Information transmission system and information transmission method

Abstract

To achieve appropriate communication via a power line.SOLUTION: The information transmission system includes a plurality of disturbance-incorporation control devices that are provided in a plurality of power generating facilities 122 connected to a power distribution line 120 of a power distribution system PS through the power distribution line 120 and incorporate different disturbances DT into physical quantities at connection points of the power generating facilities 122 to the power distribution line 120, and a disturbance analysis device that is provided in a power receiving facility 126 connected to the power distribution line 120, acquires a system state ST of the power distribution system PS by detecting the disturbance DT, and changes a state of the power receiving facility 126 on the basis of the acquired system state ST.SELECTED DRAWING: Figure 1

Description

[Technical Field]

[0001] The present invention relates to an information transmission system and an information transmission method. [Background technology]

[0002] As background art in this technical field, the abstract of the following Patent Document 1 states, "A method, an apparatus, and a computer program for transmitting and / or receiving information are described. Information encoded in a carrier signal including a modulation pattern superimposed on a grid frequency at which electricity flows within a synchronous region of a power grid is decoded in a receiving device by measuring characteristics related to the frequency of the electricity flowing within the power grid, accessing data indicative of one or more predetermined code patterns, and performing a correlation process to determine a correlation between the modulation pattern and one of the one or more predetermined code patterns. The information is decoded based on the determined correlation. This allows information to be easily transmitted within a synchronous region of a power grid." [Prior art documents] [Patent documents]

[0003] [Patent Document 1] Special Publication No. 2016-513927 Summary of the Invention [Problem to be solved by the invention]

[0004] However, in the above-mentioned technology, there is a demand for realizing more appropriate communication via power lines. The present invention has been made in view of the above circumstances, and an object of the present invention is to provide an information transmission system and an information transmission method that can realize appropriate communication via power lines. [Means for solving the problem]

[0005] In order to solve the above problems, the information transmission system of the present invention is characterized by comprising: a plurality of disturbance introduction control devices provided in a plurality of power generation facilities connected to the distribution lines of an electric power system, each of which introduces a different disturbance into a physical quantity at the connection point of each of the power generation facilities to the distribution line; and a disturbance analysis device provided in a power receiving facility connected to the distribution line, which detects the disturbances to obtain the system state of the electric power system, and changes the state of the power receiving facility based on the obtained system state. [Effects of the Invention]

[0006] According to the present invention, appropriate communication via power lines can be achieved. [Brief explanation of the drawings]

[0007] [Figure 1] FIG. 2 is a system diagram showing one system state of the power system in the first embodiment. [Figure 2] FIG. 10 is a system diagram showing another system state of the power system. [Figure 3] FIG. 10 is a diagram illustrating an example of existence probability. [Figure 4] FIG. 1 is a block diagram showing an example of the configuration of a power generation facility. [Figure 5] FIG. 2 is a block diagram showing an example of the configuration of power receiving equipment. [Figure 6] FIG. 1 is a block diagram of a computer. [Figure 7] 10 is a flowchart of a disturbance mixing routine. [Figure 8] 1 is a flowchart of a disturbance analysis routine. [Figure 9] FIG. 1 is a diagram illustrating an example of a voltage ratio in a power distribution line. [Figure 10] FIG. 10 is an enlarged view of the vertical axis of FIG. [Figure 11] FIG. 10 is a diagram illustrating an example of a calculation result of the existence probability. [Figure 12] FIG. 10 is a system diagram of a power system in a second embodiment. [Figure 13] FIG. 10 is a diagram illustrating an example of existence probability in the second embodiment. [Figure 14]5A to 5C are diagrams illustrating various examples of setting tables. [Figure 15] FIG. 11 is a diagram illustrating an example of a management table according to the third embodiment. DETAILED DESCRIPTION OF THE INVENTION

[0008] [Outline of the embodiment] A technique called islanding, in which a portion of a power grid is isolated due to various factors and the isolated grid continues to supply power through the independent operation of generators, is being studied in various fields. By applying islanding, it is possible to quickly isolate a portion of the grid when the supply and demand of power becomes tight, such as when the load suddenly increases, from the perspective of the upper grid. In recent years, there has been an increase in inverter loads, which cause voltage drops and increase current consumption, and this is one of the causes of cascading. Therefore, islanding can suppress cascading and other problems.

[0009] On the other hand, islanding has the advantage of reducing the possibility of a power outage due to the influence of an unstable upstream system, even in a grid that is isolated by islanding. In other words, there are many advantages to being able to continue supplying power using the power source within the microgrid formed by islanding. This is motivated by the fact that in recent years, in addition to rotating machine generators, the introduction of converters suitable for independent operation has come into view. Incidentally, when configuring protection devices for private electrical facilities connected to the distribution grid, procedures such as determining setting values ​​are followed in consultation with the transmission and distribution company. This is because setting values ​​must be based on physical quantities that cannot be known on the consumer side, such as earth capacitance.

[0010] The above-mentioned earth capacitance changes in response to changes in the system configuration due to islanding. Therefore, it is preferable that the settings of the protection devices on the customer side also be dynamically changed in accordance with dynamic changes in the system configuration. While it is possible to notify the details of dynamic changes in the system configuration via normal communication paths, this may be affected by communication failures such as disasters and other congestion. Therefore, it is preferable that the customer side's equipment obtains information about the system configuration via the heavy-current power lines used for power supply. This is because it eliminates the need for a separate contract with a telecommunications company and is not affected by communication company failures.

[0011] Technologies such as power line carriers have been used for communication via high-current electric wires. However, power line carriers use carrier frequencies that are much higher than the power supply frequency, requiring a modem that can modulate and demodulate at that frequency. Furthermore, there are issues with the carrier frequency and output level, such as the inability to communicate through a transformer.

[0012] On the other hand, by applying the technology of the above-mentioned Patent Document 1, it is considered possible to transmit information by modulating the load based on the load-frequency characteristics of a synchronous generator, thereby transmitting information by frequency deviation. However, modulating the load in order to utilize the load-frequency characteristics requires a load change amount sufficient to obtain the desired modulation degree. This is considered applicable only when the ratio of modulatable load to total power can be relatively large, for example, in a small-scale power system such as an isolated island. In other words, it is considered difficult to apply this technology to a large-scale power system. Therefore, the embodiment described below provides a technology that can realize appropriate communication via a high-current electric wire and has a wide range of applicability.

[0013] [First embodiment] Overall Configuration of First Embodiment FIG. 1 is a system diagram showing one system state ST-1 of the power system PS-1 in the first embodiment. 1, power system PS-1 includes distribution lines 120-0 to 120-4 that transmit three-phase AC current, a transformer 121 in a distribution substation bank (not shown), power generation facilities 122-1 to 122-3, switches 124-1 to 124-3, and power receiving facility 126. Power receiving facility 126 is, for example, consumer facility, and includes a protection device 140 and a load device 130. Load device 130 is any type of device that consumes power.

[0014] In the following description, multiple components, physical quantities, information, etc. that have the same or similar functions or meanings may be expressed by adding "-" and alphanumeric characters to the same reference numeral, such as "power generation facilities 122-1 to 122-3." However, when it is not necessary to distinguish between these multiple components, etc., they may be expressed by omitting "-" and alphanumeric characters, such as "power generation facility 122."

[0015] As will be described in detail later, each power generating facility 122 includes a disturbance introduction control device 310 (see FIG. 4), and the power receiving facility 126 includes a disturbance analysis device 350 (see FIG. 5). The disturbance introduction control device 310 and the disturbance analysis device 350 constitute an information transmission system.

[0016] Switches 124-1 to 124-3 are inserted at various points in the distribution line 120. The distribution line 120-0 is a distribution line that runs from the transformer 121 to the power generation facility 122-1. The distribution line 120-1 is a distribution line that runs from the power generation facility 122-1 to the switch 124-1. The distribution line 120-2 is a distribution line that runs from the switch 124-1 to the switch 124-2. The distribution line 120-3 is a distribution line that runs from the switch 124-2 to the switch 124-3. The distribution line 120-4 is a distribution line that runs from the switch 124-3 to the power receiving facility 126. Although not shown in FIG. 1 , automatic distribution voltage regulators (SVRs) are inserted at various points in the distribution line 120.

[0017] The capacitances to the ground of the distribution lines 120-0, 120-1, 120-2, and 120-3 are referred to as C0, C1, C2, and C3. The capacitance to the ground of the distribution line 120-4 is assumed to be negligibly small. The power generation facility 122 is a facility including, for example, a storage battery 334 (see FIG. 4 ) and a converter 332 that inputs and outputs electric power between the storage battery 334 and the distribution line 120.

[0018] 1, all switches 124 are closed. As a result, the system configuration seen from power receiving equipment 126 of the section from transformer 121 to power receiving equipment 126 becomes system configuration SC-1, which is the entire range from transformer 121 to power receiving equipment 126. Here, an estimated value of the ground fault current when a single-line ground fault occurs in load device 130 of power receiving equipment 126 is set as ground fault current estimated value I1 (not shown).

[0019] The capacitance used as the basis for calculating the ground-fault current estimate I1 is C0+C1+C2+C3. As shown in FIG. 5 (described later), the protection device 140 includes a ground-fault protection relay 142 (relay) and an overcurrent protection relay 144 (relay). The ground-fault protection relay 142 opens when the zero-phase component of the current passing through the protection device 140 exceeds a predetermined set value Ia (not shown), thereby disconnecting the load device 130 from the distribution line 120. The overcurrent protection relay 144 opens when the current passing through the protection device 140 exceeds a predetermined set value Ib (not shown), thereby disconnecting the load device 130 from the distribution line 120. Therefore, if the set value Ia is set to a value slightly lower than the ground-fault current estimate I1, the ground-fault protection relay 142 of the protection device 140 can be opened when a single-line ground fault occurs.

[0020] 2 is a system diagram showing another system state ST-2 of the power system PS-1. Note that in FIG. 2, some of the reference numerals shown in FIG. 1 are omitted. In system state ST-2, for some reason, switch 124-1 is in the open state. As a result, the system configuration seen from power receiving equipment 126 becomes system configuration SC-2, which is the range from switch 124-1 to power receiving equipment 126. Here, an estimated value of the ground fault current when a single-line ground fault occurs in load device 130 of power receiving equipment 126 is set to ground fault current estimated value I2 (not shown). In this case, the capacitance that serves as the basis for calculating ground fault current estimated value I2 is C2+C3.

[0021] However, if the setting value Ia set in the protection device 140 remains the same value set based on the ground-fault current estimated value I1 in the system state ST-1 (see FIG. 1), there may be cases where the actually occurring ground-fault current does not exceed the setting value Ia. In this case, a problem occurs in which the power receiving equipment 126 cannot be protected from ground faults. For this reason, it becomes necessary to set the setting value Ia according to the state of the power system PS-1, such as the system states ST-1 and ST-2.

[0022] For this reason, in this embodiment, in each power generation facility 122, a disturbance is applied to the physical quantity (for example, voltage) in the distribution line 120 at that location, and the disturbance is detected in the power receiving facility 126 to determine the current system state ST. Returning to Fig. 1, in the first embodiment, the disturbances applied to the distribution line 120 in the power generation facilities 122-1, 122-2, and 122-3 are called DT-1, DT-2, and DT-3.

[0023] <Outline of Disturbance DT> Below, we will provide an overview of disturbance DT. To generate the disturbance DT, a disturbance sequence BS (not shown) is applied in each power generating facility 122 and power receiving facility 126. In this embodiment, the disturbance sequence BS is common to all power receiving facilities 126. The disturbance sequence BS is a multi-bit sequence, but it is preferable to apply an M-sequence sequence. When an M-sequence is applied, where n is a natural number equal to or greater than 2, the sequence length BSL (not shown), which is the number of bits of the disturbance sequence BS, is "2 to the nth power -1", and takes values ​​such as "63", "127", and "255". When an M-sequence disturbance sequence BS is applied, the autocorrelation of the disturbance sequence BS becomes a delta function.

[0024] By using a large value such as "1023" as the sequence length BSL, the amplitude of the disturbance DT can be made very small. Also, by using a small value such as "63" as the sequence length BSL, the time required to detect islanding can be shortened.

[0025] Furthermore, common short-cycle TS and long-cycle TL (neither shown) are applied to each power generating facility 122 and power receiving facility 126. The short-cycle TS is a period corresponding to "1 bit" of the disturbance sequence BS, and has a length of, for example, "1 second" or "0.25 seconds." The long-cycle TL is a period corresponding to all bits of the disturbance sequence BS, and is the value obtained by multiplying the short-cycle TS by the sequence length BSL of the disturbance sequence BS. For example, if the sequence length BSL is "255" and the short-cycle TS is "0.25 seconds," the long-cycle TL is "63.75 seconds."

[0026] If the short cycle TS is set to about 0.1 seconds, it is preferable to carefully select the value of the short cycle TS due to flicker sensitivity. Furthermore, if the short cycle TS is set shorter than 0.1 seconds, it is preferable to take into consideration inductive interference with low-current electric wires. Furthermore, since the short cycle TS is the cycle for switching the command value supplied to the converter 332, there may be limitations depending on the specifications of the converter 332 (for example, the PWM carrier frequency).

[0027] Furthermore, if the short period TS is further shortened, electrical and magnetic induction interference may occur. The incorporation of disturbance DT is achieved by switching the command value supplied to converter 332 (see FIG. 4). Therefore, when a high frequency higher than the order of kHz is adopted, it is generally preferable to add a modem device or the like. This modem device or the like will inject disturbance DT into the distribution line 120 by AC coupling via a coupling capacitor. For these reasons, it is preferable to set the short period TS to 0.1 seconds or more.

[0028] Here, a function called a disturbance function f(t) is defined based on the disturbance sequence BS, the short-period TS, and the long-period TL. Here, “t” is the elapsed time from the start timing of the long-period TL. The disturbance function f(t) is a function that switches between the value of the disturbance sequence BS, i.e., “1” or “0,” for each short-period TS. Assuming that the disturbance function f(t) is applied to the power generation facility 122, during the period when the disturbance function f(t) is “1,” the power generation facility 122 applies a disturbance in a predetermined direction to the physical quantity of the power distribution line 120. For example, it is conceivable to increase the voltage of the power distribution line 120 by “ΔV1.” Furthermore, during the period when the disturbance function f(t) is “0,” the power generation facility 122 applies a disturbance in the opposite direction to the physical quantity of the power distribution line 120. For example, it is conceivable to decrease the voltage of the power distribution line 120 by “ΔV1.”

[0029] However, different lag values ​​ΔT1, ΔT2, and ΔT3 are applied to the disturbance function f(t) for each of the power generation facilities 122-1, 122-2, and 122-3. That is, the power generation facilities 122-1, 122-2, and 122-3 generate their own disturbances DT-1, DT-2, and DT-3 based on the disturbance functions f(t+ΔT1), f(t+ΔT2), and f(t+ΔT3), respectively. The lag values ​​ΔT1, ΔT2, and ΔT3 are all natural number multiples of the short-period TS.

[0030] The power receiving equipment 126 measures a physical quantity (e.g., voltage V(t)) on the power distribution line 120-4 and acquires a difference value dm(t) (not shown) for each short-period TS. This difference value dm(t) is, for example, the difference value between the physical quantity in the current short-period TS and the physical quantity in the immediately preceding short-period TS. Next, the power receiving equipment 126 performs limiter processing (details of which will be described later) on the difference value dm(t) to limit the amplitude within a predetermined range. The result of the limiter processing is called a corrected difference value h(t) (not shown).

[0031] Next, the power receiving equipment 126 calculates the cross-correlation between the disturbance function f(t) and the corrected difference value h(t+ΔT) for multiple lag values ​​ΔT ranging from "0" to "long-period TL." The cross-correlation obtained by this calculation is referred to as the existence probability G(ΔT), or simply the existence probability G, as a function of the lag value ΔT. Here, it is assumed that the state of the power system PS-1 is the system state ST-1 shown in FIG. 1. In this case, the existence probability G shows peaks when the lag values ​​ΔT are ΔT1, ΔT2, and ΔT3.

[0032] 3 is a diagram showing an example of the presence probability G. In graphs GR1 and GR2, the vertical axis represents the presence probability G, and the horizontal axis represents the lag value, i.e., the elapsed time within the long period TL. In graphs GR1 and GR2, the presence probabilities G(ΔT) at lag values ​​ΔT1, ΔT2, and ΔT3 are called presence probabilities G1, G2, and G3.

[0033] According to graph GR1, the existence probabilities G1, G2, and G3 peak at high values ​​and exceed a predetermined threshold value ThG. This indicates that all of power generation facilities 122-1, 122-2, and 122-3 are connected to power receiving facility 126 via distribution line 120. In other words, the state of power system PS-1 as seen from power receiving facility 126 is ST-1. Therefore, by setting the system capacitance used to calculate setting value Ia to "C0+C1+C2+C3," it is possible to prevent erroneous operation or non-operation of protection device 140.

[0034] Furthermore, according to graph GR2, the presence probabilities G2 and G3 exceed the threshold value ThG, but the presence probability G1 is less than the threshold value ThG. This shows that power generation facilities 122-2 and 122-3 are connected to power receiving facility 126 via distribution line 120, but power generation facility 122-1 is not connected. In other words, switch 124-1 is in the open state, and the state of power system PS-1 as seen from power receiving facility 126 is ST-2. Therefore, by setting the system capacitance used to calculate setting value Ia of ground fault protective relay 142 to "C2+C3," it is possible to prevent malfunction or non-operation of protection device 140.

[0035] Since the number of switches 124 capable of performing islanding is expected to be limited to a certain extent, a correspondence table between the positions of the opened switches 124 and the corresponding setting value Ia can be created in advance. Therefore, in practice, it is not necessary to calculate the setting value Ia from the capacitance to ground every time islanding occurs. Also, the time limit setting of the ground fault protection relay 142 in the switch 124 can be changed using a similar procedure. Also, the setting value Ib of the overcurrent protection relay 144 can be calculated using a procedure similar to that for the setting value Ia of the ground fault protection relay 142.

[0036] <Power Generation Facility 122> FIG. 4 is a block diagram showing an example of the configuration of the power generation facility 122. 4, the power generation facility 122 includes a disturbance introduction control device 310, a drive device 330, a converter 332, a storage battery 334, a power generation facility disturbance analysis device 400, and a measurement unit 402. The converter 332 converts between a DC voltage input / output from the storage battery 334 and a three-phase AC voltage in the power distribution line 120.

[0037] As a result, the converter 332 outputs power discharged from the storage battery 334 via the distribution line 120, or charges the storage battery 334 with power input via the distribution line 120. The driving device 330 drives the converter 332 by issuing commands regarding voltage, current, etc. to be input / output from the converter 332 to the distribution line 120. The disturbance introduction control device 310 also issues a command to the driving device 330 to introduce a disturbance DT (see FIG. 1).

[0038] The measurement unit 402 includes sensors (not shown) that measure various physical quantities such as voltage, current, and power factor in the distribution line 120. The power generation facility disturbance analysis device 400 is a device that detects a disturbance DT at the connection point of the power generation facility 122 to the distribution line 120 based on the measured physical quantities, and thereby acquires the system state ST of the power system PS-1.

[0039] The power generation facility disturbance analysis device 400 has the same functions as the disturbance analysis device 350 (see FIG. 5) provided in the power receiving facility 126 described below. However, the power generation facility disturbance analysis device 400 and the measurement unit 402 do not necessarily have to be provided in all power generation facilities 122. This point will also be described in detail later.

[0040] The disturbance introduction control device 310 includes a timing synchronization unit 312, a sequence length and sequence specification determination unit 313, a sequence generation unit 314, a command value offset output unit 315, a lag value setting unit 322, a long-cycle timer 323, a short-cycle timer 324, a sequence value pointer calculation unit 325, and an overall control unit 326.

[0041] The timing synchronization unit 312 communicates with the timing synchronization unit 312 in the other power generation facilities 122, and performs synchronization control of the start timing of the long-cycle TL and the short-cycle TS. By synchronizing the timing, appropriate presence probabilities G1, G2, and G3 appear for the lag values ​​ΔT1, ΔT2, and ΔT3 shown in FIG.

[0042] The lag value setting unit 322 sets different lag values ​​(lag values ​​ΔT1, ΔT2, ΔT3, etc.) for each power generation facility 122. Information on these lag values ​​ΔT1, ΔT2, ΔT3, etc. is shared among the power receiving facilities 126, the protection devices 140, and other devices that need to detect dynamic changes in the system configuration due to islanding, etc.

[0043] The sequence length and sequence specification determination unit 313 determines the sequence length BSL and sequence specifications. The sequence specifications determine the generator polynomial of the disturbance sequence BS, the type of sequence, etc. When the disturbance sequence BS is generated using a shift register, the generator polynomial can be defined by the tap position of the shift register. Furthermore, it is preferable to determine the type of sequence to be a sequence that is easy to synchronize with time. The longer the sequence length BSL, the higher the resistance to external noise can be expected and the smaller the amplitude of the disturbance DT that is mixed in. On the other hand, the longer the sequence length BSL, the longer the response time for detecting the grid state ST in the power receiving equipment 126. Therefore, it is preferable to determine the sequence length BSL to be applied taking these trade-offs into consideration.

[0044] The sequence generation unit 314 generates a disturbance sequence BS according to the sequence length and sequence specifications determined by the sequence length and sequence specification determination unit 313 .

[0045] The long-cycle timer 323 generates a timing pulse for each long cycle TL. The short-cycle timer 324 generates a timing pulse for each short cycle TS. Due to the operation of the timing synchronizer 312 described above, the timing of generation of these timing pulses is synchronized in all of the power generation equipment 122 and power receiving equipment 126.

[0046] Furthermore, if there is other equipment (not shown) that needs to sense dynamic changes in the system configuration due to islanding or the like, the generation timing of these timing pulses will be synchronized in these other equipment as well. Note that it is not necessarily necessary to use two timers, and a counter may be applied instead of long-cycle timer 323. That is, this counter should count the timing pulses of short-cycle timer 324, and reset the count result when the count result reaches sequence length BSL.

[0047] The sequence value pointer calculation unit 325 calculates a sequence value pointer PT (not shown) that indicates the bit to be referenced in the disturbed sequence BS. More specifically, the sequence value pointer calculation unit 325 accumulates timing pulses for each short cycle TS output by the short cycle timer 324, adds values ​​corresponding to the lag values ​​(ΔT1, ΔT2, ΔT3) to this accumulation result, and sets the remainder when this addition result is divided by the sequence length BSL as the sequence value pointer PT.

[0048] The command value offset output unit 315 reads the value (“0” or “1”) of the sequence value pointer PT of the disturbance sequence BS, and based on the result, outputs a command value offset OFS to the driving device 330. For example, it is assumed that the driving device 330 outputs a voltage command value in the distribution line 120 to the converter 332.

[0049] In this example, when the value of the series value pointer PT for the disturbance series BS is "0," the command value offset output unit 315 outputs a command value offset amount OFS that decreases the voltage command value by, for example, "3%." Also, when the value of the series value pointer PT for the disturbance series BS is "1," the command value offset output unit 315 outputs a command value offset amount OFS that increases the voltage command value by, for example, "3%." The drive device 330 increases or decreases the supplied command value offset amount OFS with respect to a reference value of the voltage command value, and supplies the result to the converter 332 as a voltage command value.

[0050] The above-described command value offset amount OFS is an example, and the command value offset amount OFS may be an amount relative to another command value output by the driving device 330 to the converter 332. For example, the command value offset amount OFS may specify a minute fluctuation in the power factor of the converter 332. The overall control unit 326 controls the other components of the disturbance introduction control device 310 in an overall manner.

[0051] <Power receiving equipment 126> FIG. 5 is a block diagram showing an example of the configuration of the power receiving equipment 126. As shown in FIG. 5, the power receiving equipment 126 includes a measurement unit 372, a disturbance analyzer 350, a protection device 140, and a load device 130. The measurement unit 372 includes sensors (not shown) that measure various physical quantities, such as the voltage, current, and power factor, in the power distribution line 120-4. As described above, the protection device 140 disconnects the load device 130 from the power distribution line 120-4 when the current passing therethrough exceeds a predetermined setting value Ia. The disturbance analyzer 350 sets the setting value Ia for the protection device 140 based on the physical quantity measured by the measurement unit 372. The setting value Ib of the overcurrent protection relay 144 may also be set using a similar procedure.

[0052] The disturbance analysis device 350 includes a measurement value acquisition unit 354, a sequence length and sequence specification determination unit 355, a sequence generation unit 356, a time differencing and limiter processing unit 357, a correlation calculation unit 358, a setting value setting unit 359, a timing synchronization unit 362, a long-cycle timer 363, a short-cycle timer 364, an existence probability calculation unit 365, a system configuration estimation unit 366, a setting value determination unit 367, and an overall control unit 368.

[0053] The measurement value acquisition unit 354 acquires the above-mentioned measurement value from the measurement unit 372. Here, as an example, it is assumed that the voltage V(t) in the power distribution line 120-4 is selected as the measurement value. The sequence length and sequence specification determination unit 355 determines the sequence length BSL, which is the bit length of the disturbance sequence BS, and the sequence specifications, in the same way as the sequence length and sequence specification determination unit 313 in the power generation facility 122 (see FIG. 4). Note that the determined sequence length BSL and sequence specifications are the same as those determined in the power generation facility 122.

[0054] The sequence generation unit 356 generates a disturbance sequence BS in accordance with the sequence length BSL and sequence specifications determined by the sequence length and sequence specification determination unit 355. The generated disturbance sequence BS is the same as that generated in the power generation facility 122.

[0055] The time differencing / limiter processing unit 357 executes time differencing processing and limiter processing. The time differencing processing is processing for calculating the difference between a physical quantity in the current short-period TS and a physical quantity in the immediately preceding short-period TS, thereby obtaining the above-mentioned difference value dm(t). The limiter processing is processing for limiting the absolute value of the difference value dm(t) to a predetermined threshold value when the absolute value of the difference value dm(t) exceeds this threshold value. The result of this limiter processing becomes the above-mentioned corrected difference value h(t).

[0056] Here, the significance of limiter processing will be explained. As described above, automatic voltage regulators (SVRs) (not shown) are inserted throughout the distribution line 120, and these SVRs and the like can cause step-like voltage changes in the voltage V(t). Therefore, limiter processing is performed to reduce the effect of such step-like voltage changes to a negligible level.

[0057] For example, if the sequence length BSL of the disturbance sequence BS is 255, and a single discrete change in voltage occurs due to the SVR, the correlation calculation peak will be reduced by approximately 1 / 250. This is equivalent to a slight reduction in the C / N ratio relative to background noise. In this way, by performing limiter processing, the impact of changes in voltage V(t) due to the SVR, etc., can be greatly reduced.

[0058] The correlation calculation unit 358 calculates the above-mentioned existence probability G(ΔT) (see FIG. 3) by calculating the cross-correlation between the disturbance function f(t) and the corrected difference value h(t+ΔT). The timing synchronization unit 362, like the timing synchronization unit 312 in the disturbance mixing control device 310 (see FIG. 4), communicates with the timing synchronization unit 312 in each power generation facility 122 and performs synchronization control of the start timing of the long-cycle TL and the short-cycle TS. Like the short-cycle timer 324 in the disturbance mixing control device 310, the short-cycle timer 364 generates a timing pulse for each short-cycle TS. However, it is preferable that the timing pulse in the short-cycle timer 364 be delayed by "1 / 2 period" of the short-cycle TS compared to the timing pulse from the short-cycle timer 324 (see FIG. 4) in the power generation facility 122. This allows the existence probabilities G1, G2, and G3 to be detected with high sensitivity based on the applied disturbances DT-1, DT-2, and DT-3.

[0059] A similar function can be achieved by delaying the long-cycle timer 363 on the receiving side by half a cycle of the short-cycle timer. The delay of the short-cycle timer by half a cycle is applied exclusively to either the short-cycle timer 364 or the long-cycle timer 363. Both the process of applying the half-cycle delay and the process of not applying it may be always executed on the receiving side.

[0060] The existence probability calculation unit 365 determines that the power generation facility 122 corresponding to the lag value ΔT exists at a location where the existence probability G(ΔT) calculated by the correlation calculation unit 358 exceeds the threshold value ThG (see FIG. 3).

[0061] The timing pulse of the short-cycle TS generated by the above-described short-cycle timer 364 may have a two-phase configuration using a pulse that is in phase with that of the power generation facility 122 and a pulse that is delayed by "1 / 2 cycle" of the short-cycle TS. In addition to two phases delayed by a half cycle, the short-cycle timer 364 may generate three-phase timing pulses that are delayed by "1 / 3 cycle" each, or n-phase timing pulses that are delayed by "1 / n cycle" each.

[0062] When two-phase timing pulses are applied, the existence probability calculation unit 365 may determine that the power generation facility 122 is present when the existence probability G based on at least one of the phases exceeds the threshold value ThG (see FIG. 3). When n-phase timing pulses are applied, the existence probability calculation unit 365 may determine that the power generation facility 122 is present when the existence probability G in half or more of the phases exceeds the threshold value ThG (see FIG. 3).

[0063] Based on the determination result by the existence probability calculation unit 365, the system configuration estimation unit 366 estimates the system configuration SC (for example, system configurations SC-1 and SC-2 in FIGS. 1 and 2) visible from the position of the protection device 140 of the power receiving equipment 126.

[0064] The setting value determination unit 367 determines the setting value Ia for the ground fault protection relay 142 in the protection device 140 according to the estimated system configuration SC. For example, as described above, the system capacitance used to calculate the setting value Ia in the system configuration SC-1 (see FIG. 1) is "C0+C1+C2+C3," and the system capacitance used to calculate the setting value Ia in the system configuration SC-2 (see FIG. 2) is "C2+C3."

[0065] The setting value setting unit 359 sets the setting value Ia determined by the setting value determination unit 367 in the ground fault protection relay 142 of the protection device 140. The overall control unit 368 controls the other components of the disturbance introduction control device 310 overall.

[0066] In the above example, all power generation facilities 122 are provided with a disturbance mixing control device 310 (see FIG. 4). However, it is not necessary to provide a disturbance mixing control device 310 to all power generation facilities 122. In other words, the disturbance mixing control device 310 may be provided only to the main power generation facilities 122 that are located in a position sufficient for islanding detection. More preferably, the disturbance mixing control device 310 should be provided to the power generation facilities 122 with a large apparent power capacity. This allows for a greater degree of freedom in the amplitude of the disturbance DT to be mixed in.

[0067] Furthermore, in the above example, each power generation facility 122 is provided with a storage battery 334, but various other power generation devices may be applied instead of the storage battery 334. However, if a solar power generation device or the like is applied as the power generation device, there will be times when the power generation facility 122 cannot generate power. For this reason, it is preferable to apply a power generation device that can generate power continuously, such as a fuel cell or a small-output hydroelectric power generation facility.

[0068] Furthermore, the converter 332 is not necessarily required in each power generation facility 122, and a generator, which is a rotating machine, may be used instead of the converter 332. In this case, the command value offset amount OFS may be a minute fluctuation with respect to excitation. In this way, the disturbance DT is not limited to the voltage V(t) but can be realized in various physical quantities such as the power factor and the active power output.

[0069] Furthermore, the number of power generating facilities 122 equipped with the disturbance mixing control device 310 is not limited to the minimum number required for islanding detection, and the disturbance mixing control device 310 may be provided in more power generating facilities 122. That is, in each section used to identify islanding, two or more power generating facilities 122, including backup power generating facilities, may be provided with the disturbance mixing control device 310. In this case, the power generating facilities 122 in the same section may operate in coordination, so that at least one power generating facility 122 is always in operation.

[0070] In order to coordinate the operation of multiple power generation facilities 122, it is preferable to provide the power generation facility disturbance analyzer 400 (see FIG. 4) described above in each of the power generation facilities 122 that are to be coordinated. This allows the disturbance DT caused by the other power generation facility 122 that is to be coordinated to be detected. Note that a power generation facility 122 equipped with the power generation facility disturbance analyzer 400 is sometimes referred to as a "power generation facility with an analyzer." If the disturbance DT caused by the other power generation facility 122 cannot be detected, it is considered that the other power generation facility 122 has stopped operating, the distribution line 120 has been interrupted, or the other power generation facility 122 has stopped applying the disturbance DT. In such cases, it is preferable that the power generation facility disturbance analyzer 400 operate the converter 332 of the own facility or the disturbance introduction control device 310 of the own facility.

[0071] Fig. 6 is a block diagram of the computer 980. The disturbance mixing control device 310 shown in Fig. 4 and the disturbance analysis device 350 shown in Fig. 5 each include one or more computers 980 shown in Fig. 6. 6, a computer 980 includes a CPU 981, a storage unit 982, a communication I / F (interface) 983, an input / output I / F 984, and a media I / F 985. Here, the storage unit 982 includes a RAM 982a, a ROM 982b, and an SSD (Solid State Drive) 982c.

[0072] The communication I / F 983 is connected to a communication circuit 986. The input / output I / F 984 is connected to an input / output device 987. The media I / F 985 reads and writes data from a recording medium 988. The ROM 982b stores an IPL (Initial Program Loader) and the like executed by the CPU. The SSD 982c stores control programs, various data, and the like. The CPU 981 executes the control programs and the like read from the SSD 982c to the RAM 982a to realize various functions. The interiors of the disturbance mixing control device 310 and the disturbance analysis device 350 shown in Figures 4 and 5 are primarily shown as blocks showing functions realized by the control programs and the like.

[0073] <Operation of the First Embodiment> Next, the operation of the first embodiment will be described. 7 is a flowchart of the disturbance mixing routine. This routine is executed by the disturbance mixing control device 310 of each power generation facility 122, etc. 7, when the process proceeds to step S723, the lag value setting unit 322 sets lag values ​​(for example, ΔT1, ΔT2, ΔT3). Next, when the process proceeds to step S724, the sequence length / sequence specification determination unit 313 determines the sequence length BSL and sequence specifications of the disturbance sequence BS.

[0074] Next, when processing proceeds to step S725, the sequence generation unit 314 generates a disturbance sequence BS. Next, when processing proceeds to step S726, the sequence value pointer calculation unit 325 determines whether the current time is the start timing of the short cycle TS. Specifically, it determines whether the short cycle timer 324 has output a timing pulse. If the determination here is "No," the processing of step S726 is repeated.

[0075] On the other hand, if the determination in step S726 is "Yes", processing proceeds to step S727, where sequence value pointer calculation unit 325 updates sequence value pointer PT. In addition, command value offset output unit 315 reads the bit specified by the updated sequence value pointer PT from disturbance sequence BS, and updates command value offset OFS according to that value.

[0076] Next, when the process proceeds to step S728, the driving device 330 updates the command value (for example, voltage command value) to be supplied to the converter 332 by increasing or decreasing the updated command value offset amount OFS with respect to the reference value of the command value. This changes the operating state of the converter 332. Thereafter, the processes of steps S726 to S728 are repeated.

[0077] 8 is a flowchart of a disturbance analysis routine, which is executed by the disturbance analysis device 350 of the power receiving facility 126 or the like. 8, when the process proceeds to step S754, the measurement value acquisition unit 354 acquires various measurement values ​​from the measurement unit 372. Next, when the process proceeds to step S755, the time differencing / limiter processing unit 357 acquires a corrected difference value h(t) based on these measurement values.

[0078] Next, when the process proceeds to step S756, the sequence length and sequence specification determination unit 355 and the sequence generation unit 356 generate a disturbed sequence BS. Next, when the process proceeds to step S757, the correlation calculation unit 358 calculates the above-mentioned existence probability G(ΔT) by calculating the cross-correlation between the disturbance function f(t) and the corrected difference value h(t+ΔT) for multiple lag values ​​ΔT.

[0079] Next, when the process proceeds to step S758, the existence probability calculation unit 365 detects a peak exceeding the threshold value ThG from the existence probability G(ΔT). Next, when the process proceeds to step S759, the existence probability calculation unit 365 determines whether or not each power generation facility 122 exists.

[0080] Incidentally, the disturbance sequence BS is not limited to one type, and multiple types of disturbance sequences BS may be applied. In step S760, the existence probability calculation unit 365 determines whether or not the processing of steps S756 to S759 has been completed for all the applied disturbance sequences BS. If the determination here is "No," the processing returns to step S756, and the processing from step S756 onwards is executed for any unprocessed disturbance sequence BS. On the other hand, if the determination is "Yes," the processing proceeds to step S761.

[0081] Next, when the process proceeds to step S761, the system configuration estimation unit 366 estimates the system configuration SC visible from the position of the protection device 140 of the power receiving equipment 126. Next, when the process proceeds to step S762, the setting value determination unit 367 determines a setting value Ia for the ground fault protection relay 142 in the protection device 140 according to the estimated system configuration SC. In addition, the setting value setting unit 359 outputs the determined setting value Ia and sets the setting value Ia in the ground fault protection relay 142. Thereafter, the process from step S754 onwards is repeated.

[0082] In the flows of Figures 7 and 8, it is assumed that timing synchronization has already been achieved. This can be achieved by a method of synchronizing timing using a periodically activated task (not shown). Specifically, synchronization with absolute time may be achieved using GPS or the like, or relative synchronization may be achieved between related devices such as converters and protection devices 140. For the latter relative synchronization, for example, a disturbance series dedicated to synchronization may be introduced from converters or generators on the upstream side of the system, and the disturbance series may be detected downstream by correlation calculation. Using a disturbance series dedicated to time synchronization enables simplification of both hardware and software, such as GPS receivers and network stacks when using NTP.

[0083] <Measurement results> Next, an example of the measurement result in the first embodiment will be described. Fig. 9 is a diagram showing an example of the voltage ratio in the distribution line 120. That is, in Fig. 9, the vertical axis is the ratio (pu, power unit) between the voltage in the distribution line 120 and a predetermined reference voltage, and the horizontal axis is time. Also in Fig. 9, the black solid line represents the voltage ratio when no disturbance DT is mixed in, and the gray circles represent the voltage ratio when a disturbance DT is mixed in. The vertical axis in Fig. 9 is a plot with a full scale of around 1 pu, but the waveform is almost the same before and after the mixing of the disturbance DT.

[0084] FIG. 10 is an enlarged view of the vertical axis of FIG. In Fig. 10, the scale of the vertical axis is expanded by about six times compared to Fig. 9. In Fig. 10 as well, the voltage ratio has almost the same waveform before and after the introduction of the disturbance DT.

[0085] FIG. 11 is a diagram showing an example of the calculation result of the existence probability G. The vertical axis of FIG. 11 is the existence probability G(ΔT), and the horizontal axis is the lag value ΔT. The existence probability G(ΔT) shown in FIG. 11 is calculated based on the voltages shown in FIGS. 9 and 10. The sequence length BSL of the disturbance sequence BS related to the mixed disturbance DT is "1023." Although not shown in the figure, the existence probability G(ΔT) can be sufficiently detected even when the amplitude of the disturbance DT is reduced to about "1 / 3" of that shown in FIGS. 9 and 10.

[0086] [Second embodiment] 12 is a system diagram of a power system PS-2 in the second embodiment. In the second embodiment, parts corresponding to those in the first embodiment are given the same reference numerals, and their description may be omitted. 12, power system PS-2 includes a distribution line 120 that transmits three-phase AC current, power generation facilities 122-1 to 122-3, switches 124-1 to 124-3, and power receiving facility 126. In terms of power flow calculation, at point MP1 on the left end of distribution line 120, there is no transformer 121, and it is considered to be connected to an infinite system.

[0087] The configurations of the power generation facilities 122-1 to 122-3 and the power receiving facility 126 are the same as those in the first embodiment. However, in this embodiment, the disturbances DT-1, DT-2, and DT-3 that each power generation facility 122 applies to the distribution line 120 are "power factors" at the connection points between each power generation facility 122 and the distribution line 120.

[0088] Fig. 13 is a diagram showing an example of the presence probability G(ΔT) in the second embodiment. Fig. 13 shows the results of applying power factor disturbances DT-1, DT-2, and DT-3 to the distribution line 120 in the power generation facilities 122-1 to 122-3, performing a power flow calculation on the results, and calculating the presence probability G(ΔT) at several points on the distribution line 120. First, graph GR21 in FIG. 13 shows the probability of the presence of a generator detected from the bus voltage of the voltage V(t) of the distribution line 120 by the protection device 140 in the power receiving equipment when no islanding is performed on the distribution line 120. In graph GR21, obvious peaks can be recognized in the presence probabilities G1, G2, and G3, and it can be understood that the presence of the power generation facilities 122-1 to 122-3 can be detected by simply comparing the presence probability G(ΔT) with a threshold value. Also, graph GR22 in FIG. 13 shows the probability of the presence of a generator detected from the bus voltage of the voltage V(t) of the distribution line 120 when the distribution line 120 is in an open state in the middle of the power generation facilities 122-1 and 122-2. In graph GR22, the presence probability G1 is at an extremely low level, and it can be understood that the power generation facility 122-1 is not connected to the distribution line 120 as seen from the power receiving equipment 126.

[0089] In graph GR21, the reason for the relationship of "G1 < G2 < G3" is based on the system distance from the protection device 140 in the power receiving equipment, which is the detection point, to each power generation facility 122. That is, since the distribution line 120 has series impedance and parallel capacitance, due to the effect of the low-pass filter, the influence of the disturbance DT becomes smaller as the distance increases.

[0090] As described above, in a system where many protection devices 140 with an islanding detection function are arranged near the end of the system, it is conceivable to increase the amplitude of the disturbance DT mixed in from the upstream side (substation side) of the system, or to give a slope to the mixing ratio.

[0091] Also, graph GR23 in FIG. 13 shows the presence probability G(ΔT) when the power receiving equipment 126 is moved to point MP2 without performing islanding on the distribution line 120. In graph GR23, based on the distance between point MP2 and each power generation facility 122, a relationship of "G1 > G2 > G3", which is opposite to that of graph GR21, occurs.

[0092] Furthermore, graph GR23 has a higher noise floor than graphs GR21 and GR22. This is because an infinite system is used in place of transformer 121 in the power flow calculation. Because the amplitude of voltage fluctuations in an infinite system is "0," the amplitude of disturbances at point MP2 adjacent to the infinite system decreases, and the CN ratio deteriorates. However, in an actual system, the impedance is higher than in an infinite system, so the deterioration of the CN ratio is smaller.

[0093] Furthermore, near the point where a grid-connected inverter with sufficient apparent power capacity to maintain the grid voltage operates in voltage maintenance mode, the amplitude of the voltage fluctuation approaches "0." In this case, by using the power factor as the physical quantity that mixes in the disturbance, the disturbance DT for the power flow does not become "0" even when the amplitude of the voltage fluctuation is "0." Therefore, by appropriately switching the physical quantity for disturbance detection according to the situation, the power generation equipment 122 can be detected more reliably. Furthermore, the power receiving equipment 126 may always perform disturbance detection processing on the measured values ​​of multiple physical quantities. This eliminates the need for the power receiving equipment 126 to switch the physical quantity.

[0094] [Third embodiment] Next, a power system according to the third embodiment will be described. The configuration of the power system according to the third embodiment is the same as that of the power system PS-1 (see FIG. 1) according to the first embodiment, except for the following points. That is, in the third embodiment, the disturbance mixing control device 310 of each power generation facility 122 and the disturbance analysis device 350 of the power receiving facility 126 store a setting table DTS (see FIG. 14) that defines the contents of the disturbance DT.

[0095] As a result, each disturbance introduction control device 310 and disturbance analysis device 350 introduces and detects disturbances DT based on the stored setting table DTS. The disturbance analysis device 350 also stores a management table MT (see FIG. 15) described later. The disturbance analysis device 350 sets various setting values ​​in the protection device 140 based on the setting value table.

[0096] Fig. 14 shows various examples of the setting table DTS. That is, the disturbance mixing control device 310 and the disturbance analysis device 350 in the third embodiment store one of the setting tables DTS-A to DTS-D shown in Fig. 14 as the setting table DTS.

[0097] In the setting table DTS-A, "1," "2," and "3" in the "Power Generation Equipment" column are the numbers following the "-" of the power generation equipment 122-1, 122-2, and 122-3, respectively. In the setting table DTS-A, a lag value ΔT is set as a disturbance corresponding to these. The lag value ΔT corresponds to the above-mentioned lag values ​​ΔT1, ΔT2, and ΔT3, and is stored in the protection device 140 or the like. It is sufficient for each power generation equipment 122 to at least hold its own lag value ΔT.

[0098] In the setting table DTS-B, the meaning of the "Power Generation Equipment" column is the same as in the setting table DTS-A. As disturbances corresponding to these, the setting table DTS-B sets disturbance sequences BS-1, BS-2, and BS-3.

[0099] That is, in the setting table DTS-B, a different disturbance sequence BS is assigned to each power generating equipment 122, rather than a lag value ΔT. This method eliminates the need for time (or timing) synchronization between all power generating equipment 122 and power receiving equipment 126. On the other hand, the protection device 140 in the power receiving equipment 126 must perform correlation calculations to detect all of the disturbance sequences BS in use. However, using a technique that applies FFT or the like in the correlation calculation unit 358 (see FIG. 5) can reduce overhead, so this is unlikely to be an excessive burden.

[0100] In the setting table DTS-C, the meanings of the "power generation facility" and "disturbance sequence" columns are the same as those in the setting table DTS-B. Furthermore, in the setting table DTS-C, a lag value ΔT is set for each power generation facility 122. The power generation facility 122-1 is assigned a disturbance sequence BS-1, and the lag value ΔT is variable within the range of "0 to 126." Furthermore, the power generation facilities 122-2 and 122-3 are assigned a common disturbance sequence BS-2 and different lag values ​​ΔT.

[0101] As a result, the protection device 140 and other devices in the power receiving equipment 126 connected to the grid can obtain not only the existence of the power generation equipment 122-1 but also information from the power generation equipment 122-1. That is, the power generation equipment 122-1 can transmit any information using the lag value ΔT. For example, the remaining charge of the storage battery 334 (see FIG. 4) in the power generation equipment 122-1 can be transmitted using the lag value ΔT. This allows other power generation equipment 122 in the same section to determine the timing at which they should enter backup mode.

[0102] When the transmission of information from the power generation facility 122-1 is unnecessary, the power generation facility 122-1 may be assigned the same disturbance sequence BS-2 as the power generation facilities 122-2 and 122-3 and a different lag value from the power generation facilities 122-2 and 122-3. This reduces the consumption of the disturbance sequence BS. Applying a different disturbance sequence BS to the power generation facility 122 can reduce interference from adjacent systems, for example.

[0103] In the setting table DTS-D, two disturbance sequences BS-X and BS-Y and two lag values ​​ΔTX and ΔTY are set for each power generation facility 122. For example, the sequence length BSL of the disturbance sequence BS-X can be set to "511" and the sequence length BSL of the disturbance sequence BS-Y can be set to "63." As described above, when the sequence lengths are short, the response time until the presence probability G of the power generation facility 122 is calculated can be shortened, and therefore the islanding detection time can be shortened.

[0104] Furthermore, when the sequence length BSL is long, noise resistance is high, and therefore a more accurate existence probability G can be obtained. Judgment based on a disturbance DT with a short sequence length BSL can be used to change the setting value of a ground fault protection relay 142 with a short time limit setting (e.g., with an instantaneous element). This increases the reliability of fault detection. For example, consider the ground fault protection relay 142 included in the terminal protection device 140. A circuit breaker (not shown) on the substation side may request consecutive time limit coordination. In this case, a very short time limit setting may occur.

[0105] In such a case, the requested time limit setting for the terminal-side earth fault protection relay 142 falls below the lower limit of the time limit setting. Therefore, it is advisable to take measures such as adding an instantaneous element to the response of the earth fault protection relay 142. However, islanding may reduce the number of series stages for time limit coordination. In this case, it is possible to set the terminal-side time limit setting to a value within the stabilizable range.

[0106] On the other hand, in a state without islanding, the power receiving equipment 126 may be protected by relying on the interrupting capability of the circuit breaker at the sending point of the distribution substation. However, in an islanding state, the circuit breaker at the substation becomes irrelevant, so a change in the protection method for the power receiving equipment 126 is required. Specifically, it is expected that the power generating equipment 122 in the microgrid formed by islanding will be able to protect the power receiving equipment 126 by appropriately shutting down.

[0107] Meanwhile, the converter 332 in the power generation facility 122 has functions such as Fault Ride Through (FRT) and islanding detection. Therefore, when islanding is detected, it is preferable to appropriately change the behavior of these power sources in the microgrid. The method of this embodiment can also be applied to autonomous changes of the power generation facility 122 in the microgrid without using communication.

[0108] FIG. 15 is a diagram showing an example of the management table MT in the third embodiment. In the management table MT, the leftmost column indicates the detection results of the power generation equipment 122. The "1," "2," and "3" in the "Detection Result" column are the numbers following the "-" for the power generation equipment 122-1, 122-2, and 122-3, respectively, and indicate the power generation equipment 122 that was detected. The second column from the left indicates the setting value Ia of the ground fault protection relay 142. The third column from the left indicates the setting value Ib of the overcurrent protection relay 144. The rightmost column of the management table MT indicates the notification destinations for various types of information. In this way, convenience can be improved by previously setting in the table a set of corresponding setting values, notification destinations, etc. according to the detection results of the power generation equipment 122.

[0109] Here, the significance of notifying various information to the "notification destination" will be explained. Specifically, it is conceivable that the disturbance analysis device 350 in the power receiving equipment 126 notifies the main power generating equipment 122 (hereinafter referred to as the main power generating equipment), which plays a role in controlling the frequency and voltage in the microgrid, that it has detected microgridding. Meanwhile, the main power generating equipment also detects microgridding on its own. For this reason, it is conceivable that the disturbance analysis device 350 in the power receiving equipment 126 detects microgridding even though the main power generating equipment has not detected microgridding. The occurrence of such a discrepancy can be detected by the disturbance analysis device 350 in the power receiving equipment 126 transmitting various information to the main power generating equipment.

[0110] If the primary power generation facility detects the above-described discrepancy, it may notify the disturbance analyzer 350 in the power receiving facility 126 of this fact. This allows the disturbance analyzer 350 in the power receiving facility 126 to recognize that the primary power generation facility has correctly detected the microgrid. In other words, the power receiving facility 126 can confirm that the primary power generation facility is taking over the short-circuit current interruption function that has previously been performed by the distribution substation.

[0111] Storing the detection results of the power generation equipment 122 and the corresponding setting values ​​in the form of a management table MT is important for simplification. It is also possible to calculate the setting values ​​from data representing the configuration of nearby grids (connection relationships, impedance, ground capacitance, and short-circuit capacity of existing generators) without using the management table MT. However, in this case, the setting values ​​would have to be calculated every time a change in the grid configuration is detected. In other words, a microgrid system diagram would be created by recursively tracing the grid connections. This type of processing would result in a large overhead.

[0112] Furthermore, it is not practical and requires a lot of man-hours to continually update the stored system-related information in the disturbance analysis devices 350 in all related power receiving equipment 126 every time a system facility is newly installed, modified, or abolished. With the format of management table MT shown in Fig. 15, it is not necessary to store system information in each of the disturbance analysis devices 350 in the power receiving equipment 126, and information can be updated simply by replacing the contents of the table, improving convenience.

[0113] [Variations] The present invention is not limited to the above-described embodiments and various modifications are possible. The above-described embodiments are provided as examples to facilitate understanding of the present invention and are not necessarily limited to those including all of the described configurations. Furthermore, it is possible to replace part of the configuration of one embodiment with the configuration of another embodiment, or to add the configuration of another embodiment to the configuration of one embodiment. It is also possible to delete part of the configuration of each embodiment, or to add or replace other configurations. Furthermore, the control lines and information lines shown in the figures are those considered necessary for explanation, and do not necessarily represent all control lines and information lines necessary for the product. In reality, it is acceptable to consider that almost all components are interconnected. Possible modifications of the above-described embodiments include, for example, the following:

[0114] (1) The hardware of the disturbance mixing control device 310 and the disturbance analysis device 350 in the above embodiment can be realized by a general computer, so the processes corresponding to the above-mentioned block diagrams and flowcharts, as well as programs that execute the various processes described above, may be stored on a storage medium (a computer-readable storage medium on which a program is recorded) or distributed via a transmission line.

[0115] (2) In the above embodiment, the processes corresponding to the block diagrams and flowcharts, as well as the various other processes described above, are described as software processes using programs. However, some or all of these processes may be replaced with hardware processes using an ASIC (Application Specific Integrated Circuit) or an FPGA (Field Programmable Gate Array), etc.

[0116] (3) The various processes executed in the above embodiment may be executed by a server computer via a network (not shown), and the various data stored in the above embodiment may also be stored in the server computer.

[0117] [Effects of the embodiment] As described above, according to the embodiment, the information transmission system includes a plurality of disturbance mixing control devices 310 that are provided in a plurality of power generation facilities 122 connected to the distribution line 120 of the power system PS and that mix different disturbances DT into physical quantities at the connection points of each power generation facility 122 to the distribution line 120, and a disturbance analysis device 350 that is provided in a power receiving facility 126 connected to the distribution line 120 and that detects the disturbances DT to obtain a system state ST of the power system PS and changes the state of the power receiving facility 126 based on the obtained system state ST. This enables appropriate communication to be achieved via the distribution line 120, which is a power line.

[0118] Furthermore, it is more preferable that the disturbance analysis device 350 acquires the system state ST for each power generation facility 122 based on the connection state of whether or not the facility is connected to the power receiving facility 126 via the distribution line 120, and changes the state of the power receiving facility 126 based on the acquired system state ST. This makes it possible to change the state of the power receiving facility 126 based on whether or not the facility is connected to the power receiving facility 126 via the distribution line 120.

[0119] Furthermore, it is more preferable that the power receiving facility 126 includes a load device 130 that consumes power and a protection device 140 that is inserted between the power distribution line 120 and the load device 130 and that cuts off the connection between the power distribution line 120 and the load device 130 as necessary, and the disturbance analysis device 350 changes the state of the protection device 140 based on the connection state. This allows the disturbance analysis device 350 to change the state of the protection device 140 based on the connection state.

[0120] More preferably, the protection device 140 includes relays (142, 144), and the disturbance analyzer 350 changes the settings Ia and Ib of the relays (142, 144). This allows the disturbance analyzer 350 to change the settings Ia and Ib of the relays (142, 144) based on the connection state.

[0121] Furthermore, some of the power generation facilities 122 are power generation facilities with an analyzer that include an in-power generation facility disturbance analyzer 400 that acquires the system state ST of the power system PS by detecting a disturbance DT at the connection point to the distribution line 120, and it is more preferable that the in-power generation facility disturbance analyzer 400 changes the operating state of the analyzer-equipped power generation facility based on the acquired system state ST. In this way, the in-power generation facility disturbance analyzer 400 can change the operating state of the analyzer-equipped power generation facility based on the acquired system state ST.

[0122] Furthermore, it is more preferable that the power generation facility disturbance analysis device 400 starts mixing in a disturbance DT or ends mixing in a disturbance DT in the power generation facility with an analyzer based on the acquired system state ST. This allows the power generation facility disturbance analysis device 400 to start mixing in a disturbance DT or end mixing in a disturbance DT based on the acquired system state ST.

[0123] Furthermore, the disturbance introduction control device 310 generates the disturbance DT using a disturbance sequence BS, which is a multi-bit sequence, and it is more preferable that the disturbance sequence BS is a sequence whose autocorrelation is a delta function. In this way, by applying the disturbance sequence BS whose autocorrelation is a delta function, the system state ST can be detected with high accuracy.

[0124] Furthermore, the multiple power generation facilities 122 generate disturbances DT using a common disturbance sequence BS and different lag values ​​ΔT, the disturbance mixing control device 310 and the disturbance analysis device 350 have a function for synchronizing timing with each other, the disturbance analysis device 350 calculates an existence probability G based on the cross-correlation between the result of applying the multiple lag values ​​ΔT to the common disturbance sequence BS and the physical quantity in the distribution line 120, and more preferably, the system state ST is acquired based on whether the existence probability G corresponding to each lag value ΔT exceeds a predetermined threshold value ThG. This makes it possible to identify each power generation facility 122 according to the lag value ΔT.

[0125] Furthermore, the multiple power generation facilities 122 each generate a disturbance DT using a different disturbance sequence BS, and the disturbance analysis device 350 calculates the existence probability G based on the cross-correlation between each disturbance sequence BS and a physical quantity in the distribution line 120, and more preferably acquires the system state ST based on whether the existence probability G corresponding to each disturbance sequence BS exceeds a predetermined threshold value ThG. This makes it possible to identify each power generation facility 122 according to the disturbance sequence BS.

[0126] Furthermore, the multiple power generation facilities 122 generate disturbances DT using the disturbance sequence BS and a lag value ΔT, and the combination of the disturbance sequence BS and the lag value ΔT in each power generation facility 122 is different for each power generation facility 122. The disturbance mixing control device 310 and the disturbance analysis device 350 have a function for synchronizing timing with each other, and the disturbance analysis device 350 calculates an existence probability G based on the cross-correlation between a result of applying the corresponding lag value ΔT to the disturbance sequence BS based on the multiple combinations and a physical quantity in the distribution line 120. It is more preferable to acquire the system state ST based on whether the existence probability G corresponding to each combination exceeds a predetermined threshold value ThG. This makes it possible to identify more power generation facilities 122 based on the combination of the disturbance sequence BS and the lag value ΔT, and to transmit information other than the system state ST.

[0127] Furthermore, it is more preferable that the disturbance introduction control device 310 sets the amplitude of the disturbance DT to be introduced based on the relationship between the position in the power system PS of the power generation facility 122 to which the disturbance introduction control device 310 belongs and the position in the power system PS of the disturbance analysis device 350. This allows the amplitude of the disturbance DT to be set to a value that is easy for the disturbance analysis device 350 to detect.

[0128] Furthermore, it is more preferable that the disturbance analysis device 350 changes the state of the power receiving equipment 126 based on a management table MT that associates the system state ST with the processing to be executed. This improves the convenience of information management, updating, etc. [Explanation of symbols]

[0129] 120 Power Distribution Lines 122 Power generation facilities 126 Power receiving equipment 130 Loading device 140 Protective devices 142 Earth fault protection relay (relay) 144 Overcurrent protection relay (relay) 310 Disturbance Intrusion Control Device 350 Disturbance Analysis Device 400 Power generation facility disturbance analysis device G Existence Probability BS disturbance series DT disturbance MT Management Table PS power system ST system status ΔT lag value ThG threshold Ia, Ib setting values

Claims

1. a plurality of disturbance mixing control devices provided in a plurality of power generation facilities connected to a distribution line of the power system, each of which mixes a different disturbance into a physical quantity at a connection point of each of the power generation facilities to the distribution line; a disturbance analysis device that is provided in a power receiving facility connected to the power distribution line, detects the disturbance, acquires a system state of the power system, and changes a state of the power receiving facility based on the acquired system state. An information transmission system characterized by:

2. The disturbance analysis device acquires the system state based on a connection state of each of the power generation facilities, indicating whether or not the facilities are connected to the power receiving facilities via the distribution line, and changes the state of the power receiving facilities based on the acquired system state.

2. The information transmission system according to claim 1.

3. the power receiving equipment includes a load device that consumes power, and a protection device that is inserted between the power distribution line and the load device and that cuts off a connection between the power distribution line and the load device as necessary; The disturbance analyzer changes the state of the protection device based on the connection state.

3. The information transmission system according to claim 2.

4. the protection device includes a relay; The disturbance analyzer changes the setting value of the relay.

4. The information transmission system according to claim 3.

5. a part of the power generation facility is a power generation facility with an analyzer, the power generation facility including an in-power generation facility disturbance analyzer that detects the disturbance at a connection point to the distribution line and acquires a system state of the power system, The power generation facility disturbance analyzer changes the operating state of the power generation facility with analyzer based on the acquired system state.

2. The information transmission system according to claim 1.

6. The power generation facility disturbance analyzer starts or ends the introduction of the disturbance in the power generation facility equipped with the analyzer based on the acquired system state.

6. The information transmission system according to claim 5.

7. the disturbance mixing control device generates the disturbance using a disturbance sequence that is a multi-bit number sequence, The disturbance sequence is a sequence whose autocorrelation is a delta function.

2. The information transmission system according to claim 1.

8. the plurality of power generation facilities generate the disturbances using the common disturbance sequence and different lag values, the disturbance mixing control device and the disturbance analysis device have a function of synchronizing timing with each other; The disturbance analysis device calculates an existence probability based on a cross-correlation between a result of applying a plurality of the lag values ​​to the common disturbance sequence and a physical quantity in the power distribution line, and acquires the system state based on whether the existence probability corresponding to each of the lag values ​​exceeds a predetermined threshold.

8. The information transmission system according to claim 7.

9. the plurality of power generation facilities each generate the disturbance using a different disturbance sequence, The disturbance analysis device calculates an existence probability based on a cross-correlation between each of the disturbance sequences and a physical quantity in the power distribution line, and acquires the system state based on whether the existence probability corresponding to each of the disturbance sequences exceeds a predetermined threshold.

8. The information transmission system according to claim 7.

10. a step of injecting different disturbances into physical quantities at connection points of the power generation facilities to the distribution line from a plurality of disturbance injection control devices provided in the plurality of power generation facilities connected to the distribution line of the power system; a step of detecting the disturbance by a disturbance analysis device provided in a power receiving facility connected to the distribution line, thereby acquiring a system state of the power system, and changing a state of the power receiving facility based on the acquired system state. An information transmission method characterized by:

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