Detect electrical faults within the monitored area of power transmission lines

Abstract

An example system for protecting a power transmission line in response to a fault occurring within a monitored area of a power transmission system is described. In this example, the occurrence of a fault in at least one phase of the power transmission line can be identified. Thereafter, an actual rate of change of the incremental current is calculated based on the calculated incremental current. Upon determining the actual rate of change, a threshold for calculating the rate of change of the incremental current is set based on the calculated incremental voltage, the calculated incremental current, line parameters, and the area of the monitored area. Based on a comparison of the actual rate of change with the rate of change threshold, it is determined that the fault has occurred within the monitored area. Thereafter, a trip signal for controlling a switchgear associated with the power transmission line can be generated.

Description

Technical Field

[0001] The present subject matter generally relates to power transmission systems and, more particularly, to a method for detecting faults within a monitored area of a power transmission line. Background Art

[0002] Short circuit faults occurring in transmission lines are one of the most dangerous phenomena in power systems. When such faults occur, they must be detected and cleared as quickly as possible. If the fault is not cleared or resolved within a critical clearing time, the fault may cause the power transmission system to lose transient stability, which in turn may lead to a power outage. Distance relays coupled to intelligent electronic devices (IEDs) can be used to provide protection for power lines against such faults. It will be appreciated that the IEDs can monitor impedance during their operation. When the impedance monitored by the IED is less than a predetermined threshold, the distance relay can be activated to ensure protection against the fault. Since the distance relays function in response to the detection of a fault, it will be appreciated that the speed of conventional distance relays depends on the accuracy of phasor estimation during a power transmission line fault condition. BRIEF DESCRIPTION OF THE DRAWINGS

[0003] The features, aspects and advantages of the present subject matter will be better understood with reference to the following description and accompanying drawings. The use of the same reference numerals in different drawings indicates similar or identical features and components.

[0004] Figure 1 A diagram depicting an electrical grid with smart electronic devices according to one example is provided;

[0005] Figure 2 A block diagram of an example intelligent electronic device according to one example is provided;

[0006] Figures 3 to 7 An illustrative graph depicting the occurrence of a three-phase fault within a monitored area of a power transmission line, instantaneous values of current and voltage, and corresponding delta current and delta voltage is provided according to one example; and

[0007] Figure 8 A flow chart depicting an example method for determining the presence of a fault within a monitored area of power transmission lines within an electrical grid is provided.

[0008] It will be noted that throughout the drawings, like reference numerals designate similar, but not necessarily identical, elements. The drawings are not necessarily drawn to scale, and the size of some components may be exaggerated to more clearly illustrate the examples shown. Furthermore, the drawings provide examples and / or implementations consistent with the description; however, the description is not limited to the examples and / or implementations provided in the drawings. DETAILED DESCRIPTION

[0009] An electrical fault can be considered a deviation in voltage and / or current values that may be caused by external or internal changes in the power grid. Under normal operating conditions, power grid devices in a transmission line carry normal voltages and currents and operate within their normal operating parameters. However, during an electrical fault, excessive currents may flow through such network devices as a result. This can cause damage to devices and equipment within the power grid. Conventionally, a number of preventative measures are implemented to protect the power grid. In one such example, when impedance drops below a predetermined value, an IED can cause a distance relay to detect the fault and accordingly generate a trip command for a switching device (such as a circuit breaker) to trip, thereby preventing any damage that may result from the impedance drop experienced in the power grid. Faults can be broadly categorized as asymmetric and symmetric faults. An asymmetric fault is a condition in which the load on all three phases of a three-phase power supply becomes unequal across a transmission line. On the other hand, a symmetric or balanced fault can be considered a fault that simultaneously and equally affects each of the three phases of the power grid. Examples of such symmetric faults include, but are not limited to, line-to-line-to-line (LLLL) and line-to-line-to-line-to-ground (LLLG).

[0010] One of the techniques employed for detecting faults and / or protecting transmission lines from these faults involves what is commonly referred to as distance protection. In this case, short circuits on transmission lines can be detected based on the measurement of short-circuit impedance. To this end, a protection device, such as an IED, can measure the impedance up to the fault location. Based on this, a further determination can be made to determine whether the fault actually occurred within the transmission line or area to be protected by the protection device. If it is determined that the short circuit that has occurred is located on the line to be protected, the line in question is disconnected, and the faulty network section is isolated from the system.

[0011] As will also be understood, power transmission may include power generation from one or more sources. Currently, power generation may also involve renewable power sources, which may help reduce the inertia and transient stability margin of the power grid. Due to the impact on stability, high-speed protection is necessary. Conventional techniques for high-speed protection are based on certain time domain protection principles. Such techniques can also adopt high sampling rates and processing capabilities for high-speed line protection. This approach can generally reduce fault detection time, depending on the fault location and source-to-line impedance ratio. However, given that the participation of such renewable sources in the power grid is only going to increase, methods for detecting faults faster are desirable.

[0012] A method for detecting the occurrence of an electrical fault that may have occurred within a monitored area of a power transmission line is described. In one example, the occurrence of a fault in at least one phase of the power transmission line can be initially identified. Furthermore, the actual rate of change of a delta current and a delta voltage based on the calculated delta current and voltage is determined. The delta current corresponds to a current difference. Similarly, the delta voltage can be considered a value corresponding to a voltage difference. In this example, the current and voltage are measured at terminals of the power transmission line.

[0013] In the case of determining the actual rate of change of the incremental current, a threshold value for the rate of change of the incremental current can be further determined. The threshold value for the rate of change of the incremental current can be understood as the rate of change of the incremental current assuming a fault occurs at the zone boundary. The threshold value for the rate of change of the incremental current then forms the basis for determining whether the fault under consideration occurs at the zone boundary. In the example, the threshold value for the rate of change of the incremental current can be calculated based on the calculated incremental voltage, the calculated incremental current, the line parameters, and the zone setting of the monitored area. It can be noted that other parameters can also be used to calculate the threshold value for the rate of change of the incremental current. The zone setting (reachable range setting) is a setting that determines the scope of protection, i.e., the area that is expected to be covered by the protection and beyond which the protection will not operate. This can be in the form of a percentage of the transmission line length or impedance.

[0014] Thereafter, a further determination may be made to determine whether the fault has occurred within the monitored area. The monitored area may be considered to be a portion of the power transmission line monitored by an intelligent electronic device (IED). In an example, the determination may be based on a comparison of an actual rate of change of the incremental current and a threshold value for the rate of change of the incremental current. For example, an actual rate of change of the incremental current greater than the threshold value for the rate of change of the incremental current indicates a fault. On the other hand, if the actual rate of change of the incremental current is less than the threshold value for the rate of change of the incremental current, it may be concluded that the fault may have occurred outside the monitored area. Upon determining that the fault has occurred within the monitored area, a trip signal may be generated for controlling a switching device (e.g., a circuit breaker) associated with the power transmission line.

[0015] The described method also makes it possible to determine whether a fault has occurred within reach and should be corrected in a shorter time than conventional methods, thereby preventing any adverse effects of faults such as those arising due to saturation of current transformers. It has also been observed that a power transmission system implementing the present subject matter is able to detect and maintain stability in the event of a fault during power surge conditions. The manner of the steps mentioned above may vary in various examples without departing from the scope of protection sought. In conjunction with the attached Figures 1 to 5 These and other aspects are described in further detail.

[0016] Figure 1 A block diagram of an equivalent electrical grid 100 according to an example is provided. Grid 100 includes a transmission line 102 and dual power sources, namely, power sources 104 and 106. Transmission line 102 is also provided with one or more switching devices 108-1, 2, 3, 4, ..., N (collectively referred to as switching devices 108). Switching devices 108 allow circuits to be disconnected to limit the flow of excess current in the grid during a fault condition. It should be noted that the depicted electrical grid 100 is merely illustrative. Grid 100 may include additional components without departing from the scope of the present subject matter.

[0017] Grid 100 is also equipped with intelligent electronic devices 110 (referred to as IEDs 110). IEDs 110 can be in electrical communication with transmission lines 102, either directly or via other connections. During operation, IEDs 110 can receive and monitor measurements from one or more measuring devices. Examples of such measuring devices include, but are not limited to, current transformers and voltage transformers. Based on the received measurement data, IEDs 110 can generate one or more signals to control switchgear 108, as explained in the following paragraphs.

[0018] IED 110 also includes a phase selection module 112 and a fault detection module 114. Phase selection module 112 and fault detection module 114 can be implemented as software installed within IED 110, or as hardware in the form of electronic circuitry integrated within the circuitry of IED 110. This example is described with the consideration that power grid 100 is experiencing an electrical fault. When IED 110 is placed at terminal A within transmission line 102, the present subject matter is capable of detecting the occurrence of such a fault within the monitored area, enabling the acquisition of current signals from the measurement device. It should be noted that IED 110 can also be adapted to determine the occurrence of power oscillations without departing from the scope of the present subject matter.

[0019] In operation, the phase selection module 112 determines the occurrence of a fault within a particular phase of the transmission line 102. The manner in which the fault has occurred can be determined is further explained in conjunction with other figures. Once the fault has occurred within the phase, the IED 110 can further determine whether the fault has occurred within a monitored area of the power transmission line 102. In an example, the fault detection module 114 can determine whether the fault has occurred within the monitored area.

[0020] To this end, the fault detection module 114 can determine the values of the current and voltage at the terminals of the power transmission line 102. Based on the current and voltage values, the fault detection module 114 can further determine the delta current based on the change in the current measured at the terminals. In a similar manner, the delta voltage based on the change in voltage can also be determined.

[0021] Once the aforementioned delta value is determined, the fault detection module 114 may further calculate an actual rate of change of the delta current (referred to as the actual rate of change for simplicity) based on the determined delta current. Thereafter, the fault detection module 114 may further calculate a threshold value for the rate of change of the delta current (referred to as the rate of change threshold for simplicity). In an example, the threshold value for the rate of change of the delta current may be calculated based on the calculated delta voltage, the calculated delta current, and a line parameter (e.g., resistance or inductance) corresponding to the transmission line 102 present in the monitored area.

[0022] As previously mentioned, the rate-of-change threshold can be considered to be the rate of change of the incremental current that would exist if a fault had occurred at the zone boundary. In an example, the zone boundary can be a portion of the length of transmission line 102. In another example, the zone boundary can be defined as occurring at approximately 80% of the length of transmission line 102. It should be noted that this example of defining the length at which the zone boundary exists is merely illustrative. Any other metric for defining the location of the zone boundary can be used without departing from the scope of the present subject matter.

[0023] Returning to this example, once the actual rate of change of the incremental current and the rate of change threshold are obtained, the fault detection module 114 can further process them to obtain a processed actual rate of change of the incremental current and a processed rate of change threshold. In the example, the fault detection module 114 can calculate the root mean square value of the actual rate of change and the rate of change threshold to provide a processed actual rate of change and a processed rate of change threshold.

[0024] The fault detection module 114 can then evaluate whether the fault has occurred within the region boundary based on the processed actual rate of change and the processed rate of change threshold. For example, the fault detection module 114 can compare the processed actual rate of change with the processed rate of change threshold. If the processed actual rate of change is less than the processed rate of change threshold, the fault detection module 114 can indicate that the fault has occurred outside the monitored region boundary. However, if the processed actual rate of change is greater than the processed rate of change threshold, the fault detection module 114 can accordingly indicate that the fault has occurred within the monitored region boundary.

[0025] Upon determining that a fault has occurred within the boundaries of the monitored area, the fault detection module 114 may also generate one or more trip signals for a switching device 108 (e.g., a circuit breaker) that may be coupled to the transmission line 102 in question. Based on the trip signals, the switching device 108 may be activated to isolate the fault that has occurred within the boundaries of the monitored area. Figure 2 These and other examples are described further below.

[0026] Figure 2 A block diagram of an intelligent electronic device (IED) 110 according to one example is provided. The IED 110 includes a processor 202, an interface 204, and a memory 206. The processor 202 can be a single processing unit or can include multiple units, all of which can include multiple computing units. The processor 202 can be implemented as one or more microprocessors, microcomputers, digital signal processors, central processing units, state machines, logic circuits, and / or any device that manipulates signals based on operational instructions. Among other capabilities, the processor 202 is adapted to retrieve and execute processor-readable instructions stored in the memory 206 to implement one or more functions.

[0027] Interface 204 may include various software- and hardware-enabled interfaces. Interface 204 may enable communication and connectivity between IED 110 and other components of grid 100. Examples of such components include, but are not limited to, switchgear 108 and sensors. Interface 204 may facilitate various communications within various protocols and may also enable communication with one or more computer-enabled terminals or similar network components.

[0028] Memory 206 may be coupled to processor 202. Memory 206 may include any computer-readable medium known in the art, including, for example, volatile memory, such as static random access memory (SRAM) and dynamic random access memory (DRAM); and / or non-volatile memory, such as read-only memory (ROM), erasable programmable ROM (EPROM), flash memory, hard disks, optical disks, and magnetic tape.

[0029] The IED 110 may also include one or more modules 208. Modules 208 may be implemented as a combination of hardware and programming (e.g., programmable instructions) to implement the various functions of modules 208. In the examples described herein, this combination of hardware and programming may be implemented in several different ways. For example, the programming for modules 208 may be executable instructions. Such instructions may, in turn, be stored on a non-transitory machine-readable storage medium that may be directly coupled to the IED 110 or indirectly coupled (e.g., via a networked device). In examples implemented as hardware, modules 208 may include processing resources (e.g., a single processor or a combination of multiple processors) to execute these instructions. In this example, the processor-readable storage medium may store instructions that, when executed by the processing resource, implement modules 208. In other examples, modules 208 may be implemented by electronic circuitry.

[0030] Data 212 includes data stored or generated as a result of functions performed by any of the modules 208. It should also be noted that the information stored and available in data 212 can be used to detect areas within which a fault is about to occur. In this example, modules 208 include phase selection module 112, fault detection module 114, and other modules 210. Other modules 210 may implement functions that supplement the applications or functions performed by IED 110 or any of the modules 208. Data 212 may also include pre-fault loop voltage 214, pre-fault loop current 216, delta voltage 218, delta current 220, actual rate of change of delta current 222, threshold value 224 for rate of change of delta current, processed rate of change of delta current 226, threshold value 228 for rate of change of processed delta current, and other data 230. Furthermore, IED 110 may also include other components 232. Such other components 232 may include various other electrical components that implement functions for managing and controlling the operation of electrical network 100. Examples of such other components 232 include, but are not limited to, relays, controllers, switches, and voltage regulators.

[0031] IED 110 detects the occurrence of an electrical fault within a monitored area of a power transmission line within an electrical network, such as electrical network 100. Figures 3 and 4 The operation of the IED 110 is further described. Figures 3 and 4 A series of diagrams depicting current waveforms are provided. It should be noted that the waveforms depicted are merely schematic and may be relevant to this example. Depending on the implementation, the waveforms may vary slightly.

[0032] Returning to this example, the IED 110 can be connected to one or more measurement devices installed in the power grid 100 via the interface 204. As mentioned above, examples of such measurement devices include current transformers or voltage transformers. In operation, the phase selection module 112 can monitor current and voltage measurements corresponding to the three-phase current transmitted in the power grid 100 to identify the phase that has failed.

[0033] In an example, while monitoring the flow of current within the power grid 100, the phase selection module 112 is configured to determine the state of the start signal. Based on the state of the start signal, a phase selection step may be initiated. In an example, the phase selection module 112 may process a three-phase input current. Further, the phase selection module 112 may determine phase-phase quantities by calculating a moving average of the input current for each phase. Based on the moving average of the input current, the phase selection module 112 may determine one or more phase-phase quantities based on which the start signal may be generated. The moving average and the phase-phase quantities may be determined based on equations 1 through 6, as shown below:

[0034]

[0035]

[0036]

[0037]

[0038]

[0039] in, and is an instantaneous sample of the current;

[0040] k is the current sample; and

[0041] N is the number of samples per power cycle.

[0042] In one example, the current and The amplitude of the instantaneous sample and the threshold i th In one example, the threshold i th It can be 0.01. If the phase selection module 112 determines that the current and Any one of the th , a phase selection start signal can be generated.

[0043] Once the phase selection enable signal is generated, the fault detection module 114 may further calculate the value of the delta current. In an example, the delta of the electrical signal at any time is defined as the difference between the instantaneous amplitude of the signal at that time and the amplitude of the same signal at that time in the previous power cycle. In one example, the amount of delta is calculated for the phase current and the phase-to-phase current based on the following equation:

[0044]

[0045]

[0046]

[0047]

[0048]

[0049]

[0050] in, is the kth sample of the secondary current signal at terminal A, and where p represents the corresponding phase, p∈(a,b,c);

[0051] is the (kN)th sample of the current signal measured at terminal A;

[0052] N is the number of samples in a power cycle;

[0053] is the kth sample of the phase current increment, p∈(a,b,c); and

[0054] is the kth sample of the phase current increment, pp∈(ab,bc,ca)

[0055] Once the amount of the increment of the different current signals, i.e., the delta current, has been obtained, the phase selection module 112 may further process it. In one example, the phase selection module 112 may use a moving average filter to obtain the delta current. In one example, one or more steps are used to obtain the pre-processing. In the first step, the amount of the increment is passed through a moving average filter over a power cycle window to obtain a first absolute value. It is based on the following equation:

[0056]

[0057] Where N is the number of samples in a power cycle

[0058] is the kth sample of the output of the first moving average filter, p∈(a,b,c,ab,bc,ca)

[0059] In the second step, the output of the first moving average filter can be passed through a second moving average filter of a half power cycle window and a second absolute value will be obtained It is based on the following equation:

[0060]

[0061] Where N is the number of samples in a power cycle

[0062] is the kth sample of the output of the second moving average filter, p∈(a,b,c,ab,bc,ca)

[0063] Once the processing has been performed, the phase selection module 112 identifies the fault loop so that the maximum and minimum values in the phase and phase-phasor are identified for each sample. In one example, the maximum and minimum values in the phase and phase-phasor identified for each sample are based on the following equations:

[0064] For the maximum and minimum current values in a phasor:

[0065]

[0066]

[0067] For the maximum and minimum current values in a phase-phasor:

[0068]

[0069]

[0070] In one example, the fault in the loop may correspond to a single-phase fault or a phase-to-phase (i.e., three-phase) fault. To determine the type of fault, a comparison may be made between the determined absolute value and a predetermined value (i.e., ε, which is set to 0.001 in one example). To this end, the phase selection module 112 may define a counter value. In one example, the amplitude of the instantaneous sample of the current for each sample (i.e., ) is compared with a predetermined parameter ε. Based on the comparison, the phase selection module 112 can increase the counter value. Once the counter value exceeds a predetermined threshold, a single-phase fault or a three-phase fault can be identified.

[0071] The above method is described with reference to the following example. In this example, six counters are defined corresponding to each phase or phase-to-phase loop. For example, counters A, B, and C can correspond to phases a, b, and c. Additional exemplary counters AB, BC, and CA can be defined, where these respective counters correspond to phases ab, bc, and ca. The manner in which each of counters A, B, C, AB, BC, and CA is incremented can be determined based on the following equations explained below:

[0072] Increment counter A if:

[0073]

[0074]

[0075]

[0076] Increment counter B if:

[0077]

[0078]

[0079]

[0080] Increment counter C if:

[0081]

[0082]

[0083]

[0084] Increment counter AB if:

[0085]

[0086]

[0087] Increment counter BC if:

[0088]

[0089]

[0090] Increment the counter CA if:

[0091]

[0092]

[0093] if If each of the counters A, B, or C is less than ε, the phase selection module 112 can determine that a single-phase fault has occurred. Thereafter, the phase selection module 112 can further determine whether any of the counters A, B, or C has reached a predetermined counter limit to determine in which phase (i.e., phases a, b, or c) the fault has occurred. For example, if counter A reaches a predefined counter limit (e.g., 10), the phase selection module 112 can determine that a single-phase fault has occurred in phase a. Similarly, the phase selection module 112 can determine that the occurrence of a single-phase fault (i.e., a line fault) is in phase b or c based on the counter reaching the predetermined counter limit, and a trip signal can then be generated for the corresponding phase.

[0094] if If each of the counters AB, BC, or CA is greater than ε, the phase selection module 112 can determine the occurrence of a phase-to-phase fault or a three-phase fault. For example, if any of the counters AB, BC, or CA reaches a predetermined counter limit, the phase selection module 112 can conclude that a phase-to-phase fault or a three-phase fault has occurred in the corresponding phase-to-phase loop and can therefore generate a trip signal. It should be noted that the above examples are merely illustrative and are not the only way to identify a phase that has experienced a fault. Other examples for detecting the occurrence of a fault may also be utilized without departing from the scope of the present subject matter.

[0095] After detecting the occurrence of a fault, the fault detection module 114 can determine whether the fault in the power transmission line 102 has occurred within the boundaries of the monitored area. In the example, the fault detection module 114 receives measurements of the pre-fault loop voltage 214 and the pre-fault loop current 216. The fault detection module 114 can also obtain the current and voltage by measuring the current and voltage at the terminals of the power transmission line 102. In the example, waveforms 302 and 304 respectively depict the measured voltage and current in one example, as shown in FIG. Figure 3 A-3B. Further, the fault detection module 114 also receives measurements of a delta voltage 218 and a delta current 220, wherein the delta voltage 218 and the delta current 220 correspond to differences in voltage and current, respectively, measured during the fault and / or before the occurrence of the fault, based on the following equations:

[0096] Δi k =(i k -i k-N )………(34)

[0097] Δv k =(v k -v k-N )……(35)

[0098] in:

[0099] Δi k is the incremental current;

[0100] Δv k is the delta voltage;

[0101] k is the current sample; and

[0102] N is the number of samples in one cycle.

[0103] It may be noted that the above equations are merely illustrative, and the first set of equations may also be determined by other mechanisms.

[0104] Figure 3 C to Figure 3The waveforms corresponding to the delta voltage 218 and delta current 220 are further depicted in FIG. Figure 3 C to Figure 3 D is an exemplary graph depicting the delta voltage 218 and delta current 220 as waveforms 306 and 308. It should also be noted that the depicted graph is merely illustrative and corresponds to one of many other examples that fall within the scope of the present subject matter. Once the delta voltage 218 and delta current 220 are determined, the fault detection module 114 further processes the pre-fault loop voltage 214, the pre-fault loop current 216, the delta voltage 218, and the delta current 220 to reduce noise and thereby provide processed values of the pre-fault loop voltage, pre-fault loop current, delta voltage, and delta current. The pre-processing performed by the fault detection module 114 may be performed to smooth the samples in order to isolate errors that may be due to noise or any other undesirable components.

[0105] In an example, pre-processing may be performed by the fault detection module 114 based on the following equation:

[0106]

[0107]

[0108]

[0109]

[0110]

[0111] in

[0112] Δv lpma is the processed delta voltage;

[0113] Δi lplma is the processed incremental current across the inductive component of the transmission line;

[0114] Δi lprma is the processed incremental current across the resistive components of the transmission line;

[0115] is the processed pre-fault circuit voltage; and

[0116] is the processed pre-fault loop current.

[0117] Once the aforementioned values are obtained, the fault detection module 114 calculates the actual rate of change of the delta current 222 based on the processed delta current. The value of the actual rate of change of the delta current 222 can be calculated based on the following equation:

[0118]

[0119] Here, Δt is the time difference in seconds.

[0120] In addition to the above, the fault detection module 114 may also calculate a threshold value 224 for the rate of change of the incremental current based on the processed incremental voltage, the processed incremental current, and the voltage measured at the boundary of the monitored area (i.e., at the boundary A of the transmission line 102) before the fault occurs. In one example, the threshold value for the rate of change of the incremental current is calculated based on the following equation:

[0121]

[0122] where z b represents the boundaries of the monitored area, and

[0123] Where R1 and L1 are the positive sequence series resistance and inductance of the transmission line.

[0124] After calculation, the fault detection module 114 determines the RMS values of the rate of change of incremental current 222 and the threshold value of the rate of change of incremental current 224 to provide a processed rate of change of incremental current 226 and a processed threshold value of the rate of change of incremental current 228, which may be expressed as:

[0125]

[0126]

[0127] in describes the processed rate of change of current; and

[0128] A threshold value that describes the rate of change of the processed delta current.

[0129] Thereafter, the fault detection module 114 further determines whether a fault is about to occur in the monitored area based on a comparison between the processed rate of change 226 of the incremental current and the threshold value 228 for the rate of change of the incremental current. In one example, when the processed rate of change 226 of the incremental current is greater than the threshold value 228 for the rate of change of the incremental current, the fault detection module 114 identifies the occurrence of a fault within the monitored area. Conversely, when the processed rate of change 226 of the incremental current is less than the threshold value 228 for the rate of change of the incremental current, the fault detection module 114 indicates that the fault is occurring outside the monitored area. Figure 4 Waveforms 402 , 404 are shown in , which relate to a comparison between the processed rate of change of incremental current 226 and the threshold value 228 for the processed rate of change of incremental current.

[0130] In one embodiment, the proposed method is tested using specific examples such as CT saturation, power oscillation, and faults during power oscillation. Figures 5 to 7 These and other aspects are described in further detail.In one example, consider a fault scenario where a CT is saturated. Figure 5 The performance of the proposed algorithm for a fault example with CT saturation is shown. The test example has a fault with a low fault resistance of 0.1 ohm at 2% of the line (4 km for a 200 km line). In general, Figure 5 A shows the terminal current measured at the local terminal A as shown by waveform 502, Figure 5 B shows the amount of increase in current as shown by waveform 504, and Figure 5 C is the comparison of the actual rate of change of the current with the threshold value as shown in waveforms 506 and 508 respectively. It can be seen from these two waveforms that the fault current is as high as 10kA and the CT is saturated (as shown in Figure 5). Figure 5 B) the circled portion of the waveform depicted.

[0131] In another example, fault detection within a zone may occur during a power oscillation. Figure 6 The corresponding waveforms depicted during power oscillations are shown. Figure 6 A shows the terminal voltage during power oscillation as shown by waveform 602, Figure 6 B shows the terminal current during the power oscillation as shown by waveform 604, Figure 6 C shows the incremental current 220 during power oscillation, and Figure 6 D shows a comparison between the actual rate of change 222 of the incremental current, as shown in waveforms 606 and 608, respectively, and the rate of change threshold 224 of the incremental current. As can be seen from the waveforms, the rate of change of the current does not cross the threshold, and therefore the distance element does not operate. In yet another example, a power swing lockout function (e.g., implemented by IED 110) locks the distance relay to prevent operation during a power swing. However, if a fault occurs during a power swing, the distance protection of the transmission line will reliably operate. Figure 7 The corresponding waveform depicting a fault detected during power oscillation is shown. Currently, the unlocking function is used to detect the fault during power oscillation and unlock the distance relay. The proposed solution explained in the previous section does not require any locking during power oscillation. It works accurately for faults during power oscillation, such as Figure 7 The various waveforms are shown in Figure 2.

[0132] For example, Figure 7A shows the location of a fault to be identified within 20 km of a 200 km transmission line. In one example, the fault start time is 5 seconds as shown in waveform 702, and the detection time is approximately 5.002 seconds as shown in waveform 704. This analysis further indicates that a fault exists within the monitored area. It can be noted that Figure 7 The experimental image of A was captured within 2ms after the fault occurred. Figure 7 B shows the location of a fault to be identified within 100 km of a 200 km transmission line. In one example, the fault start time is 5 seconds as shown in waveform 706, and the detection time is approximately 5.003 seconds as shown in waveform 708. This analysis also indicates that a fault exists within the monitored area. It can be noted that Figure 7 The experimental image of B was captured within 3ms after the fault occurred.

[0133] Figure 7 C shows the location of a fault to be identified within 128 km of a 200 km transmission line. In one example, the fault start time is 5 seconds as shown in waveform 710, and the detection time is approximately 5.003 seconds as shown in waveform 712. This analysis also indicates that a fault exists within the monitored area. It can be noted that Figure 7 The experimental graph of C was captured within 3ms after the fault occurred. Figure 7 D shows the location of a fault to be identified within 128 km of a 200 km transmission line. In one example, the fault initiation time is 5 seconds, as shown in waveform 714, and the detection time is negligible, as shown in waveform 716. This analysis indicates that the fault occurred outside the monitored area. Therefore, this solution can potentially eliminate the need for power oscillation locking or unlocking of the Zone-1 distance relay.

[0134] Figure 8 A flow chart of a method 800 for detecting the occurrence of an electrical fault within a monitored area of a power transmission line in a power transmission system, according to one embodiment of the present subject matter, is shown. The order in which these methods are described is not intended to be construed as limiting, and any number of the described method blocks can be combined in any order to implement these methods or alternative methods. Additionally, the method 800 can be implemented by any suitable hardware, non-transitory machine-readable instructions, or a combination thereof, to process resources.

[0135] At block 802, the IED 110 receives measurements of the pre-fault loop voltage 214 and the pre-fault loop current 216. In one example, the measurements of the pre-fault loop voltage 214 and the pre-fault loop current 216 may correspond to initial values of current and voltage obtained from one end of the power transmission line.

[0136] At block 804, the IED 110 identifies the occurrence of a fault within a particular phase. In one example, the loop identification within a particular phase may correspond to each phase of one of the three-phase current or three-phase voltage. The occurrence of a fault within the loop may be identified based on predetermined conditions, as previously expressed in equations (19) to (33). Upon detection of the fault, a trip signal may be generated.

[0137] At block 806, the IED 110 determines measurements of the delta voltage 218 and delta current 220. In one example, the delta voltage 218 and delta current 220 may correspond to differences in voltage and current, respectively, measured during the fault and / or measured before the fault occurred. Equations based on this determination are shown in equations (34) to (35) above.

[0138] At block 808, the IED 110 calculates the actual rate of change of the incremental current 222 based on the processed incremental current. The processed incremental current is based on the incremental current 220. In one example, the processed incremental current is measured at the boundary of the monitored area before the fault occurs. The processed incremental current and the actual rate of change of the incremental current 222 are determined based on the equations expressed in the previous equations (36) to (41).

[0139] At block 810, the IED 110 further calculates a threshold value 224 for the rate of change of the incremental current based on the processed incremental voltage. In one example, the processed incremental voltage is measured at the boundary of the monitored area before the fault occurs. The threshold value 224 for the rate of change of the incremental current is determined based on the equation expressed in the previous equation (42):

[0140] At block 812, the IED 110 also determines whether a fault is about to occur in the monitored area based on a comparison between the processed rate of change of the incremental current 226 and the threshold value 228 of the rate of change of the incremental current. In one example, if the processed rate of change of the incremental current 226 is greater than the threshold value 228 of the rate of change of the incremental current, the fault detection module 114 indicates that a fault has occurred within the monitored area. Conversely, when the processed rate of change of the incremental current 226 is less than the threshold value 228 of the rate of change of the incremental current, the fault detection module 114 identifies that the fault has occurred outside the monitored area. The processed rate of change of the incremental current 226 and the threshold value 228 of the rate of change of the incremental current are determined based on the equations expressed in equations (43) and (44).

[0141] Although the embodiments of the present subject matter have been described in language specific to structural features and / or methods, it should be noted that the present subject matter is not necessarily limited to the specific features or methods described. Instead, the specific features and methods are disclosed and explained in the context of some embodiments of the present subject matter.

Claims

1. A method for protecting a power transmission line in response to a fault within a monitored area of a power transmission system, the method comprising: identifying the occurrence of a fault in at least one phase of a power transmission line; calculating an actual rate of change of the incremental current based on the calculated incremental current; setting a threshold value for calculating a rate of change of the incremental current based on the calculated incremental voltage, the calculated incremental current, line parameters, and the area of the monitored area; determining that the fault is in the monitored area based on a comparison of an actual rate of change of the incremental current and a threshold value of the rate of change of the incremental current; as well as Based on the comparison, a trip signal is generated for controlling a switching device associated with the power transmission line.

2. The method according to claim 1, wherein The calculated delta voltage and the calculated delta current correspond to differences in voltage and current, respectively, where the voltage and current are measured at terminals of the power transmission line.

3. The method according to claim 1 or 2, wherein: Calculating the actual rate of change of the incremental current further includes: processing the calculated delta current based on a moving average filter to provide a processed delta current; and An actual rate of change of the delta current is calculated based on the processed delta current.

4. The method according to claim 3, wherein: Use the following equations to determine the processed delta voltage and processed delta current: Where Δv lpma is the processed delta voltage; Δi lplma is the processed incremental current across the inductive component of the transmission line; Δi lprma is the processed incremental current across the resistive components of the transmission line; is the processed pre-fault circuit voltage; and is the processed pre-fault loop current.

5. The method according to claim 1, wherein The line parameters include resistance and inductance of the transmission line.

6. The method according to claim 1 or 2, wherein: Identifying the occurrence of the fault in at least one phase is based on a calculated delta current associated with one terminal of the power transmission line.

7. The method according to claim 1, wherein Determining the fault further includes: calculating a root mean square value of the actual rate of change of the incremental current and the threshold value of the rate of change of the incremental current to provide a processed actual rate of change of the incremental current and a processed threshold value of the rate of change of the incremental current; and The actual rate of change of the processed incremental current is compared to a threshold value for the rate of change of the processed incremental current.

8. The method according to claim 7, wherein: When the actual rate of change of the processed incremental current is greater than a threshold value of the rate of change of the processed incremental current, the fault has occurred.

9. An intelligent electronic device (IED) for protecting a power transmission line from a fault that has occurred in at least one phase of the power transmission line within a monitored area in a power transmission system, the IED being provided at one end of the power transmission line connecting at least two terminals to one or more power transmission lines, the IED comprising: microprocessor; Output interface: Phase selection module for: detecting the occurrence of a fault in at least one phase of the power transmission line; Fault detection module for: calculating a delta voltage and a delta current based on the voltage and current measured at terminals of the power transmission line; calculating an actual rate of change of the incremental current based on the calculated incremental current; setting a threshold value for the rate of change of the calculated incremental current based on the calculated incremental voltage, the calculated incremental current, line parameters, and the area of the monitored region; comparing an actual rate of change of the incremental current with a threshold value of the rate of change of the incremental current to determine that the fault is in a monitored area; as well as Based on the comparison, a trip signal is generated for controlling a switching device associated with the power transmission line.

10. The apparatus according to claim 9, wherein A fault detection module for calculating an actual rate of change of the delta current further processes the delta current based on a moving average filter to provide a processed delta current.

11. The apparatus according to claim 10, wherein Use the following equations to determine the processed delta voltage and processed delta current: Where Δv lpma is the processed delta voltage; and Δi lplma is the processed delta current across the inductive component of the transmission line; and Δi lprma is the processed incremental current across the resistive components of the transmission line; and is the processed pre-fault circuit voltage; and is the processed pre-fault loop current.

12. The apparatus according to claim 11, wherein The fault detection module calculates the actual rate of change of the delta current using the following equation: Among them, Δi lpl,a is the processed incremental current across the inductive component of the transmission line; and Δt is the interval between two consecutive samples.

13. The apparatus according to claim 11, wherein The fault detection module calculates the threshold value of the rate of change of the delta current using the following equation: Where Δv lpma is the processed delta voltage; Δi lprma is the processed incremental current across the resistive components of the transmission line; z b Indicates the boundary of the monitored area; R1, L1 are the positive sequence series resistance and inductance of the transmission line; and Further determine using the following equation:

14. The apparatus according to claim 12 or 13, wherein The rate of change of the processed incremental current and the threshold value of the rate of change of the processed incremental current are expressed as: as well as in describes the actual rate of change of the processed delta current; and in A threshold value describing the rate of change of the processed delta current.

15. The apparatus according to claim 14, wherein The fault detection module is configured to determine that a fault occurs within the monitored area when a rate of change of the processed incremental current is greater than a threshold value of the rate of change of the processed incremental current.

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