decrease in output due to the leakage of water vapor is not clearly understood, and the leakage of water vapor can be detected only after the leakage of water vapor increases and the output decreases greatly. It was.

JP 2007-332817 A

  The present invention has been made in view of such conventional problems, and steam capable of detecting at an early stage whether or not water vapor has leaked in a steam bypass system for supplying steam to a combustor in a steam injection gas turbine. A leak detection device is to be provided.

The present invention is a gas turbine in which a turbine wheel and a compressor wheel are arranged on the same axis;
A combustor that performs combustion using fuel gas received from a fuel supply system and compressed air sucked and compressed by the compressor wheel;
A generator for generating electric power by receiving rotation of the turbine wheel rotated by combustion gas from the combustor;
An exhaust gas steam boiler that generates water vapor from feed water received from the feed water system and exhaust gas received from the turbine wheel;
A steam supply system for supplying steam generated in the exhaust gas steam boiler to the outside as process steam;
A process steam control valve disposed in the steam supply system for adjusting the pressure of steam generated in the exhaust gas steam boiler;
A steam bypass system for connecting the upstream position of the process steam control valve in the steam supply system and the combustor, and supplying a part of the steam in the steam supply system to the combustor;
An injection steam pressure gauge that is disposed in the steam bypass system or the steam supply system and measures the pressure of water vapor generated in the exhaust gas steam boiler;
An injection steam flow meter which is disposed in the steam bypass system and measures the flow rate of water vapor passing through the steam bypass system;
In the steam injection type gas turbine provided in the steam bypass system and provided with an injection steam control valve for adjusting the flow rate of the steam to be injected into the combustor, whether or not steam leaks in the steam bypass system. A steam leak detection device capable of detecting
The steam leak detection device sequentially reads the measurement value by the jet steam pressure gauge as pressure data, and the reading means for sequentially reading the measurement value by the jet steam flow meter as flow data,
A standard deviation or variance value is obtained for each of the plurality of pressure data and the plurality of flow rate data sequentially read within a predetermined measurement period, and a standard deviation or variance value for the pressure data and a standard for the flow rate data are obtained. A determination means for detecting the occurrence of water vapor leakage in the steam bypass system when the ratio with the deviation or the variance value has deviated from the predetermined normal range once or more than once. A steam leakage detection device for a steam-injection type gas turbine characterized in that (Claim 1).

The steam leak detection device of the present invention can detect whether or not steam leaks in a steam bypass system for supplying steam to a combustor in a steam injection gas turbine.
In order to realize this, in the steam injection type gas turbine of the present invention, an injection steam pressure gauge and an injection steam flow meter disposed in the steam bypass system are used. Further, the steam leak detection device of the present invention comprises the above-mentioned reading means and determination means, and uses the pressure data read from the jet steam pressure gauge and the flow rate data read from the jet steam flow meter, the standard deviation or variance between the two. A value (hereinafter, referred to as a standard deviation or the like) is obtained, and it is possible to detect whether or not water vapor leakage has occurred in the steam bypass system from these ratios.

  The steam leak detection device of the present invention can be operated almost always while the steam injection gas turbine is in operation. And when operating a steam injection type gas turbine, the opening degree of a process steam control valve is adjusted, and thereby the pressure of water vapor generated in the exhaust gas steam boiler (the pressure of water vapor in the steam supply system and the steam bypass system) It is adjusted to a predetermined target pressure. At this time, even if the opening degree of the injection steam control valve is the same, the change in the pressure of the process steam at the steam supply destination by the steam supply system, the supply amount of feed water from the feed water system to the exhaust gas steam boiler, The steam pressure in the steam supply system and the steam bypass system fluctuates due to changes in the balance between the supply amount and temperature of the exhaust gas from the turbine wheel to the exhaust gas steam boiler. The flow rate also varies.

  Here, when there is no leakage of water vapor in the steam bypass system, the flow rate of the injected steam (steam) in the steam bypass system also fluctuates in the same manner due to fluctuations in the pressure of the injected steam (steam) in the steam bypass system. As a result, it is considered that there is a substantially proportional relationship between the measured value by the jet steam pressure gauge and the measured value by the jet steam flow meter. On the other hand, when water vapor leaks in the steam bypass system, the flow rate of water vapor in the steam bypass system increases (the measured value by the injection steam flow meter increases). As a result, the steam pressure in the steam bypass system decreases (measured value by the injection steam pressure gauge decreases), and the process steam control valve is slightly closed. And if the amount of water vapor leakage does not change, the measured value by the injection steam flow meter will fluctuate due to natural pressure fluctuation in this state, but the measured value by the injection steam flow meter with respect to the fluctuation amount of the measured value by the injection steam pressure gauge The fluctuation amount of becomes larger.

In the steam leak detection device of the present invention, when steam leaks in the steam bypass system, pay attention to the change in the ratio of the steam pressure change amount and the steam flow rate change amount in the steam bypass system. Then, it is detected whether or not water vapor leakage has occurred in the steam bypass system.
Specifically, the reading means in the steam leak detection device sequentially reads the measurement value by the injection steam pressure gauge as pressure data, and sequentially reads the measurement value by the injection steam flow meter as the flow data. At this time, the steam leak detection device can sequentially read and store pressure data and flow rate data at a predetermined measurement interval (sampling time).

And the determination means in a steam leak detection apparatus calculates | requires a standard deviation etc. respectively about the several pressure data and several flow data which were read sequentially within the predetermined | prescribed measurement period. At this time, when a water vapor leak occurs in the steam bypass system, the standard deviation of the flow rate data becomes larger than the standard deviation of the pressure data. The determination means detects that the steam bypass system has leaked when the ratio between the standard deviation or the like for the pressure data and the standard deviation or the like for the flow rate data is out of a predetermined normal range. be able to.
The ratio can be obtained as a value such as a standard deviation for the flow rate data with respect to a standard deviation for the pressure data. In this case, the determination means can detect that water vapor leaks in the steam bypass system when the ratio value exceeds a predetermined value as a predetermined normal range.

And in the steam leak detection device of the present invention, the presence or absence of this leak is detected at an early stage by detecting the presence or absence of the leak of water vapor in the steam bypass system based on the standard deviation or the like for the pressure data and the flow rate data. be able to. Thereby, it is no longer necessary to operate the steam injection gas turbine in a situation where the leakage of water vapor occurs and the energy efficiency is poor, and the energy efficiency of the steam injection gas turbine can be improved.
As described above, according to the steam leak detection device of the present invention, it is possible to detect at an early stage whether or not steam leaks in a steam bypass system for supplying steam to a combustor in a steam injection gas turbine.

A preferred embodiment of the above-described steam leak detection device for a steam injection gas turbine of the present invention will be described.
In the present invention, the determination means, for each predetermined preliminary measurement period shorter than the measurement period, for each of the plurality of pressure data and the plurality of flow rate data sequentially read during the preliminary measurement period, It is preferable that the standard deviation or the variance value is obtained for each of the pressure data and the flow rate data by using the sum of the squares of deviations of the plurality of preliminary measurement periods in the measurement period. Claim 2).

  In this case, in the steam-injection gas turbine, passive changes that cannot be controlled (changes in the pressure of water vapor at the steam supply destination by the steam supply system, the supply amount of feed water from the feed water system to the exhaust gas steam boiler, and the exhaust gas Not only the balance between the supply amount and supply temperature of the exhaust gas from the turbine wheel to the steam boiler, the adjustment of the opening degree of the process steam control valve, etc., but also the opening degree of the injection steam control valve was adjusted. Even when there is an active change due to this, it is possible to accurately obtain the standard deviation and the like for each of the pressure data and the flow rate data.

That is, when there is the active change, the value of the pressure data and the value of the flow rate data fluctuate greatly. At this time, if the standard deviation is simply obtained for each of the plurality of pressure data and the plurality of flow data that are sequentially read within the predetermined measurement period, the influence of the active change is affected by the standard deviation and the flow rate of the pressure data. There is a high possibility that it will be reflected in the ratio to the standard deviation etc. of the data.
On the other hand, by calculating the standard deviation of the pressure data using the sum of the square of deviations for the pressure data, and by calculating the standard deviation of the flow data using the sum of the square of deviations for the flow data, It can suppress that the influence by an active change is reflected in the ratio of the standard deviation etc. about pressure data, and the standard deviation etc. about flow volume data.

Embodiments of a steam leakage detection apparatus for a steam injection gas turbine according to the present invention will be described below with reference to the drawings.
As shown in FIG. 1, the steam injection type gas turbine 1 of this example includes the following gas turbine 2, combustor 3, fuel supply system 31, generator 25, exhaust gas steam boiler 4, water supply system 43, steam supply system 5, A process steam control valve 51, a steam bypass system 6, an injection steam pressure gauge 61, an injection steam flow meter 62, and an injection steam control valve 63 are provided.
The gas turbine 2 sucks air A <b> 1 by rotating with the turbine wheel 21 rotated by the combustion gas G <b> 1 generated by the combustor 3, and supplies the compressed compressed air A <b> 2 to the combustor 3. The compressor wheel 22 is arranged on the same axis.

As shown in the figure, the fuel supply system 31 is configured to supply a predetermined flow rate of fuel gas F to the combustor 3. The combustor 3 is configured to perform combustion using the fuel gas F received from the fuel supply system 31 and the compressed air A2 sucked and compressed by the compressor wheel 22. Further, in order to increase the working gas in the gas turbine 2, the steam S is injected from the steam bypass system 6 into the combustor 3.
The generator 25 is connected to the output shaft of the compressor wheel 22 and is configured to generate power upon receiving the rotation of the compressor wheel 22. The exhaust gas steam boiler 4 includes an exhaust gas boiler 41 that operates using the exhaust gas G <b> 2 received from the turbine wheel 21, a steam drum 42 that performs gas-liquid separation by the exhaust gas boiler 41 to generate steam S, and an exhaust gas G <b> 2 that is received from the turbine wheel 21. And an economizer 43 as a water supply system 43 that preheats the water supply W1 and generates preheated water supply W2.

As shown in FIG. 1, the steam supply system 5 is configured to supply the steam S generated in the steam drum 42 of the exhaust gas steam boiler 4 to the outside as the process steam S1. The process steam control valve 51 is disposed in the steam supply system 5 and is configured to adjust the pressure of the steam S generated in the steam drum 42 of the exhaust gas steam boiler 4. The steam bypass system 6 connects the upstream position of the process steam control valve 51 in the steam supply system 5 and the combustor 3, and is configured to inject a part of the steam S in the steam supply system 5 to the combustor 3. Yes.
The jet steam pressure gauge 61 is disposed in the steam bypass system 6 and is configured to measure the pressure of the steam S generated in the steam drum 42 of the exhaust gas steam boiler 4. The jet steam flow meter 62 is disposed in the steam bypass system 6 and is configured to measure the flow rate of the water vapor S passing through the steam bypass system 6. The injection steam control valve 63 is disposed in the steam bypass system 6 and is configured to adjust the flow rate of the water vapor S injected to the combustor 3.

As shown in FIGS. 1 and 2, the steam leak detection device 7 of this example uses the measured value by the jet steam pressure gauge 61 and the measured value by the jet steam flow meter 62 to leak the steam S into the steam bypass system 6. It is comprised so that it may be detected whether or not.
The steam leak detection device 7 is configured to realize the following reading means 71 and determination means 72 by a calculation process by a computer. The reading means 71 sequentially reads the measurement value by the injection steam pressure gauge 61 as pressure data P (i) (i = 1 to m), and the measurement value by the injection steam flow meter 62 is flow data S (i) (i = 1 to m) are sequentially read. The determination means 72 is configured to obtain standard deviations Pd and Sd for a plurality of pressure data P (i) and a plurality of flow rate data S (i) that are sequentially read within a predetermined measurement period T3. . Then, in the determination means 72, the ratio Sd / Pd between the standard deviation Pd for the pressure data P (i) and the standard deviation Sd for the flow rate data S (i) has continuously deviated from the predetermined normal range a plurality of times. Sometimes, the steam bypass system 6 is configured to detect the leakage of the water vapor S.

Below, it demonstrates in full detail with reference to FIGS. 1-7 about the steam leak detection apparatus 7 of the steam injection type gas turbine 1 of this example.
As shown in FIG. 1, the steam injection type gas turbine 1 of this example performs combustion using the fuel gas F, compressed air A2, and water vapor S in the combustor 3, and operates the gas turbine 2 with the combustion gas G1. While generating with the generator 25, it is comprised so that the water vapor | steam S may be generated with the waste gas steam boiler 4 using the waste gas G2 from the gas turbine 2. FIG.
The steam supply system 5 and the steam bypass system 6 are both configured by piping.
The injection steam pressure gauge 61 of this example is disposed at an upstream position in the steam bypass system 6 (position close to a position connected to the steam supply system 5), and the injection steam flow meter 62 is connected to the steam bypass system 6. In FIG. 2, the fuel vapor pressure gauge 61 is disposed at a position downstream of the fuel vapor pressure gauge 61.

Further, the injection steam control valve 63 of this example is disposed at a position downstream of the position where the injection steam flow meter 62 is disposed in the steam bypass system 6 (position between the injection steam flow meter 62 and the combustor 3). It is.
The steam drum 42 is provided with a drum pressure gauge 44 for measuring the pressure of the water vapor S in the steam drum 42. The process steam control valve 51 of this example is configured to adjust the opening degree so that the measured value by the drum pressure gauge 44 becomes substantially constant.

  The determination means 72 in the steam leak detection device 7 of the present example is for a plurality of pressure data P (i) sequentially read in the preliminary measurement period T2 for each predetermined preliminary measurement period T2 shorter than the measurement period T3. The deviation sum of squares Pv (j) (j = 1 to n) is obtained, and the deviation sum of squares Sv (j) (j = 1 to 1) is obtained for a plurality of flow rate data S (i) sequentially read within the preliminary measurement period T2. n). Then, the determination means 72 uses the sum of the squared deviations Pv (j) of the pressure data P (i) of the plurality of preliminary measurement periods T2 within the measurement period T3 to use the standard deviation Pd for the pressure data P (i). And the standard deviation Sd for the flow rate data S (i) is obtained by using the sum of the squared deviations Sv (j) of the flow rate data S (i) for the plurality of preliminary measurement periods T2 within the measurement period T3. It is configured.

  The reading means 71 in the steam leak detection device 7 of this example is configured to read the pressure data P (i) and the flow rate data S (i) every predetermined sampling period (sampling time) T1. Further, the determination means 72 in the steam leak detection device 7 of the present example has a deviation square sum Pv (j) of the pressure data P (i) every predetermined preliminary measurement period (calculation time) T2 which is an integer multiple of the sampling period T1. ) And the deviation square sum Sv (j) of the flow rate data S (i). In addition, the determination means 72 of the present example has a standard deviation Pd of the pressure data P (i) and a standard of the flow rate data S (i) every predetermined measurement period (determination time) T3 that is an integral multiple of the preliminary measurement period T2. Deviation Sd is obtained, and it is configured to detect whether or not these ratios Sd / Pd are larger than a predetermined abnormality determination value A. The sampling period T1 of this example was 1 minute, the preliminary measurement period T2 of this example was 10 minutes, and the measurement period T3 of this example was 60 minutes.

Next, the operation of detecting the presence or absence of leakage of the water vapor S in the steam bypass system 6 in the steam injection gas turbine 1 using the steam leak detection device 7 will be described with reference to the flowchart of FIG.
When the steam injection type gas turbine 1 is operated, combustion in the combustor 3 is performed to start the operation of the gas turbine 2, and power generation by the generator 25 is started. Then, the steam leak detection device 7 determines whether or not the power generation output in the generator 25 is equal to or greater than a predetermined set value (step S101 in FIG. 2), and this power generation output is equal to or greater than the predetermined set value. Sometimes, detection of the presence or absence of steam leakage is started, and counting of abnormality diagnosis is started (S102). This count includes a sampling count C1 that measures the progress of the sampling period T1, a preliminary measurement period count C2 that measures the progress of the preliminary measurement period T2, and a measurement period count that measures the progress of the measurement period T3. There is C3.

Next, the steam leak detection device 7 determines whether or not the sampling count C1 has reached a predetermined sampling period T1 (1 minute in this example) (S103), and until the sampling count C1 reaches the sampling period T1, The above S102 and S103 are repeated.
When the sampling count C1 reaches the sampling period T1, the steam leak detection device 7 reads the pressure of the steam S measured by the jet steam pressure gauge 61 as the pressure data P (i) and the jet steam flow meter 62. The flow rate of water vapor S measured by the above is read as flow rate data S (i) (S104).

  Next, the steam leak detection device 7 determines whether or not the preliminary measurement period count C2 has reached a predetermined preliminary measurement period T2 (10 minutes in this example) (S105), and the preliminary measurement period count C2 is the preliminary measurement. The above S102 to S105 are repeated until the period T2. Further, when the preliminary measurement period count C2 is not the preliminary measurement period T2 (when the determination in S105 is No), the steam leak detection device 7 initializes the sampling count C1 to zero (S106).

  Next, when the preliminary measurement period count C2 reaches the preliminary measurement period T2, the steam leak detection device 7 reads the pressure data P (i) and the flow rate data S (i) sequentially read during the preliminary measurement period T2. ) (In this example, 10 data per minute) are obtained for each of the square sums of deviations Pv (j) and Sv (j) (S107). And the steam leak detection apparatus 7 preserve | saves this deviation square sum Pv (j) and Sv (j).

  Here, the sum of squared deviations Pv (j) of the pressure data P (i) can be obtained by the following calculation formula (Formula 1). Here, m represents the number of sampling data in the preliminary measurement period T2 (m = 10 in this example), and P (i) represents the pressure data P (i) at each sampling point in the preliminary measurement period T2. Pv is the sum of squared differences between the average value of the pressure data P (i) in the preliminary measurement period T2 and the value of the pressure data P (i) at each sampling point in the preliminary measurement period T2. Indicated by.

  Further, the sum of squared deviations Sv (j) of the flow rate data S (i) can be obtained by the following calculation formula (Formula 2). Here, m represents the number of sampling data in the preliminary measurement period T2 (m = 10 in this example), and S (i) represents the flow rate data S (i) at each sampling point in the preliminary measurement period T2. Sv is the sum of the difference between the average value of the flow rate data S (i) in the preliminary measurement period T2 and the value of the flow rate data S (i) at each sampling point in the preliminary measurement period T2. Indicated by.

  Next, the steam leak detection device 7 determines whether or not the measurement period count C3 has reached a predetermined measurement period T3 (60 minutes in this example) (S108), and the measurement period count C3 becomes the measurement period T3. The above steps S102 to S108 are repeated. When the measurement period count C3 is not the measurement period T3 (when the determination in S108 is No), the steam leak detection device 7 initializes the preliminary measurement period count C2 to zero (S109) and performs sampling. The count C1 is initialized to zero (S106).

  Next, after repeating S102 to S109, when the measurement period count C3 reaches the measurement period T3, the steam leak detection device 7 uses the pressure data P (i) in the plurality of preliminary measurement periods T2 in which the above calculation is performed. The sum of the squared deviations Pv (j) (in this example, the sum of squared deviations Pv (j) of 10 samples per minute) is divided by the number of samples (m × n = 60) to obtain the pressure data P A standard deviation Pd based on (i) is obtained (S110). At this time, the steam leak detection device 7 also calculates the sum of squared deviations Sv (j) of the flow rate data S (i) in the plurality of preliminary measurement periods T2 in which the above calculation is performed (in this example, 10 samples per minute). The sum of deviation square sums Sv (j)) is summed, and this is divided by the number of samples (m × n = 60) to obtain the standard deviation Sd based on the flow rate data S (i) (S110).

  Here, the standard deviation Pd based on the pressure data P (i) can be obtained by the following calculation formula (Formula 3). Here, Pv (j) indicates the value of the deviation square sum Pv (j) of the pressure data P (i) in each preliminary measurement period T2, and n is the deviation square sum Pv (j) in the measurement period T3. The number of data (n = 6 in this example) is shown.

  Further, the standard deviation Sd based on the flow rate data S (i) can be obtained by the following calculation formula (Formula 4). Here, Sv (j) represents the value of the deviation square sum Sv (j) of the flow rate data S (i) in each preliminary measurement period T2, and n represents the deviation square sum Sv (j) in the measurement period T3. The number of data (n = 6) is shown.

  Next, the steam leak detection device 7 obtains a ratio Sd / Pd between the standard deviation Sd based on the flow rate data S (i) and the standard deviation Pd based on the pressure data P (i) as a diagnostic index, and the diagnostic index Sd / Pd Is greater than a predetermined abnormality determination value A (S111). At this time, when Sd / Pd is equal to or less than A, it is determined that there is no steam leakage, the measurement period count C3 is initialized to zero (S112), and the above S102 to S112 are repeated. When the measurement period count C3 is initialized to zero, the preliminary measurement period count C2 and the sampling count C1 are also initialized to zero (S109, S106).

  On the other hand, when Sd / Pd is larger than A (when the determination in S111 is Yes), Sd / Pd is continuously set to N times (for example, N = 2 to 10). It is determined whether or not it has repeatedly increased (S113). And when Sd / Pd becomes larger repeatedly N times continuously than A (when the determination in S113 is Yes), the steam leak detection device 7 has a steam leak in the steam bypass system 6. This can be detected and a steam leak occurrence alarm can be issued (S114).

  Note that the steam leak detection device 7 does not obtain the standard deviation Pd of the pressure data P (i) and the standard deviation Sd of the flow rate data S (i), but instead distributes the dispersion value of the pressure data P (i) and the flow rate data S (i). ) And the ratio of these dispersion values is repeated N times, and it is also possible to detect that there is a steam leak when the ratio becomes larger than a predetermined abnormality determination value A.

  The steam leak detection device 7 of this example can be operated almost constantly while the steam injection gas turbine 1 is operating. When the steam injection gas turbine 1 is operated, the opening degree of the process steam control valve 51 is adjusted, whereby the pressure of the steam S generated in the exhaust gas steam boiler 4 (steam supply system 5 and steam bypass system 6). Is adjusted to a predetermined target pressure. At this time, even if the opening degree of the injection steam control valve 63 is the same, the change in the pressure of the process steam S1 at the supply destination of the steam S by the steam supply system 5, the economizer to the steam drum 42 of the exhaust gas steam boiler 4 The steam supply system 5 and the steam bypass system depend on the balance between the supply amount of the preheated water W2 from 43 and the supply amount and supply temperature of the exhaust gas G2 from the turbine wheel 21 to the exhaust gas boiler 41 of the exhaust gas steam boiler 4. The pressure of the water vapor S in 6 changes, and the flow rate of the water vapor S supplied to the steam bypass system 6 also changes accordingly.

  Here, when there is no leakage of the steam S in the steam bypass system 6, the flow rate of the injected steam (steam) S in the steam bypass system 6 is also changed due to the fluctuation of the pressure of the injected steam (steam) S in the steam bypass system 6. It fluctuates in the same manner, and as a result, it is considered that there is a substantially proportional relationship between the measured value by the jet steam pressure gauge 61 and the measured value by the jet steam flow meter 62. On the other hand, when the steam S leaks in the steam bypass system 6, the flow rate of the steam S in the steam bypass system 6 increases (the measured value by the jet steam flow meter 62 increases). As a result, the pressure of the steam S in the steam bypass system 6 decreases (measured value by the injection steam pressure gauge 62 decreases), and the process steam control valve 51 is slightly closed. Then, if the leakage amount of the steam S does not change, the measured value by the injected steam flow meter 62 changes due to natural pressure fluctuations in this state, but the injected steam flow meter with respect to the changed value of the measured value by the injected steam pressure gauge 61 The amount of fluctuation of the measured value due to 62 increases.

In the steam leak detection device 7 of the present example, when the steam S leaks in the steam bypass system 6, the ratio between the pressure change amount of the steam S and the flow rate change amount of the steam S in the steam bypass system 6. Focusing on this change, it is detected whether or not the leakage of the steam S has occurred in the steam bypass system 6.
Incidentally, in the pressure and flow rate of the steam S in the steam bypass system 6 of the steam injection gas turbine 1, not only the uncontrollable passive change X1 exists as described above, but also the injection steam control valve 63 There is also an active change X2 due to intentionally adjusting the opening.

  Here, FIG. 3 is a graph showing the relationship between the steam injection type gas turbine 1 during operation with the horizontal axis representing time and the vertical axis representing the flow rate of the steam S in the steam bypass system 6. As shown in the figure, even if the opening degree of the injection steam control valve 63 is the same, an uncontrollable passive change X1 occurs in the pressure and flow rate of the steam S in the steam bypass system 6. In addition, by changing the opening degree of the injection steam control valve 63 in order to change the supply amount of the steam S to the combustor 3, the pressure and flow rate of the steam S in the steam bypass system 6 are actively changed X2. Also occurs.

  When the active change X2 is present, the value of the pressure data P (i) and the value of the flow rate data S (i) vary greatly. At this time, when the standard deviation is simply obtained for each of the plurality of pressure data P (i) and the plurality of flow rate data S (i) sequentially read within the predetermined measurement period T3, the influence of the active change is the pressure. There is a high possibility of being reflected in the ratio of the standard deviation for the data P (i) and the standard deviation for the flow rate data S (i).

  On the other hand, as described above, the determination means 72 in the steam leak detection device 7 of the present example has a plurality of pressures sequentially read for each sampling period T1 in the preliminary measurement period T2 for each predetermined preliminary measurement period T2. The deviation square sum Pv (j) is obtained for the data P (i), and the deviation square sum Sv (j) is obtained for a plurality of flow rate data S (i) sequentially read for each sampling period T1 within the preliminary measurement period T2. Ask. Then, the determination means 72 uses the sum of the squared deviations Pv (j) of the pressure data P (i) of the plurality of preliminary measurement periods T2 within the measurement period T3 to use the standard deviation Pd for the pressure data P (i). And the standard deviation Sd for the flow rate data S (i) is obtained using the sum of the squared deviations Sv (j) of the flow rate data S (i) for the plurality of preliminary measurement periods T2 within the measurement period T3.

  Thus, even when there is an active change X2 in the pressure and flow rate of the water vapor S in the steam bypass system 6, the steam leak detection device 7 is standard for each of the pressure data P (i) and the flow rate data S (i). The deviations Pd and Sd can be obtained with high accuracy. The effect of the active change X2 is suppressed from being reflected in the ratio Sd / Pd between the standard deviation Pd for the pressure data P (i) and the standard deviation Sd for the flow rate data S (i). Can do.

  When the water vapor S leaks in the steam bypass system 6, the standard deviation Sd of the flow rate data S (i) is larger than the standard deviation Pd of the pressure data P (i). At this time, the determination means 72 determines that the diagnostic index (Sd / Pd), which is the ratio of the standard deviation Pd for the pressure data P (i) and the standard deviation Sd for the flow rate data S (i), is an abnormality determination value (A ) Continuously exceeding N times, it is possible to detect that the leakage of the steam S has occurred in the steam bypass system 6.

  In the steam leak detection device 7 of this example, the presence or absence of leakage of the steam S in the steam bypass system 6 is detected based on the standard deviations Pd and Sd for the pressure data P (i) and the flow rate data S (i). By doing so, the presence or absence of this leakage can be detected at an early stage. Thereby, the steam injection type gas turbine 1 is not operated in a situation where the leakage of the steam S occurs and the energy efficiency is poor, and the energy efficiency of the steam injection type gas turbine 1 can be improved.

  As described above, according to the steam leak detection device 7 of the present example, the presence or absence of leakage of the steam S in the steam bypass system 6 for supplying the steam S to the combustor 3 in the steam injection gas turbine 1 is detected at an early stage. can do.

  Further, in this example, as shown in FIG. 4, a predetermined measurement period T3 for obtaining the standard deviation Pd based on the pressure data P (i) and the standard deviation Sd based on the flow rate data S (i), and the leakage of the water vapor S The determination period T4 for determining the presence or absence is the same. And the steam leak detection apparatus 7 calculated | required each standard deviation Pd and Sd for every predetermined | prescribed measurement period T3, and determined the presence or absence of leak for every this measurement period T3.

  On the other hand, as shown in FIG. 5, the predetermined determination period T4 can be a period shorter than the predetermined measurement period T3. In this case, the steam leak detection device 7 determines each standard deviation Pd in the measurement period T3 that goes back a period longer than the determination period T4 for each predetermined determination period T4 (for each determination time point for determining whether there is leakage). , Sd can be used to determine whether water vapor S has leaked. In this case, this detection can be performed more rapidly while maintaining the detection accuracy of the presence or absence of leakage.

FIG. 6 is a graph showing an example in which the presence or absence of leakage of water vapor S generated in the steam bypass system 6 of the steam injection gas turbine 1 is detected using the steam leak detection device 7 of this example. In this figure, the horizontal axis indicates the day (date), and the vertical axis indicates the diagnostic index (Sd / Pd). When the steam injection gas turbine 1 is operating normally (when no steam leaks), The actual measurement results are shown for when the steam leaks and when it is normal (when the steam leak is detected and the location where the steam leak occurs is repaired).
From this figure, it can be seen that when the leakage of water vapor S occurs in the steam bypass system 6, the diagnostic index (Sd / Pd) increases and the occurrence of this leakage can be detected early.

The block diagram which shows the steam injection type gas turbine which detects the presence or absence of a steam leak with the steam leak detection apparatus in an Example. The flowchart which shows the operation | movement which detects the presence or absence of a steam leak by the steam leak detection apparatus in an Example. The graph which shows time in the Example, taking time on a horizontal axis and taking the flow volume of the water vapor | steam in a steam bypass system on a vertical axis | shaft, between both operation | movement of a steam injection type gas turbine. Explanatory drawing which shows the determination flow at the time of making the measurement period which calculates | requires a standard deviation, and the determination period which determines the presence or absence of the leakage of water vapor | steam in the Example into the same. Explanatory drawing which shows the determination flow at the time of making the determination period which determines the presence or absence of the leakage of water vapor | steam in an Example shorter than the measurement period which calculates | requires a standard deviation. The graph which shows the change of the diagnostic parameter | index during a driving | operation of a steam-injection type gas turbine by taking a day on a horizontal axis and taking a diagnostic parameter | index on a vertical axis | shaft in an Example.

Explanation of symbols

DESCRIPTION OF SYMBOLS 1 Steam injection type gas turbine 2 Gas turbine 21 Turbine wheel 22 Compressor wheel 25 Generator 3 Combustor 31 Fuel supply system 4 Exhaust gas steam boiler 41 Exhaust gas boiler 42 Steam drum 43 Economizer (water supply system)
DESCRIPTION OF SYMBOLS 5 Steam supply system 51 Process steam control valve 6 Steam bypass system 61 Injection steam pressure gauge 62 Injection steam flow meter 63 Injection steam control valve 7 Steam leak detection apparatus 71 Reading means 72 Determination means F Fuel gas G1 Combustion gas G2 Exhaust gas A1 Air A2 Compressed air W1 Water supply W2 Preheat water supply S Steam T1 Sampling period T2 Preliminary measurement period T3 Measurement period P (i) Pressure data S (i) Flow rate data Pv (j), Sv (j) Sum of squares of deviation Pd, Sd Standard deviation Sd / Pd ratio (diagnostic indicator)

Claims (2)

A gas turbine in which a turbine wheel and a compressor wheel are arranged on the same axis;
A combustor that performs combustion using fuel gas received from a fuel supply system and compressed air sucked and compressed by the compressor wheel;
A generator for generating electric power by receiving rotation of the turbine wheel rotated by combustion gas from the combustor;
An exhaust gas steam boiler that generates water vapor from feed water received from the feed water system and exhaust gas received from the turbine wheel;
A steam supply system for supplying steam generated in the exhaust gas steam boiler to the outside as process steam;
A process steam control valve disposed in the steam supply system for adjusting the pressure of steam generated in the exhaust gas steam boiler;
A steam bypass system for connecting the upstream position of the process steam control valve in the steam supply system and the combustor, and supplying a part of the steam in the steam supply system to the combustor;
An injection steam pressure gauge that is disposed in the steam bypass system or the steam supply system and measures the pressure of water vapor generated in the exhaust gas steam boiler;
An injection steam flow meter which is disposed in the steam bypass system and measures the flow rate of water vapor passing through the steam bypass system;
In the steam injection type gas turbine provided in the steam bypass system and provided with an injection steam control valve for adjusting the flow rate of the steam to be injected into the combustor, whether or not steam leaks in the steam bypass system. A steam leak detection device capable of detecting
The steam leak detection device sequentially reads the measurement value by the jet steam pressure gauge as pressure data, and the reading means for sequentially reading the measurement value by the jet steam flow meter as flow data,
A standard deviation or variance value is obtained for each of the plurality of pressure data and the plurality of flow rate data sequentially read within a predetermined measurement period, and a standard deviation or variance value for the pressure data and a standard for the flow rate data are obtained. A determination means for detecting the occurrence of water vapor leakage in the steam bypass system when the ratio with the deviation or the variance value has deviated from the predetermined normal range once or more than once. A steam leakage detection device for a steam injection type gas turbine.   2. The determination means according to claim 1, wherein the determination unit is configured to calculate a square of deviation for each of the plurality of pressure data and the plurality of flow rate data sequentially read in the preliminary measurement period for each predetermined preliminary measurement period shorter than the measurement period. In addition to obtaining the sum, the standard deviation or the variance value is obtained for each of the pressure data and the flow rate data by using a sum of squares of deviations of the plurality of preliminary measurement periods in the measurement period. A steam leakage detection device for a steam injection type gas turbine.

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