Estimation program, estimation device, and estimation method

Abstract

To easily detect a wind speed and a wind direction of a wind hitting an electrical power transmission line.SOLUTION: An estimation program causes a computer to execute processing of: acquiring backward Rayleigh scattered light from an optical fiber composite overhead ground wire provided in parallel to an electrical power transmission line; identifying each of spectral densities of a plurality of frequencies of vibration of the optical fiber composite overhead ground wire on the basis of the backward Rayleigh scattered light; estimating a wind speed of a wind hitting the electrical power transmission line on the basis of a first spectral density in a first frequency band including a natural frequency of the optical fiber composite overhead ground wire among the spectral densities; and estimating a wind direction of the wind on the basis of a second spectral density in a second frequency band which does not include the natural frequency of the optical fiber composite overhead ground wire among the spectral densities.SELECTED DRAWING: Figure 3

Description

[Technical Field]

[0001] The present invention relates to an estimation program, an estimation device, and an estimation method. [Background technology]

[0002] A method called dynamic line rating has been proposed, which controls the amount of power transmitted through a power line while monitoring its temperature. Dynamic line rating allows for real-time control of the amount of power transmitted, thereby achieving energy savings. The temperature of a power line depends on the speed and direction of the wind to which the power line is exposed. Therefore, to achieve dynamic line rating, it is desirable to monitor wind speed and direction in real time. To monitor wind speed and direction, for example, sensors can be installed on the power line and the sensor measurement data can be transmitted via cable. However, there is a risk that the transmission of the measurement data may be hindered by high magnetic and electric fields generated near the power line. Furthermore, because the power line itself is laid over a distance of several kilometers, a large number of sensors must be installed on the power line, which poses challenges in terms of sensor maintenance and cost. [Prior art documents] [Patent documents]

[0003] [Patent Document 1] International Publication No. WO2020 / 116032 [Patent Document 2] Japanese Patent Application Publication No. 7-140161 [Patent Document 3] Japanese Patent Application Publication No. 6-213911 [Patent Document 4] Japanese Patent Application Laid-Open No. 2003-185762 Summary of the Invention [Problem to be solved by the invention]

[0004] According to one aspect, an object is to easily detect the speed and direction of wind blowing on a power transmission line. [Means for solving the problem]

[0005] According to one aspect, there is provided an estimation program for causing a computer to execute the following processes: acquire backward Rayleigh scattered light from an optical fiber composite overhead ground wire installed parallel to a power transmission line; determine a spectral density of each of multiple frequencies of vibration of the optical fiber composite overhead ground wire based on the backward Rayleigh scattered light; estimate a wind speed of wind impinging on the power transmission line based on a first spectral density in a first frequency band that includes a natural frequency of the optical fiber composite overhead ground wire; and estimate a wind direction of the wind based on a second spectral density in a second frequency band that does not include the natural frequency of the optical fiber composite overhead ground wire. [Effects of the Invention]

[0006] According to one aspect, the wind speed and direction of wind blowing on a power transmission line can be easily detected. [Brief explanation of the drawings]

[0007] [Figure 1] Figure 1 is a schematic diagram of a power line and its surroundings. [Figure 2] FIG. 2 is a schematic diagram of the system according to this embodiment. [Figure 3] FIG. 3(a) is a schematic diagram showing the overall configuration of the estimation device, and FIG. 3(b) is a block diagram for explaining the hardware configuration of the calculation device. [Figure 4] FIG. 4 is a diagram for explaining the principle of vibration measurement. [Figure 5] FIG. 5 is a schematic diagram of the spectral density identified by the identification unit. [Figure 6] FIG. 6 is a schematic diagram showing the relationship between the wind speed of the wind hitting the OPGW and the vibration strength of the OPGW. [Figure 7] 7(a) and (b) are diagrams showing the relationship between the strain rate of the OPGW and the wind direction. [Figure 8]FIG. 8 is a schematic diagram of the vibration spectral density at a location of the OPGW used to estimate wind speed and direction. [Figure 9] FIG. 9 is a schematic diagram showing an example of the function form of the function f. [Figure 10] FIG. 10 is a schematic diagram showing a method for correcting the wind direction. [Figure 11] FIG. 11 is a schematic diagram showing a method for correcting the wind direction. [Figure 12] FIG. 12 is a schematic diagram showing a method for estimating the temperature of a power transmission line. [Figure 13] FIG. 13 is a flowchart of the estimation method according to this embodiment. [Figure 14] FIG. 14 is a schematic diagram showing an example of strain rate data. DETAILED DESCRIPTION OF THE INVENTION

[0008] Prior to describing the present embodiment, the matters considered by the inventors of the present invention will be described.

[0009] Figure 1 is a schematic diagram of a power transmission line and its surroundings. In this example, a power transmission line 2 is installed between steel towers 1, and an OPGW (Optical fiber composite overhead ground wire) 3 is installed in parallel to the power transmission line 2.

[0010] A sensor 5 for measuring wind speed and direction is installed on the power transmission line 2. The sensor 5 wirelessly transmits measurement data including the measured wind speed and direction to a data collection center 6 or the like. In addition to wind speed and direction, the sensor 5 may also measure the temperature of the power line, vibrations, etc.

[0011] Based on the wind speed and direction measured by the sensor 5 in this way, the data collection center 6 can estimate the temperature of the power transmission line 2 .

[0012] However, the sensors 5 installed on the power transmission lines 2 must be resistant to high electric fields and high magnetic fields. Furthermore, since it is difficult to supply power to the sensors 5 from the outside, a power generation mechanism is also required to supply power to the sensors 5. As a result, the types of sensors 5 that can be installed on the power transmission lines 2 are limited. Moreover, because the power transmission lines 2 are laid over distances of several kilometers, a large number of sensors must be installed on the power transmission lines, which creates issues with the maintainability and cost of the sensors.

[0013] (Present embodiment) Fig. 2 is a schematic diagram of the system according to this embodiment. In Fig. 2, the same elements as in Fig. 1 are denoted by the same reference numerals, and their description will be omitted below.

[0014] This system is a system for estimating the wind speed and direction of the wind that hits the power transmission line 2, and includes an estimation device 100.

[0015] In this example, a distributed acoustic sensor (DAS) is used as the estimation device 100. The DAS is a system that calculates vibrations caused by the expansion and contraction of the optical fiber based on the time it takes for the backscattered Rayleigh light to return after pulsed light is incident on the optical fiber of the OPGW 3, as well as the phase difference and intensity of the backscattered Rayleigh light.

[0016] Fig. 3(a) is a schematic diagram showing the overall configuration of the estimation device 100. As illustrated in Fig. 3(a), the estimation device 100 includes a measurement device 10, a calculation device 20, etc. The measurement device 10 includes a laser 11, an optical circulator 12, a detector 13, etc. The calculation device 20 includes an acquisition unit 21, a generation unit 22, an identification unit 23, a wind speed estimation unit 24, a wind direction estimation unit 25, a correction unit 26, a temperature estimation unit 27, and a storage unit 28.

[0017] FIG. 3(b) is a block diagram illustrating the hardware configuration of the arithmetic device 20. As illustrated in FIG. 3(b), the arithmetic device 20 includes a CPU (Central Processing Unit) 101, a RAM (Random Access Memory) 102, a storage device 103, an interface 104, and the like. These devices are connected via a bus or the like. The CPU 101 is a central processing unit. The CPU 101 includes one or more cores. The RAM 102 is a volatile memory that temporarily stores programs executed by the CPU 101, data processed by the CPU 101, and the like. The storage device 103 is a non-volatile storage device. The storage device 103 can be, for example, a read-only memory (ROM), a solid-state drive (SSD) such as a flash memory, or a hard disk driven by a hard disk drive. When the CPU 101 executes the estimation program stored in the storage device 103, the calculation device 20 is realized with an acquisition unit 21, a generation unit 22, an identification unit 23, a wind speed estimation unit 24, a wind direction estimation unit 25, a correction unit 26, a temperature estimation unit 27, and a storage unit 28. Each unit of the calculation device 20 may be hardware such as a dedicated circuit.

[0018] The laser 11 is a light source such as a semiconductor laser, and emits laser light within a predetermined wavelength range to the optical fiber 30 of the OPGW 3. In this embodiment, the laser 11 emits optical pulses (laser pulses) at predetermined time intervals. The optical circulator 12 guides the optical pulses emitted by the laser 11 to the optical fiber 30 whose vibration is to be measured, and guides the backscattered light returning from the optical fiber 30 to the detector 13.

[0019] The optical pulse incident on the optical fiber 30 propagates through the optical fiber 30. The optical pulse propagates through the optical fiber 30 while gradually attenuating, generating forward scattered light traveling in the propagation direction and backscattered light (return light) traveling in the return direction. The backscattered light re-enters the optical circulator 12. The backscattered light incident on the optical circulator 12 is output to the detector 13. The detector 13 is, for example, a receiver for obtaining the phase difference with the locally emitted light.

[0020] Fig. 4 is a diagram for explaining the principle of vibration measurement. As illustrated in Fig. 4, a laser pulse is incident as incident light into optical fiber 30. Among the backscattered light, coherent returning light, which is Rayleigh scattered light having the same frequency as the incident light, returns to optical circulator 12 with its phase shifted by vibration. Acquiring unit 21 acquires this coherent returning light. Based on the detection result of detector 13, generating unit 22 generates time-series data of the phase difference caused by expansion and contraction of optical fiber 30 at each sampling position (hereinafter referred to as time-series phase data).

[0021] The memory unit 28 stores the time-series phase data at each sampling position created by the generation unit 22. The sampling positions are points or sections defined at predetermined intervals in the extension direction of the optical fiber 30. For example, the sampling positions are points defined every 1.25 m in the extension direction of the optical fiber 30, or sections defined every 1.25 m and having a length of 1.25 m or less. Each phase difference in the time-series phase data may be obtained from the phase difference detected at each point, or may be obtained from the sum or average of the phase differences detected in each section. Note that if the next laser pulse is generated before the return light scattered at the end of the optical fiber 30 returns, the return light will be mixed in and accurate measurement will not be possible; therefore, the minimum period of the laser pulse is determined by the length of the optical fiber to be measured.

[0022] Vibration measurement can be performed using the time-series phase data at each sampling position. For example, the time-series phase data can be used to calculate vibration data representing the displacement per unit time of each sampling position on the optical fiber 30. This technique is known as self-interference. The physical quantity measured differs depending on whether the interfering light is locally emitted light or backscattered light. The former is a phase difference corresponding to strain, while the latter is a phase difference corresponding to strain rate obtained by taking the time difference. The generation unit 22 acquires the phase difference at the laser pulse period and converts it into time-series strain rate data corresponding to the optical fiber position. The identification unit 23 identifies the spectral density of each of the multiple frequencies of vibration of the OPGW 3 based on this time-series strain rate data.

[0023] FIG. 5 is a schematic diagram of the spectral density identified by the identification unit 23. The horizontal axis of FIG. 5 represents the vibration frequency of the OPGW 3, and the vertical axis represents the spectral density. As shown in FIG. 5, the spectral density has multiple peaks. These peaks correspond to the natural frequencies of the OPGW 3.

[0024] The natural frequency of OPGW3 changes depending on the tension of OPGW3. Therefore, if the bolts on tower 1 loosen, the tension of OPGW3 changes, and the natural frequency of OPGW3 also changes. In addition, if a part called a cleat that connects OPGW3 to tower 1 or a clamp that connects power line 2 to tower 1 loosens, the tension of OPGW3 also changes, and the natural frequency of OPGW3 also changes.

[0025] FIG. 6 is a schematic diagram showing the relationship between the wind speed of the wind blowing on the OPGW 3 and the vibration strength of the OPGW 3. In FIG.

[0026] As shown in Figure 6, there is a nonlinear relationship between wind speed and vibration intensity. This is because the vortices near the OPGW 3 change depending on the wind speed. Furthermore, when the OPGW 3 is normally vibrated, a lock-in phenomenon occurs, in which the OPGW 3 resonates near its natural frequency, but this nonlinear relationship can also be obtained when the wind speed increases and the lock-in phenomenon disappears.

[0027] 7(a) and (b) are diagrams showing the relationship between the strain rate of the OPGW 3 and the wind direction. Here, the wind direction is defined as the angle θ (0≦θ≦90°) between the extending direction A of the OPGW 3 and the wind flow direction. In addition, the magnitude of the wind speed v is the same in both Figs. 7(a) and (b).

[0028] As shown in Figures 7(a) and (b), the strain rate is highly dependent on the wind direction θ. In particular, OPGW3 vibrates most strongly when the wind direction θ is 90°, and conversely, the vibration of OPGW3 is weakest when the wind direction θ is 0°.

[0029] In Figures 7(a) and (b), the wind speed v was kept constant and the wind direction θ was changed, but conversely, if the wind direction θ was kept constant and the wind speed v was changed, the vibration strength of the OPGW3 near the natural frequency would increase. This is because there is a strong correlation between the wind speed v and the vibration strength near the natural frequency.

[0030] Using this, in this embodiment, the estimation device 100 estimates the wind speed and wind direction as follows.

[0031] FIG. 8 is a schematic diagram of the vibration spectral density at a position of the OPGW 3 used to estimate wind speed and direction.

[0032] As shown in FIG. 8, the specifying unit 23 divides this spectral density into a first frequency band 41 that includes the natural frequency of the OPGW 3 and a second frequency band 42 that does not include the natural frequency of the OPGW 3.

[0033] As described above, wind speed has a strong correlation with vibration intensity near the natural frequency of the OPGW 3. Therefore, the wind speed estimation unit 24 estimates the speed of wind blowing on the power transmission line 2 parallel to the OPGW 3 based on the spectral density in the first frequency band 41 that includes the natural frequency.

[0034] As an example, the wind speed estimation unit 24 estimates the wind speed v at the position where the spectral density in FIG. 8 is acquired based on the following equation (1). v = f(X,θ) (1) Here, f is a function determined in advance through experiments or the like. X is a first spectral density in the first frequency band 41. θ is the wind direction defined in FIGS. 7(a) and 7(b). The wind speed estimation unit 24 uses the first spectral density X at each position of the OPGW 3 to estimate the wind speed of the wind blowing on the power transmission line 2 near each position from equation (1).

[0035] Fig. 9 is a schematic diagram showing an example of the functional form of the function f. In this example, a function f is used in which the wind speed v increases linearly with respect to the first spectral density X when the wind direction θ is fixed. Also, reflecting the results of Figs. 7(a) and (b), when the wind speed v is fixed, the first spectral density X increases as the wind direction θ increases.

[0036] 7(a) and 7(b), the wind direction θ affects the strain rate and is therefore correlated with the second spectral density Y of the second frequency band 42 that does not include the natural frequency. Therefore, the wind direction estimation unit 25 estimates the wind direction θ (0≦θ≦90°) based on the following equation (2). θ=g(Y) (2) Here, g is a function determined in advance through experiments, etc. The wind direction estimation unit 25 uses the second spectral density Y at each position of the OPGW 3 to estimate the wind direction of the wind blowing on the power transmission line 2 near each position from equation (2).

[0037] 7(a) and (b), the strain rate is the same for all wind directions: θ, -θ, 90°-θ, and -90°+θ. Therefore, even if the wind direction θ is calculated using equation (2), it is not possible to determine whether the actual wind direction corresponds to θ, -θ, 90°-θ, or -90°+θ.

[0038] Therefore, in this embodiment, the wind direction θ is corrected as follows using wind direction data provided by, for example, AMeDAS (Automated Meteorological Data Acquisition System).

[0039] 10 is a schematic diagram showing a method for correcting the wind direction θ. Here, the acquisition unit 21 acquires the angle φ (0≦φ<360°) between the extension direction A and the wind direction. As an example, the acquisition unit 21 acquires AMeDAS information including the wind direction, and acquires the angle φ from that information. Note that a wind direction sensor may be provided in the OPGW 3, and the acquisition unit 21 may acquire the wind direction measured by the wind direction sensor as the angle φ.

[0040] Next, the correction unit 26 corrects the wind direction θ as follows.

[0041] a When 0°≦φ≦90° θ→θ b When 90°<φ≦180° θ→180°-θ c When 180°<φ≦270° θ→180°+θ d When 270°<φ≦360° θ→360°-θ This allows the wind direction θ, which was in the range of 0≦θ≦90° before correction, to be expanded to the range of 0≦θ<360°.

[0042] 6, there is a nonlinear relationship between the wind speed and the vibration strength of the OPGW 3. A method for correcting the wind direction θ associated with this nonlinearity will now be described.

[0043] Fig. 11 is a schematic diagram showing the correction method. When the wind speed increases, the vibration strength of the OPGW 3 also increases, and the natural frequency f n The vibration intensity in the vicinity also increases, and the vibration peak frequency f p is the natural frequency f n Matches.

[0044] However, when the wind speed becomes large enough, the lock-in phenomenon no longer occurs, and the peak frequency of the vibration f p is the natural frequency f nand the natural frequency f n The spectral density at

[0045] Therefore, when the vibration intensity decreases with an increase in wind speed in this way, the correction unit 26 corrects the first spectral density X to compensate for the decrease in vibration intensity. As an example, the correction unit 26 corrects the first spectral density X according to the following equation (3).

[0046] X → C(f p )*X···(3) In addition, C(f p ) is a predetermined correction function. p ) can be optimized through experiments. For example, the peak frequency f p and natural frequency f n The function C(f p ) is used. Furthermore, "*" is an operator indicating convolution. In this case, the wind speed estimation unit 24 estimates the wind speed v according to the following equation (4). v=f(C(f p )*X,θ) (4) Incidentally, although the wind speed and direction of the wind blowing against the power transmission line 2 can be estimated as described above, it is preferable to also estimate the temperature of the power transmission line 2 in order to realize dynamic line rating.

[0047] FIG. 12 is a schematic diagram illustrating a method for estimating the temperature of a power line. In this example, the temperature estimation unit 27 estimates the temperature of the power line 2 based on the wind speed and wind direction estimated as described above. The estimation method is not particularly limited. For example, a model for calculating the temperature of the power line 2 from the air temperature, the amount of sunlight, the wind direction, and the wind speed may be created, and the temperature estimation unit 27 may calculate the temperature of the power line 2 based on the model. In this case, the air temperature and the amount of sunlight may be measured by a sensor provided on the power line 2, and the output value of the sensor may be used. Alternatively, the air temperature and the amount of sunlight included in the AMeDAS information for the area near the power line 2 may be used. Furthermore, since the estimation device 100 using the DAS can estimate the wind direction and wind speed for each position on the power line 2, the temperature estimation unit 27 may estimate the temperature for each position on the power line 2, thereby estimating the temperature distribution along the extension direction of the power line 2.

[0048] Next, the estimation method according to this embodiment will be described with reference to the flowchart of FIG.

[0049] First, the acquisition unit 21 acquires coherent light, which is Rayleigh scattered light emitted from the optical fiber 30 (step S11).

[0050] Next, the generating unit 22 generates time-series strain rate data at each position of the optical fiber 30 based on the Rayleigh scattered light acquired by the acquiring unit 21 (step S12).

[0051] Fig. 14 is a schematic diagram showing an example of the strain rate data. As shown in Fig. 14, the strain rate data is information that associates the elapsed time from the start of measurement, the position of the optical fiber 30, and the strain rate (με / s).

[0052] Referring again to Fig. 11, the identification unit 23 then identifies the spectral density at each frequency by performing a short-time Fourier transform on the strain rate data with an arbitrary window width (step S13). The arbitrary window width is the window width for the time period for which the wind direction and wind speed are desired to be output.

[0053] Furthermore, the identifying unit 23 identifies a first spectral density X and a second spectral density Y from the spectral densities (step S14).

[0054] Next, the corrector 26 corrects the first spectral density X according to the method described with reference to FIG. 11 (step S15).

[0055] Next, the wind speed estimating unit 24 estimates the wind speed based on the first spectral density X using the above-mentioned equation (4) (step S16).

[0056] Subsequently, the wind direction estimation unit 25 estimates the wind direction based on the second spectral density Y using the above-mentioned equation (2) (step S17).

[0057] Next, the corrector 26 corrects the wind direction according to the method described with reference to FIG. 10 (step S18).

[0058] Next, the temperature estimation unit 27 estimates the temperature of the power transmission line 2 according to the method described with reference to Fig. 12 (step S19). After that, the process returns to step S11 after a certain time has elapsed. This completes the basic processing of the estimation method according to this embodiment.

[0059] According to the above-described embodiment, by using a DAS as the estimation device 100, it is possible to estimate the wind speed and direction based on the spectral densities X and Y. Therefore, it is not necessary to provide a large number of sensors for measuring the wind speed and direction on the power transmission line 2, and it is possible to easily detect the wind speed and direction of the wind blowing on the power transmission line 2. [Explanation of symbols]

[0060] 1...tower, 2...power line, 3...OPGW, 5...sensor, 6...data collection center, 10...measuring device, 11...laser, 12...optical circulator, 13...detector, 20...computing device, 21...acquisition unit, 22...generation unit, 23...identification unit, 24...wind speed estimation unit, 25...wind direction estimation unit, 26...correction unit, 27...temperature estimation unit, 28...memory unit, 30...optical fiber, 41...first frequency band, 42...second frequency band, 100...estimation device, 103...memory device, 104...interface.

Claims

1. The backscattered light is acquired from an optical fiber composite overhead ground wire installed parallel to the power transmission line, determining a spectral density of each of a plurality of frequencies of vibration of the optical fiber composite overhead ground wire based on the backscattered Rayleigh light; estimating a wind speed of wind blowing against the power transmission line based on a first spectral density in a first frequency band including a natural frequency that varies depending on the tension of the optical fiber composite overhead ground wire, among the spectral densities; estimating the wind direction based on a second spectral density in a second frequency band that does not include the natural frequency of the optical fiber composite overhead ground wire, among the spectral densities; An estimation program that causes a computer to execute the processing.

2. When the vibration intensity at the natural frequency decreases with an increase in the wind speed, the first spectral density is corrected to compensate for the decrease. The estimation program according to claim 1 , for causing the computer to execute processing.

3. In the process of estimating the wind direction, a first angle θ between a first direction and the wind direction is estimated within a range of 0≦θ≦90°; obtaining a second angle φ between the first direction and the wind direction, the second angle φ being in the range of 0≦φ<360°; correcting the first angle θ in accordance with the value of the second angle φ; The estimation program according to claim 1 , for causing the computer to execute processing.

4. When 0°≦φ≦90°, the first angle θ is not corrected, When 90°<φ≦180°, the first angle θ is corrected to 180°−θ; When 180°<φ≦270°, the first angle θ is corrected to 180°+θ; 4. The estimation program according to claim 3, wherein when 270°<φ≦360°, the first angle θ is corrected to 360°−θ.

5. The estimation program according to claim 1 , for causing the computer to execute a process of estimating the temperature of the power transmission line based on the estimated wind direction and the estimated wind speed.

6. an acquisition unit that acquires backward Rayleigh scattered light from an optical fiber composite overhead ground wire that is installed parallel to the power transmission line; a specifier for calculating the spectral density of each of a plurality of frequencies of vibration of the optical fiber composite overhead ground wire based on the backward Rayleigh scattered light; a wind speed estimation unit that estimates a wind speed of wind blowing against the power transmission line based on a first spectral density in a first frequency band that includes a natural frequency that changes in accordance with the tension of the optical fiber composite overhead ground wire, among the spectral densities; a wind direction estimation unit that estimates the wind direction based on a second spectral density in a second frequency band that does not include the natural frequency of the optical fiber composite overhead ground wire, among the spectral densities; An estimation device comprising:

7. The backscattered light is acquired from an optical fiber composite overhead ground wire installed parallel to the power transmission line, determining a spectral density of each of a plurality of frequencies of vibration of the optical fiber composite overhead ground wire based on the backscattered Rayleigh light; estimating a wind speed of wind blowing against the power transmission line based on a first spectral density in a first frequency band including a natural frequency that varies depending on the tension of the optical fiber composite overhead ground wire, among the spectral densities; estimating the wind direction based on a second spectral density in a second frequency band that does not include the natural frequency of the optical fiber composite overhead ground wire, among the spectral densities; An estimation method characterized in that the processing is executed by a computer.

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