Temperature monitoring system for stator and temperature measurement and calculation method for stator

Abstract

A temperature monitoring system for a stator. The temperature monitoring system comprises: a plurality of monitoring areas (1-X), which correspond to different structures of a stator; a plurality of optical-fiber temperature measurement points (11-1A, 21-2B, X1-XC), which are distributed within the plurality of monitoring areas; and N demodulators (i1-iN), wherein N is an integer greater than or equal to two, and each demodulator is connected to at least one optical-fiber temperature measurement point within each monitoring area. Further disclosed is a temperature measurement and calculation method for a stator. The temperature measurement and calculation method comprises: determining a first correlation model between a monitored temperature of a faulty measurement point and operating conditions, and then determining a roughly-calculated temperature value of the faulty measurement point on the basis of an operating condition at the current moment; determining a second correlation model between a monitored temperature of a neighboring measurement point and the operating conditions; then determining a roughly-calculated temperature value of the neighboring measurement point; determining a wear coefficient between the roughly-calculated temperature value and an actual temperature value of the neighboring measurement point; and on the basis of the wear coefficient, determining a measured and calculated temperature value of the faulty measurement point at the current moment. The stability and reliability of the temperature monitoring system are improved.

Description

Temperature monitoring system and temperature measurement method for stator Technical Field

[0001] The present application relates to the technical field of generator monitoring, and in particular to a temperature monitoring system and a temperature measurement method for a stator. Background Art

[0002] The operating temperature of the stator-related areas of a hydro-turbine generator is an important indicator for evaluating the operating status of the hydro-turbine generator. Accurately and reliably obtaining the stator area temperature and accurately evaluating the stator area temperature monitoring data are very important for the safe and stable operation of the unit.

[0003] Currently, platinum resistance temperature detectors (RTDs) are widely recognized and adopted within the industry for online temperature monitoring of stator winding slots in hydro-turbine generator stators. For a long time, damage to stator RTDs has been a relatively common fault type during the operation of hydro-turbine generator sets. Differences in the manufacturing process and installation quality control of different mainstream brands of RTDs have led to variations in post-operation failure patterns (such as the time between the initial failure and the commissioning of the unit, and the ratio of resistance failures to the total number of RTDs in the unit). Overall, for the operation and maintenance of hydropower station generators, the various types of stator RTDs currently in common use exhibit poor long-term reliability and a high failure rate.

[0004] Currently, there are a few cases of using fiber-optic temperature measurement technology for measuring stator temperature in hydro-turbine generators. However, due to concerns about the reliability of the technology, most of these applications are localized. When fiber-optic temperature measurement is adopted on a large scale, ensuring the stability and reliability of existing systems while applying the new technology remains a significant challenge, yet a solution remains unresolved.

[0005] Summary of the Invention

[0006] The main purpose of the present invention is to propose a temperature monitoring system and a temperature measurement method for a stator, aiming to solve the above-mentioned problems existing in the prior art.

[0007] To achieve the above object, the present invention provides a temperature monitoring system for a stator, characterized in that the temperature monitoring system comprises:

[0008] Multiple monitoring areas corresponding to different stator structures;

[0009] Multiple fiber optic temperature measurement points are distributed in multiple monitoring areas;

[0010] N demodulators, where N is an integer greater than or equal to 2;

[0011] Each demodulator is connected to at least one optical fiber temperature measuring point in each monitoring area.

[0012] In some embodiments,

[0013] Each monitoring area has M sub-areas, where M is an integer greater than or equal to 1;

[0014] Different sub-areas within the same monitoring area have different axial heights in the stator;

[0015] Each demodulator is connected to at least one optical fiber temperature measuring point in each sub-area of ​​each monitoring area.

[0016] In some embodiments,

[0017] Multiple monitoring areas include the stator winding area, the core area, the slip ring area, and the core pressure finger area.

[0018] In some embodiments,

[0019] The stator winding region includes three sub-regions: an upper interlayer sub-region, a middle interlayer sub-region, and a lower interlayer sub-region; and / or

[0020] The core region includes three sub-regions: an upper core sub-region, a middle core sub-region, and a lower core sub-region; and / or

[0021] The core pressure finger area includes two sub-areas: the upper pressure finger sub-area and the lower pressure finger sub-area.

[0022] In some embodiments,

[0023] The stator winding area is provided with n1 optical fiber temperature measuring points, n1 = 3*a*k1, where a is the number of parallel branches of the stator winding, k1 is the number of optical fiber temperature measuring points on each branch of each phase, and the number of optical fiber temperature measuring points in each sub-area is n1 / 3; and / or

[0024] The core area is provided with n2 optical fiber temperature measuring points, n2=Z*k2, where Z is the number of slots in the stator core, k2 is the temperature measuring point coefficient of the core area, and the number of optical fiber temperature measuring points in each sub-area is n2 / 3; and / or

[0025] The slip ring area is provided with n3 optical fiber temperature measuring points, where n3 = 3*a*k3, where a is the number of parallel branches of the stator winding and k3 is the number of measuring points on each branch of each phase; and / or

[0026] The core pressure finger area is provided with n4 optical fiber temperature measuring points, n4=2*k4, wherein k4 is the measuring point coefficient of the core pressure finger area, and the number of optical fiber temperature measuring points in each sub-area is n4 / 2.

[0027] In some embodiments,

[0028] In each sub-area of ​​each monitoring area, any two circumferentially adjacent optical fiber temperature measuring points are connected to two different demodulators.

[0029] In some embodiments,

[0030] The value of k1 is 3, 4, 5, 6; and / or

[0031] The value of k2 is 0.07-0.09; and / or

[0032] The value of k3 is 1 or 2; and / or

[0033] The values ​​of k4 are 5, 6, 7, and 8.

[0034] In addition, to achieve the above-mentioned purpose, the present invention further proposes a temperature measurement method, characterized in that it is applied to the temperature monitoring system for a stator of any of the above-mentioned embodiments to measure the temperature value of a fault measurement point;

[0035] Methods include:

[0036] Determine a first correlation model between the monitored temperature and the working condition of the fault measuring point based on historical data of the fault measuring point;

[0037] Determine a rough temperature value T0(t1) of the fault measuring point at the current time t1 based on the first correlation model and the working condition at the current time t1;

[0038] Determine the adjacent measuring points based on the location of the fault measuring point;

[0039] Determine a second correlation model between the monitored temperature and the working condition of the adjacent measuring points based on historical data of the adjacent measuring points;

[0040] Based on the second correlation model, determine the rough temperature value T1(t1) of the adjacent measuring point at the current time t1;

[0041] Determine the wear coefficient k5 of the adjacent measuring point = T1'(t1) / T1(t1), where T1'(t1) is the measured temperature value of the adjacent measuring point at the current time t1;

[0042] Determine the temperature measurement value T0'(t1)=k5*T0(t1) of the fault measurement point at the current moment.

[0043] In some embodiments,

[0044] The operating conditions include the unit's speed, excitation current, excitation voltage, stator current, average cold air temperature of the air cooler, and average hot air temperature of the air cooler.

[0045] In some embodiments,

[0046] Based on the location of the fault measuring point, determine the adjacent measuring points including:

[0047] In the same sub-area, the optical fiber temperature measurement point that is closest to the fault measurement point and has no fault is determined as the adjacent measurement point.

[0048] The temperature monitoring system proposed in this application is used to monitor the temperature of a generator stator. Because a large number of structures in a generator stator require temperature monitoring, the temperature monitoring system employs a one-to-many connection between the demodulator and the fiber-optic temperature measurement points. A single demodulator can demodulate temperature signals collected by multiple fiber-optic temperature measurement points, thereby reducing the number of demodulators and the size of the temperature monitoring system.

[0049] In addition, the temperature monitoring system is equipped with optical fiber temperature measurement points at multiple locations on each structure to be monitored, thereby obtaining more accurate and comprehensive temperature information of the corresponding structure to be monitored.

[0050] Each demodulator is connected to fiber optic temperature measurement points in all monitoring areas. Therefore, even if some demodulators fail to work, the temperature monitoring system can still obtain partial temperature information of each component to be monitored.

[0051] The temperature measurement method proposed in this application is used in the aforementioned temperature monitoring system. A first correlation model is established using the historical operating conditions and temperatures of the faulty measuring point. Based on this first correlation model, actual operating parameters are used to obtain a rough temperature estimate for the faulty measuring point. The rough temperature estimates of adjacent measuring points and the measured temperature values ​​are then used to determine a wear coefficient. The rough temperature estimate of the faulty measuring point is then corrected using the wear coefficient, ultimately yielding a relatively accurate temperature estimate for the faulty measuring point. Therefore, even if some optical fiber temperature measuring points and / or the demodulator fail, the temperature measurement method of this application can still provide relatively accurate temperature values ​​for each stator structure. BRIEF DESCRIPTION OF THE DRAWINGS

[0052] In order to more clearly illustrate the technical solutions of the embodiments of the present application, the following is a brief introduction to the drawings required for use in the embodiments. It should be understood that the following drawings only show certain embodiments of the present application and therefore should not be regarded as limiting the scope. For ordinary technicians in this field, other relevant drawings can be obtained based on these drawings without creative work.

[0053] The methods, systems, and / or programs in the accompanying drawings will be further described according to exemplary embodiments. These exemplary embodiments will be described in detail with reference to the drawings. These exemplary embodiments are non-limiting exemplary embodiments, wherein reference numerals represent similar structures in the various views of the drawings.

[0054] FIG1 is a schematic structural diagram of a temperature monitoring system involved in some embodiments of the present application;

[0055] FIG2 is a flow chart of a temperature measurement method according to some embodiments of the present application. DETAILED DESCRIPTION

[0056] To make the objectives, technical solutions, and advantages of the embodiments of the present application more clear, the technical solutions in the embodiments of the present application will be clearly and completely described below in conjunction with the accompanying drawings of the embodiments of the present application. Obviously, the described embodiments are only part of the embodiments of the present application, not all of the embodiments. Generally, the components of the embodiments of the present application described and shown in the drawings herein can be arranged and designed in various different configurations.

[0057] Therefore, the following detailed description of the embodiments of the present application provided in the accompanying drawings is not intended to limit the scope of the present application for protection, but merely represents selected embodiments of the present application. All other embodiments obtained by persons of ordinary skill in the art based on the embodiments in the present application without making any creative efforts shall fall within the scope of protection of the present application.

[0058] It should be noted that similar reference numerals and letters denote similar items in the following drawings, and therefore, once an item is defined in one drawing, it does not need to be further defined or explained in subsequent drawings.

[0059] In the description of this application, it should be noted that if the terms "center", "upper", "lower", "left", "right", "vertical", "horizontal", "inner", "outer", etc. appear, the orientation or position relationship indicated is based on the orientation or position relationship shown in the accompanying drawings, or the orientation or position relationship in which the product of the application is usually placed when in use. It is only for the convenience of describing this application and simplifying the description, and does not indicate or imply that the device or element referred to must have a specific orientation, be constructed and operate in a specific orientation. Therefore, it cannot be understood as a limitation on this application. In addition, if the terms "first", "second", etc. appear in the description of this application, they are only used to distinguish the description and cannot be understood as indicating or implying relative importance.

[0060] Furthermore, the use of terms such as "horizontal" and "vertical" in the description of this application does not necessarily imply that a component must be absolutely horizontal or suspended, but rather that it can be slightly tilted. For example, "horizontal" simply means that its direction is more horizontal than "vertical" and does not mean that the structure must be completely horizontal, but rather that it can be slightly tilted.

[0061] It should also be noted that, unless otherwise expressly specified or limited, the terms "disposed," "installed," "connected," and "connected" should be understood broadly. For example, they may refer to fixed connections, detachable connections, or integral connections; mechanical connections or electrical connections; direct connections or indirect connections through an intermediate medium; and internal connections between two components. A person of ordinary skill in the art will understand the specific meanings of the above terms in this application based on the specific circumstances.

[0062] Example

[0063] The temperature monitoring system in the embodiment of the present application can be used to monitor the temperature of the generator stator. The temperature monitoring system in the embodiment of the present application includes multiple monitoring areas, multiple optical fiber temperature measurement points, and N demodulators, where N is an integer greater than or equal to 2.

[0064] In this embodiment, the monitoring area, as the placement area of ​​the optical fiber temperature measuring points, may not have a physical structure, but rather be a spatial area within or around different structures of the stator. The monitoring area corresponds to different structures of the stator, and the optical fiber temperature measuring points are distributed within the monitoring area to collect temperature data of the corresponding stator structure. The stator structures whose temperatures need to be collected include the stator winding, the iron core, the slip ring, and the iron core pressure finger, and the corresponding monitoring areas are the stator winding area, the iron core area, the slip ring area, and the iron core pressure finger area. Optionally, the stator winding area can be the area between the upper and lower layers of the stator winding slot; the iron core area can be the back area of ​​the stator iron core, that is, the outer surface area of ​​the column formed by the stator iron core; the slip ring area can be the area at the stator winding slip copper ring joint; the iron core pressure finger area can be the area on the side of the upper and lower layers of the stator iron core.

[0065] Fiber optic temperature measurement points include fiber optic temperature sensors (including but not limited to fiber optic temperature measurement technologies based on different technical principles such as fiber Bragg grating temperature measurement, fluorescence fiber optic temperature measurement, and semiconductor (gallium arsenide) fiber optic temperature measurement). Fiber optic temperature sensors are installed within the monitoring area and connected to the demodulator via optical fiber.

[0066] Each demodulator is connected to at least one fiber optic temperature measurement point in each monitoring area. For example, please refer to FIG1 , which is a schematic diagram of the structure of a temperature monitoring system. The temperature monitoring system in FIG1 includes multiple monitoring areas 1-X, multiple fiber optic temperature measurement points 11-1A, 21-2B, X1-XC, and N demodulators i1-iN. Demodulator i1 is connected to fiber optic temperature measurement point 11 in monitoring area 1, fiber optic temperature measurement point 21 in monitoring area 2, ..., and fiber optic temperature measurement point X1 in monitoring area X; demodulator i2 is connected to fiber optic temperature measurement point 12 in monitoring area 1, fiber optic temperature measurement point 22 in monitoring area 2, ..., and fiber optic temperature measurement point X2 in monitoring area X; ...; demodulator iN is connected to fiber optic temperature measurement point 1N in monitoring area 1, fiber optic temperature measurement point 2N in monitoring area 2, ..., and fiber optic temperature measurement point XN in monitoring area X. It is easy to understand that the number A of optical fiber temperature measurement points in monitoring area 1, the number B of optical fiber temperature measurement points in monitoring area 2, and the number C of optical fiber temperature measurement points in monitoring area X all need to be greater than or equal to the number N of demodulators.

[0067] In the temperature monitoring system of this embodiment, N or more optical fiber temperature measurement points are arranged in each monitoring area, so that more accurate and comprehensive temperature information of the corresponding monitored structure can be obtained. In addition, each demodulator is connected to the optical fiber temperature measurement points in all monitoring areas. Therefore, even if some demodulators malfunction and cannot work, the temperature monitoring system can still obtain partial temperature information of each monitored component.

[0068] Furthermore, in the temperature monitoring system of this embodiment, each monitoring area is provided with M sub-areas, where M is an integer greater than or equal to 1, wherein the monitoring area along the axial height change of the stator is divided into multiple sub-areas (i.e., M≥2), and the monitoring area where the axial height of the stator remains unchanged is one sub-area (i.e., M=1). Fiber optic temperature measuring points are arranged in each sub-area within the same monitoring area, and the temperature values ​​collected in these sub-areas can more comprehensively reflect the temperature distribution of the corresponding stator structure after being aggregated. Specifically, the sub-areas within the monitoring area are divided according to the axial height of the stator, and different sub-areas within the same monitoring area have different axial heights in the stator, and all fiber optic temperature measuring points within the same sub-area have the same axial height. Each demodulator is connected to at least one fiber optic temperature measuring point in each sub-area of ​​each monitoring area.

[0069] It should be noted that due to the limitations of the heat dissipation structure and the stator structure, the heat dissipation conditions vary across the stator. This manifests itself as different temperatures at different axial heights within the same stator structure, leading to different temperatures detected at different axial heights within the same monitoring area. It is understandable that for a monitoring area that varies along the stator's axial height, if all fiber optic temperature measurement points within that monitoring area are concentrated at the same axial height, such as if all fiber optic temperature measurement points on the back of the stator core are concentrated at one end of the back of the stator core, the monitored temperature cannot effectively represent the temperature of the corresponding stator structure. This embodiment solves the above problem by dividing the monitoring area into M sub-areas according to axial height.

[0070] Optionally, the stator winding area is divided into three sub-areas: an upper interlayer sub-area, a middle interlayer sub-area, and a lower interlayer sub-area. Specifically, the stator winding area is provided with n1 optical fiber temperature measurement points, where n1 = 3*a*k1. Here, 3 represents the number of phases of the stator winding. a represents the number of parallel branches of the stator winding. It is understood that to withstand large currents, each phase of the stator winding may include multiple parallel conductors, which are parallel branches. k1 represents the number of optical fiber temperature measurement points on each branch of each phase. Preferably, k1 is 3, 4, 5, or 6. Preferably, the number of optical fiber temperature measurement points in the upper interlayer sub-area, the middle interlayer sub-area, and the lower interlayer sub-area is the same, that is, the number of optical fiber temperature measurement points in each sub-area is n1 / 3. It is understood that to ensure that each demodulator is connected to at least one optical fiber temperature measurement point in each sub-area of ​​the stator winding area, n1 / 3 ≥ N.

[0071] Optionally, the core region is divided into three sub-regions: an upper core sub-region, a middle core sub-region, and a lower core sub-region. Specifically, the core region is provided with n2 optical fiber temperature measurement points, where n2 = Z*k2. Where Z is the number of slots in the stator core. k2 is the temperature measurement point coefficient of the core region. Preferably, the value of k2 is 0.07-0.09. Preferably, the number of optical fiber temperature measurement points in the upper core sub-region, the middle core sub-region, and the lower core sub-region is the same, that is, the number of optical fiber temperature measurement points in each sub-region is n2 / 3. It should be noted that when n2 is not a multiple of 3, the number of optical fiber temperature measurement points in each sub-region can be rounded down or up from n2 / 3. Here, "the same number" can mean that the difference between any two of the three numbers is less than or equal to 1. For example, when n2 is 20, the number of optical fiber temperature measurement points in one sub-region is rounded down to 6, and the number of optical fiber temperature measurement points in the other two sub-regions is 7. It can be understood that in order to satisfy the requirement that each demodulator is connected to at least one optical fiber temperature measurement point in each sub-region of the core region, n2 / 3≥N.

[0072] Optionally, for the slip ring area, it can be assumed that its axial height is basically the same, so its sub-area is the entire area of ​​the slip ring area and no further division is required. Specifically, the slip ring area is provided with n3 optical fiber temperature measurement points, n3 = 3*a*k3. Among them, 3 represents the number of phases of the stator winding. a is the number of parallel branches of the stator winding. k3 is the number of measurement points on each branch of each phase. Preferably, the value of k3 is 1 or 2. It can be understood that in order to meet the requirement that each demodulator is connected to at least one optical fiber temperature measurement point in the slip ring area, n3 ≥ N.

[0073] Optionally, the core pressure finger area is divided into two sub-areas: an upper pressure finger sub-area and a lower pressure finger sub-area. Specifically, the core pressure finger area is provided with n4 optical fiber temperature measuring points, n4=2*k4. Wherein, k4 is the measuring point coefficient of the core pressure finger area, and preferably, the value of k4 is 5, 6, 7, or 8. Preferably, the number of optical fiber temperature measuring points in the upper pressure finger sub-area and the lower pressure finger sub-area is the same, that is, the number of optical fiber temperature measuring points in each sub-area is n4 / 2. It can be understood that in order to satisfy that each demodulator is connected to at least one optical fiber temperature measuring point in each sub-area of ​​the core pressure finger area, n4 / 2≥N.

[0074] Some embodiments of the present application also relate to a temperature measurement method. This temperature measurement method is applied to the temperature monitoring system of the aforementioned embodiments to measure the temperature value of a faulty measurement point. It should be noted that a faulty measurement point in the present application indicates that a temperature value cannot be obtained from the measurement point. In other words, the faulty measurement point may be a fault in the optical fiber temperature measurement point itself or a fault in the demodulator connected to the optical fiber temperature measurement point.

[0075] Please refer to Figure 2, which is a flow chart of a temperature measurement method according to an embodiment of the present application. The temperature measurement method includes steps S100-S700.

[0076] Step S100 : determining a first correlation model between the monitored temperature and the working condition of the fault measuring point based on historical data of the fault measuring point.

[0077] In this embodiment, the historical data at the fault measurement point includes historical temperature data and historical operating condition data. The historical temperature data can be the actual temperature value monitored at the optical fiber temperature measurement point before the fault, or it can be the actual temperature value monitored before the fault by other means. The historical operating condition data refers to the operating conditions of the generator set where the stator is located, including but not limited to the speed, excitation current, excitation voltage, stator current, average air cooler cold air temperature, average air cooler hot air temperature, and other operating condition data.

[0078] Optionally, this embodiment can establish a mathematical model by means of an empirical regression equation, and correct the mathematical model by means of a regression algorithm, and finally obtain a first correlation model f0 between the monitored temperature of the fault measuring point and the working condition. The relationship between the historical monitored temperature T0 and the first correlation model f0 is as follows: T0(t0)=f0[n(t),I f (t),U f (t),I(t),T c (t),T h (t)]| t＝t0

[0079] Among them, T0(t0) is the historical monitoring temperature of the fault measurement point at the historical time t0, n(t) is the unit speed at time t, I f (t) is the excitation current of the unit at time t, U f (t) is the excitation voltage of the group at time t, I(t) is the stator current of the group at time t, T c (t) is the average cold air temperature of the air cooler of the unit at time t, T h (t) is the average hot air temperature of the air cooler of the unit at time t, f0[]| t＝t0 This represents the conversion of historical operating condition data at time t0 into historical monitoring temperature T0 using the first correlation model f0. It can be understood that the excitation parameters (excitation current and voltage) are related to the core iron loss, while the stator current is related to the copper loss of the stator bar. Both of these components are related to heat generation. The average hot air temperature and the average cold air temperature of the air cooler are related to heat dissipation. Therefore, these parameters all affect the monitoring temperature.

[0080] Optionally, this embodiment can also use deep learning to establish a first correlation model f0 between the monitored temperature and operating conditions at the fault measurement point. Specifically, a neural network model can be established to divide the historical temperature data and corresponding historical operating condition data at different times into a training set, a validation set, and a test set. The final first correlation model f0 is obtained through training.

[0081] Step S200 : determining a rough temperature value T0 ( t1 ) of the fault measuring point at the current time t1 based on the first correlation model and the working condition at the current time t1 .

[0082] In this embodiment, the working condition at the current time t1 can be brought into the first correlation model f0 to obtain the rough temperature value T0(t1) of the fault measurement point at the current time t1: T0(t1)=f0[n(t),I f (t),U f (t),I(t),T c (t),T h (t)]| t＝t1 .

[0083] Step S300: Determine adjacent measuring points based on the location of the fault measuring point.

[0084] Specifically, in the same sub-area, the optical fiber temperature measurement point that is closest to the fault measurement point and has no fault may be determined as the adjacent measurement point.

[0085] Step S400 : determining a second correlation model between the monitored temperature and the working condition of the adjacent measuring point based on historical data of the adjacent measuring point.

[0086] Step S500 : determining a rough temperature value T1 ( t1 ) of a neighboring measuring point at the current time t1 based on the second correlation model.

[0087] In this embodiment, the historical data of the adjacent measuring points include historical temperature data and historical operating condition data. Among them, the historical temperature data can be the actual temperature value monitored by the adjacent measuring point before the fault occurs at the fault measuring point, or it can be the actual temperature value monitored by other means before the fault occurs at the fault measuring point. The historical operating condition data is the operating condition of the generator set where the stator is located, including but not limited to the speed of the set, excitation current, excitation voltage, stator current, average temperature of cold air of the air cooler, average temperature of hot air of the air cooler and other operating condition data. Specifically, a method similar to the first correlation model f0 can be used, such as an empirical formula or deep learning method to establish the second correlation model f1. For example, the second correlation model f1 is established by an empirical formula, and the relationship between the historical monitoring temperature T1 of the adjacent measuring point and the second correlation model f1 is obtained as follows: T1(t0)=f1[n(t),I f (t),U f (t),I(t),T c (t),T h (t)]| t＝t0

[0088] Among them, T1(t0) is the historical monitoring temperature of the adjacent measuring point at the historical time t0, f1[]| t＝t0 It indicates that the historical operating condition data at the historical time t0 is converted into the historical monitoring temperature T1 by using the second correlation model f1.

[0089] Substitute the working condition at the current time t1 into the second correlation model f1 to obtain the rough temperature value T1(t1) of the adjacent measuring point at the current time t1: T1(t1)=f1[n(t),I f (t),U f (t),I(t),T c (t),T h (t)]| t＝t1 .

[0090] Step S600 , determining the wear coefficient k5 of the adjacent measuring point=T1′(t1) / T1(t1), wherein T1′(t1) is the actual temperature value of the adjacent measuring point at the current time t1.

[0091] Step S700: Determine the temperature measurement value T0'(t1)=k5*T0(t1) of the fault measurement point at the current moment.

[0092] In this embodiment, the wear coefficient k5 can represent the degree of deviation between the rough temperature estimate obtained by the second correlation model f1 and the actual measured temperature value. It is understood that the electrical parameters of different phases of the same generator set vary slightly, and different measuring points within the same subregion are located at the same axial height relative to the stator, resulting in similar heat dissipation conditions. Therefore, the wear coefficients of two adjacent measuring points (i.e., the degree of deviation between the rough temperature estimate and the actual temperature value) are relatively consistent. Using the wear coefficients of adjacent measuring points to correct the rough temperature estimate of the faulty measuring point can ultimately yield a more accurate temperature estimate for the faulty measuring point.

[0093] It should be noted that in the temperature measurement method of this embodiment, step numbers S100-S700 do not represent the order in which the method is executed. As long as the method can successfully obtain the temperature measurement value T0'(t1), some steps can be swapped or performed simultaneously. For example, step S100 and step S300 can be swapped or performed simultaneously, and so on. This will not be repeated here.

[0094] By using the temperature measurement method of this embodiment, even if some optical fiber temperature measurement points fail, relatively accurate temperature values ​​of various stator structures can still be obtained.

[0095] Furthermore, in the temperature monitoring system of some embodiments, in each sub-region of each monitoring region, any two circumferentially adjacent optical fiber temperature measurement points are connected to two different demodulators. Taking the upper interlayer sub-region of the stator winding region with 9 optical fiber temperature measurement points and 3 demodulators as an example: the 9 measurement points are evenly distributed along the circumference, in the order of C1, C2, C3, ..., C9, C9 and C1 are adjacent; the 3 demodulators are i1, i2, and i3; as an optional connection method, demodulator i1 is connected to optical fiber temperature measurement points C1, C4, and C7, demodulator i2 is connected to optical fiber temperature measurement points C2, C5, and C8, and demodulator i3 is connected to optical fiber temperature measurement points C3, C6, and C9, so that any two circumferentially adjacent optical fiber temperature measurement points are connected to two different demodulators. In this temperature monitoring system, even if any demodulator fails, the optical fiber temperature measurement point closest to the faulty measurement point below the demodulator will be determined as a neighboring measurement point because there is no fault, thereby ensuring that the wear coefficient k5 obtained by the aforementioned temperature measurement method can be closer to the degree of deviation between the rough temperature value of the faulty measurement point and the actual temperature value, thereby obtaining a more accurate temperature measurement value of the faulty measurement point.

[0096] The above description is merely a preferred embodiment of the present application and is not intended to limit the present application. Various modifications and variations are possible for those skilled in the art. Any modifications, equivalent substitutions, or improvements made within the spirit and principles of the present application shall be included within the scope of protection of the present application.

Claims

1. A temperature monitoring system for a stator, characterized in that: The temperature monitoring system comprises: A plurality of monitoring areas corresponding to different structures of the stator; A plurality of optical fiber temperature measuring points are distributed in the plurality of monitoring areas; N demodulators, where N is an integer greater than or equal to 2; Each of the demodulators is connected to at least one of the optical fiber temperature measuring points in each of the monitoring areas.

2. The temperature monitoring system for a stator according to claim 1, characterized in that: Each of the monitoring areas has M sub-areas, where M is an integer greater than or equal to 1; Different sub-areas within the same monitoring area have different axial heights in the stator; Each of the demodulators is connected to at least one of the optical fiber temperature measuring points in each sub-area of ​​each monitoring area.

3. The temperature monitoring system for a stator according to claim 2, characterized in that: The multiple monitoring areas include a stator winding area, an iron core area, a slip ring area, and an iron core pressure finger area.

4. The temperature monitoring system for a stator according to claim 3, characterized in that: The stator winding region includes three sub-regions: an interlayer upper sub-region, an interlayer middle sub-region, and an interlayer lower sub-region; and / or The core region includes three sub-regions: an upper core sub-region, a middle core sub-region, and a lower core sub-region; and / or The core finger pressing area includes two sub-areas: an upper finger pressing sub-area and a lower finger pressing sub-area.

5. The temperature monitoring system for a stator according to claim 4, characterized in that: The stator winding area is provided with n1 optical fiber temperature measuring points, n1=3*a*k1, wherein a is the number of parallel branches of the stator winding, k1 is the number of the optical fiber temperature measuring points on each branch of each phase, and the number of the optical fiber temperature measuring points in each sub-area is n1 / 3; and / or The core region is provided with n2 optical fiber temperature measuring points, n2=Z*k2, wherein Z is the number of slots of the stator core, k2 is the temperature measuring point coefficient of the core region, and the number of the optical fiber temperature measuring points in each sub-region is n2 / 3; and / or The slip ring region is provided with n3 optical fiber temperature measuring points, n3=3*a*k3, wherein a is the number of parallel branches of the stator winding, and k3 is the number of measuring points on each branch of each phase; and / or The core pressure finger area is provided with n4 optical fiber temperature measuring points, n4=2*k4, wherein k4 is the measuring point coefficient of the core pressure finger area, and the number of the optical fiber temperature measuring points in each sub-area is n4 / 2.

6. The temperature monitoring system for a stator according to claim 5, characterized in that: In each sub-area of ​​each monitoring area, any two circumferentially adjacent optical fiber temperature measurement points are connected to two different demodulators.

7. The temperature monitoring system for a stator according to claim 5, characterized in that: The value of k1 is 3, 4, 5, 6; and / or The value of k2 is 0.07-0.09; and / or The value of k3 is 1 or 2; and / or The value of k4 is 5, 6, 7, 8.

8. A temperature measurement method, characterized in that: The method is applied in a temperature monitoring system for a stator as claimed in any one of claims 2 to 6 to calculate the temperature value of a fault measuring point; The method comprises: Determine a first correlation model between the monitored temperature and the working condition of the fault measuring point based on the historical data of the fault measuring point; Determine a rough temperature value T0(t1) of the fault measuring point at the current time t1 based on the first correlation model and the working condition at the current time t1; Based on the location of the fault measuring point, determining adjacent measuring points; Determine a second correlation model between the monitored temperature and the working condition of the adjacent measuring point based on the historical data of the adjacent measuring point; Based on the second correlation model, determine a rough temperature value T1(t1) of the adjacent measuring point at the current time t1; Determine the wear coefficient k5 of the adjacent measuring point = T1'(t1) / T1(t1), wherein T1'(t1) is the actual temperature value of the adjacent measuring point at the current time t1; Determine the temperature measurement value T0'(t1)=k5*T0(t1) of the fault measurement point at the current moment.

9. The temperature measurement method according to claim 8, characterized in that: The operating conditions include the rotation speed, excitation current, excitation voltage, stator current, average temperature of cold air of the air cooler, and average temperature of hot air of the air cooler.

10. The temperature measurement method according to claim 8, characterized in that: Based on the position of the fault measuring point, determining the adjacent measuring points includes: In the same sub-area, the optical fiber temperature measuring point which is closest to the fault measuring point and has no fault is determined as a neighboring measuring point.

Images