100 Questions on Relay Protection Knowledge

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1. What is a relay protection device? Answer: When faults occur in electrical components within the power system (such as generators, transmission lines, etc.) or in the power system itself, thereby jeopardizing its safe operation, a relay protection device is an automated measure and equipment capable of promptly sending warning signals to operating personnel, or directly issuing trip commands to the controlled circuit breakers to prevent further development of such events. Such devices are generally referred to as relay protection devices. 2. What are the tasks of relay protection in a power system? Answer: The basic tasks of relay protection are: (1) When a fault occurs in a component of the power system being protected, the relay protection device associated with that component must promptly and accurately send a tripping command to the circuit breaker closest to the faulty component, thereby disconnecting the faulty component from the power system in a timely manner. This helps to minimize damage to the power system components themselves, reduce the impact on the safe operation of the power system, and meet certain specific requirements of the power system (such as maintaining its transient stability). (2) It detects abnormal operating conditions of electrical equipment, and sends signals based on these abnormal conditions as well as the equipment’s operation and maintenance conditions (such as whether there are personnel on duty regularly), so that the on-duty staff can take action, the device can make automatic adjustments, or those electrical devices that, if continued to operate, could cause accidents can be disconnected. Relay protection devices that respond to abnormal operating conditions allow for operation with a certain delay. 3. Briefly describe the basic principles and configuration of relay protection. Answer: Relay protection primarily relies on changes in electrical quantities (such as current, voltage, power, frequency, etc.) that occur when components in the power system experience short circuits or other abnormalities, to establish the principle behind its operation. There are also other physical parameters, such as the large amount of gas generated in case of a fault inside the transformer tank, as well as increases in oil flow velocity or oil pressure. In most cases, regardless of the physical quantity being measured, relay protection devices consist of a measurement section (and setting adjustment section), a logic section, and an actuation section. 4. What are the basic requirements of power systems for relay protection? Answer: Relay protection devices must meet the requirements of reliability, selectivity, sensitivity, and speed. These four characteristics are closely related to one another, being both contradictory and unified. (1) Reliability refers to the ability to operate reliably when protecting that moving object. It should remain inactive when it is not supposed to move. Reliability is the most fundamental requirement for the performance of relay protection devices. (2) Selectivity means that the fault is first cleared by the protection of the faulty device or circuit itself; only when the protection or circuit breaker of the faulty device or circuit fails to operate is it allowed for the protection of adjacent devices, circuit protection, or failure protection of circuit breakers to clear the fault. To ensure the selectivity of protection devices that require coordination with adjacent equipment and lines, as well as of two components within the same protection system that need to work in coordination with each other (such as starting and tripping elements or blocking and operating elements), their sensitivity coefficients and operating times should generally be coordinated with one another. (3) Sensitivity refers to the requirement that, in the event of a metallic short circuit within the protected area of a device or circuit, the protective device must possess the necessary sensitivity factor; specific minimum sensitivity factors for various types of protection are specified in the regulations. The requirements for selectivity and sensitivity are met through the setting of relay protection. (4) Rapidity refers to the requirement that protective devices should extinguish short-circuit faults as quickly as possible. The purpose of this is to improve system stability, reduce the degree of damage to faulty equipment and lines, limit the scope of the fault’s impact, and enhance the effectiveness of automatic reclosing as well as the automatic activation of backup power sources or equipment. Generally, speediness is improved by measures such as installing high-speed protection devices (e.g., high-frequency protection and differential protection), fully utilizing the functions of zero-sequence ground instantaneous protection and interphase quick-break protection, and reducing the inherent operating time of relays as well as the circuit breaker tripping time. 5. How to ensure the reliability of relay protection? Answer: The reliability of relay protection is primarily ensured by reasonably configured relay protection devices with excellent quality and technical performance, as well as proper operation, maintenance, and management. No electrical equipment (lines, busbars, transformers, etc.) is allowed to operate without relay protection. All operating equipment in power grids of 220 kV and above must be protected by relay protection devices with two sets of independent AC and DC input and output circuits, each controlling different circuit breakers. When any set of relay protection devices or any group of circuit breakers fails to operate, another set of relay protection devices can be used to operate another group of circuit breakers in order to eliminate the fault. In all cases, it is required that the DC power supply for these relay protection devices and circuit breakers be supplied through separate fuses. 6. To ensure the selectivity of power grid relay protection, what requirements must be met for the step-by-step coordination between relay protections at different levels of the power grid? Answer: The setting of relay protections in upper and lower-level power grids (including those at the same level, as well as those one level above or below) should follow the principle of hierarchical coordination in order to meet the requirements of selectivity. That is, when a fault occurs in a lower-level circuit or component, the setting values of the relay protection for that faulty circuit or component must be compatible, both in terms of sensitivity and operating time, with those of the relay protection in the upper-level circuits or components, so as to ensure that faults can be selectively isolated when they occur in the power grid. 7. Under what circumstances is it permissible to sacrifice some of the selectivity of relay protection? Answer: It is permissible to sacrifice some of the selectivity of relay protection in the following situations: (1) For the feed lines connected to the supply transformers, whether there is one transformer in operation or multiple transformers operating in parallel (including cases where there are multiple T-connected supply transformers or feed lines), it is allowed to set the quick-acting protection on the line side to avoid faults on the other side of the transformer’s busbar. When necessary, the line quick-acting section protection can operate with a short time delay. (2) For series-fed power supply lines, if the operating time of the protection devices on the power source side is increased excessively in accordance with the principle of step-by-step coordination, certain intermediate substations with smaller capacity can be treated as T-connected substations or as non-coordinating points, thereby reducing the number of coordination levels and shortening the operating time. (3) The coordination of the internal protection for the double-circuit system can be determined based on the operation of the main protection for the double circuits (such as cross-link differential protection), or based on the conditions under which the zero-sequence current (or phase-current quick-break) protections on both sides will operate in the event of a fault in one of the circuits ； In cases of genuine difficulties, it is permitted for there to be a lack of coordination between the delay protection sections of the two circuits when one of them fails. (4) In the lines that form a ring network operation, it is allowed to designate a predetermined disconnection point or a single disconnection line. 8. To ensure sensitivity, how should the setting value of the last stage of ground fault protection be determined? Answer: The last stage of ground fault protection (for example, phase-zero current protection stage IV) should be set based on ground fault conditions corresponding to the grounding resistance value at the following short-circuit points: 100Ω for 220 kV lines ； 330 kV line, 150 Ω; 500 kV line, 300 Ω. Under the above conditions, the setting value of the operating current for the last stage of the zero-sequence current protection should not exceed 300A. When a high-resistance ground fault occurs at the end of a line, it is permissible for the line protection devices on both sides to operate sequentially to isolate the fault. For 110 kV lines, considering the requirements regarding operating sensitivity under potential high-resistance ground faults, the temporarily set current value for the final-stage zero-sequence current protection generally should not exceed 300 A (primary value). In such cases, it is permissible for the zero-sequence current protections on both sides of the line to operate sequentially in order to isolate the fault. 9. What is the typical maximum oscillation period considered for the system? Answer: Apart from the predetermined disconnection points, it is not allowed for protective devices to trip erroneously during system oscillations. In the absence of specific data for this power grid, except for the weak interconnection lines between regional systems, the maximum oscillation period of the system is generally assumed to be 1.5 seconds. 10. Briefly describe the basic principles and regulations for the setting calculation of relay protection in power grids of 220 kV and above. Answer: (1) For line relay protection in power grids with voltages of 220 kV and above, the near-backup principle is generally adopted. When a set of relay protection devices associated with a faulty component fails to operate, another set of independently operating relay protection devices takes action to isolate the fault. When a circuit breaker fails to operate, circuit breaker failure protection is activated, which shuts off all other circuit breakers that supply power to components connected to the faulty one. (2) For the protection of instantaneous faults or the duration of such protection, its setting value shall ensure reliable non-activation in the event of external faults outside the protected component, except in the case of unit or line transformer banks (including a line with two terminal transformers). (3) The setting of upper and lower-level relay protections should generally follow the principle of step-by-step coordination to meet the requirements for selectivity. That is, in the event of a failure in a lower-level component, the relay protection for that faulty component must be capable of coordinating with the relay protection of the upper-level component both in terms of sensitivity and operating time, so as to ensure selective isolation of the fault when it occurs in the power grid. (4) The setting calculation of relay protection shall be based on the normal operating mode. The so-called normal operating mode refers to the common operating mode as well as the normal maintenance operating mode when a line or a component adjacent to the protected equipment is under maintenance. For special operating modes, they can be handled temporarily in accordance with dedicated operating procedures or based on the actual conditions at the time. (5) The operation mode with the transformer neutral point grounded should be arranged in such a way as to maintain the substation’s zero-sequence impedance as constant as possible. In special operating conditions where the zero-sequence impedance of the substation changes significantly due to reasons such as transformer maintenance, temporary measures are taken based on the actual circumstances at that time. (6) The selection of fault types is based on the common faults of individual devices; generally, simple faults are used for the setting calculation of protection devices. (7) Sensitivity calibration verifies against the types of adverse faults under normal operating conditions, ensuring that the protection meets the specified sensitivity requirements both before and after the tripping of the circuit breaker on the opposite side. For longitudinal protection, it should have sufficient sensitivity when a metallic fault occurs at the end of the protected line (the sensitivity should be greater than 2). 11. How is the grounding method of the transformer neutral point generally determined? Answer: The selection of the transformer neutral point grounding method should aim to keep the zero-sequence impedance of the substation as constant as possible. In special operating conditions where the zero-sequence impedance of the substation changes significantly due to reasons such as transformer maintenance, temporary measures should be taken in accordance with regulatory requirements or the actual situation. (1) If a substation has only one transformer, its neutral point should be directly grounded. When calculating the normal protection settings, only the normal operating condition with the transformer’s neutral point grounded needs to be considered. During transformer maintenance, it can be handled as a special operating mode, such as by adjusting the settings or shutting down or activating the relevant protection functions as specified. (2) When a substation is equipped with two or more transformers, only one of the transformers should be operated with its neutral point directly grounded; when that transformer is taken out of service, the other transformer, whose neutral point is not grounded, should be switched to a direct-grounding mode. If, for some reason, the substation must operate with two transformers whose neutral points are directly grounded, then when one of these transformers with directly grounded neutral points stops operating, and if there is a third transformer available, that third transformer will be put into operation with its neutral point directly grounded as well. Otherwise, it will be handled in special operation mode. (3) In substations operating in double-bus configuration and equipped with three or more transformers, they should operate in such a way that the neutral points of two transformers are directly grounded, with these transformers connected to different buses. When one of the transformers whose neutral point is directly grounded comes out of service, the neutral point of the other transformer, which does not have its neutral point grounded, should be directly grounded. If it is not possible to maintain one grounding point on each different bus, it shall be treated as a special operating mode. (4) To improve the coordination of protection, when a short-circuit line is under maintenance and shut down, the impact of this shutdown on the distribution of zero-sequence current can be offset by increasing the number of neutral-point grounding transformers. (5) The neutral points of autotransformers and transformers with insulation requirements must be connected to ground directly for operation. 　　12. Briefly describe the configuration principles for 220kV line protection. 　　Answer: For 220 kV lines, when stability requirements or the proper setting of backup protection systems present difficulties, two sets of full-line quick-acting protection should be installed. As a backup protection for ground short circuits, stepped or inverse-time zero-sequence current protection can be used, or ground distance protection can be employed in combination with stepped or inverse-time zero-sequence current protection. Phase-to-phase short-circuit backup protection should generally be equipped with stepped distance protection. 　　13. Briefly describe the configuration principles for 330–500 kV line protection. 　　Answer: For 330-500 kV lines, two complete and independent full-line quick-acting protection systems should be installed. For backup protection against ground short circuits, stepped or inverse-time zero-sequence current protection can be installed; alternatively, ground distance protection can be used in combination with stepped or inverse-time zero-sequence current protection. Phased distance protection can be installed as a backup protection for interphase short circuits. 　　14. What is “remote backup”? What is “near backup”? Answer: “Remote backup” refers to the situation where, when a component fails and its protective device or switch refuses to operate, the protective devices of adjacent components on the same power supply side take action to isolate the fault ； “The \"near backup\" approach enhances the protection of the components themselves through a dual configuration; in the event of a fault within the area, there is no risk of protection failure. In addition, switch failure protection is installed so that it can be activated to open the high-voltage switches on the busbar of the same substation, or to remotely operate the switches on the opposite side, when the switches fail to trip. 　　15. What is line longitudinal protection and what are its characteristics? Answer: Line longitudinal protection is a protective device that causes the switches on both sides of the line to trip rapidly simultaneously when a fault occurs on the line; it serves as the main protection for the line. It uses a specific relationship between the discriminants on both sides of the line as a criterion. That is, the discrimination values are transmitted to the opposite side via channels on both sides, and then each side determines whether it is an internal fault or an external fault in the area based on the relationship between the discrimination values from the opposite side and those from its own side. Therefore, the discriminant and channels are the main components of the relay protection device. (1) Directional high-frequency protection compares the fault direction as seen at each end of the line in order to determine whether it is an internal or external fault. If the direction observed in the case of an internal fault in the protected line is taken as the positive direction, then in the case of an external fault in the protected line, the direction observed on one side will always be the opposite. Its characteristics are: 1) It requires that the forward discrimination triggering element have sufficient sensitivity to faults at the end of the line ； 2) A dual-frequency transceiver must be used. (2) Phase difference high-frequency protection is a high-frequency protection that compares the phases of the power frequency currents on both sides of the protected line. When the phases of the fault currents on both sides are the same, the protection is locked out. 1) It can detect various symmetric and asymmetric faults under full-phase conditions, and its installation is simple ； 2) Unreacting system oscillation. The protection can continue to operate under non-full-phase operation conditions and during single-phase reclosing ； 3) Not affected by breaks in the voltage circuit, 4) High requirements for the transceiver and channels; coordinated adjustment of the protections on both sides is necessary during operation ； 5) When the channel or transceiver is disabled, the entire protection system must be taken out of operation; therefore, a separate backup protection is required. (3) High-frequency blocking distance protection uses directional distance protection devices installed on the line as the primary protection, and adds corresponding transmitting and receiving equipment to form a longitudinal distance protection system through the communication channels. Its features are: 1) It can respond in a sufficient degree of sensitivity and speed to various symmetric and asymmetric faults ； 2) Still maintains the function of backup protection ； 3) When the voltage secondary circuit is disconnected, the protection will malfunction; therefore, disconnection locking measures must be taken to shut down the protection. 　　16. What are the different types of channels for interconnecting protection systems? Answer: They can be classified into the following types: (1) Power line carrier interconnecting protection (abbreviated as high-frequency protection). (2) Microwave longitudinal protection (abbreviated as microwave protection). (3) Optical fiber longitudinal protection (abbreviated as optical fiber protection). (4) Guide wire longitudinal protection (abbreviated as guide wire protection). 　　17. What types of signals are there in pilot protection? Answer: There are three types of signals in pilot protection: (1) Blocking signal. It is a signal that prevents protective actions from triggering a trip. In other words. The absence of an open circuit signal is a necessary condition for the protection to act to trip. Protection will trigger tripping only when both conditions are met: the operation of the local protection device and the absence of a lockout signal. (2) Permissible signals. It is a signal that allows the protection action to trigger a trip. In other words, the presence of a permissive signal is a necessary condition for the protection action to trip. Only when both conditions—the operation of the local protective element and the presence of a permissive signal—are met simultaneously, will the protection device trip. (3) Trip signal. It is the signal that directly causes a trip. At this point, it does not matter whether the protection element operates or not; as long as a trip signal is received, the protection will trigger a trip. Remote trip protection makes use of such trip signals. 　　18. Why are two start elements with different set values used in differential high-frequency protection? Answer: The start elements are used to activate the transmitter in the event of a fault in the power system, thereby enabling phase comparison. To prevent misoperation of the protection system in the event of an external fault, where the activation elements of the protective devices on both sides may not operate at the same time, it is necessary to first activate the phase comparison element on one side. If the transmitter on that side activates before sending a signal, the phase comparison function will be triggered, resulting in misoperation of the protection. Therefore, two activation elements with different set values must be used. A starter with a high set value activates the phase comparison element, while a starter with a low set value activates the transmitter. Since the low-set-value starting element operates before the high-set-value starting element, this ensures that in the event of an external short circuit, when the high-set-value starting element activates the phase comparison element, the protection will definitely receive a locking signal, preventing any false operation. 　　19. What are the advantages and disadvantages of phase difference high-frequency protection? Answer: Phase difference high-frequency protection has the following advantages: (1) It can detect various symmetric and asymmetric faults under full-phase conditions, and the device is relatively simple. (2) Unreacting system oscillation. The protection can continue to operate under non-full-phase operation conditions and during single-phase reclosing. 　　(3) The protection operation is basically independent of whether there are shunt capacitors and whether the protection gaps experience asymmetric breakdown. (4) Not affected by breaks in the voltage secondary circuit. 　　The disadvantages are as follows: (1) On high-load circuits, the load current changes the phase of the currents at both ends of the circuit, which is unfavorable for the operation of internal fault protection. 　　(2) When a phase is open-circuited and grounded, or when an internal fault occurs during partial-phase operation, the sensitivity deteriorates, and it may even fail to operate. 　　(3) It has high requirements for the channel and occupies a wide frequency band. During operation, the protection devices at both ends of the line need to be coordinated. 　　(4) The distributed capacitance of the line significantly affects the phase of the currents at both ends of the line, limiting the length of lines that can be used. 　　20. Briefly describe the basic working principle of the directional comparison high-frequency protection. 　　Answer: The basic working principle of the directional comparison high-frequency protection is to compare the direction of the fault as perceived on each side of the line, in order to determine comprehensively whether it is an internal or external fault of the protected line. If the direction observed in the case of an internal fault in the protected line is taken as the positive direction, then in the case of an external fault in the protected line, the direction observed on one side will always be the opposite. Therefore, in directional comparison high-frequency protection, the discriminating element is either an element that possesses directionality itself or a current element whose operating value can distinguish between faults in the forward and reverse directions. The so-called fault direction of the comparison circuit refers to comparing the operating behavior of specific distinguishing elements on both sides. 　　20. What is the important role of interlinking protection in power grids? Answer: Interlinking protection enables rapid response across the entire grid; it helps to maintain stability in the parallel operation of power systems, increases transmission capacity, reduces the extent of damage caused by faults, and improves the coordination between backup protection systems. 21. What is closed-loop directional high-frequency protection? Answer: In directional comparison high-frequency protection, the received signal is used for locking out the protection function; this is what is known as closed-loop directional high-frequency protection. Their positive direction detection elements do not operate, and no shutdown occurs; the receivers at both ends of the non-faulty line receive the locking signal, and the corresponding protection is locked out. 　　22. What is high-frequency blocking distance protection, and how does it work? Answer: High-frequency protection that operates by using a control transmitter to send out high-frequency blocking signals in order to disable the distance protection systems on both sides is known as high-frequency blocking distance protection. This type of protection enables fault isolation at any point along the protected line without any delay. 　　23. What are the advantages and disadvantages of high-frequency blocking distance protection? Answer: This protection has the following advantages: (1) It can respond to various symmetric and asymmetric faults in a sufficiently sensitive and rapid manner. (2) It can still maintain the function of remote backup protection (when sensitivity is available). (3) Not affected by the line distribution capacitance. 　　The disadvantages are as follows: (1) Series compensation capacitors can cause high-frequency blocking distance protection to operate erroneously or fail to operate. 　　(2) It will malfunction when the voltage secondary circuit is disconnected. Break-circuit locking measures should be taken to deactivate the protection. 　　24. What are the advantages and disadvantages of high-frequency blocking negative sequence direction protection? Answer: This protection has the following advantages: (1) The principle is relatively simple. It can correctly respond to various asymmetric short circuits under full-phase operation conditions. In the case of a three-phase short circuit, the protection can operate as long as the asymmetry time is greater than 5–7 ms. 　　(2) The system does not oscillate, nor does it exhibit stable three-phase short circuit. 　　(3) When the negative-sequence voltage and current are three times the starting value, the protection operation time is 10–15 ms. (4) Negative sequence direction elements generally have satisfactory sensitivity. (5) Lower requirements are placed on high-frequency transceivers. 　　The disadvantages are as follows: (1) In the case of a fault occurring under two-phase operation conditions (including during single-phase reclosing), the protection may fail to operate. 　　(2) The presence of line distributed capacitance causes the protection to possibly malfunction when the lines are closed under no-load conditions, as the three phases are not closed simultaneously. When the distributed capacitance is large enough, this protection will also malfunction in the event of an external short circuit, and compensation measures should be taken. 　　(3) On the series compensation line, as long as the series compensation capacitors do not experience asymmetric breakdown, the short-circuit protection in the full-phase operation mode can function correctly. When the series compensation capacitor is within its protection zone, system oscillations or external two-phase short circuits occur, and if the protection gap of the capacitor breaks down asymmetrically, the protection will malfunction. When the series compensation capacitor is located outside the protection zone, a protection failure may also occur in the event of a short circuit within the zone and asymmetric breakdown of the capacitor. 　　(4) When the voltage secondary circuit is disconnected, the protection should be taken out of service. 　　25. What is the effect of partial-phase operation on the high-frequency blocking negative-sequence power direction protection? Answer: When partial-phase operation occurs on the protected line, a longitudinal negative-sequence voltage is generated at the point of disconnection, which in turn gives rise to negative-sequence currents. At both ends of the transmission line, the direction of the negative-sequence power is negative, just as it is in the case of an internal fault. Therefore, in the condition of partial-phase operation with one side disconnected, the high-frequency blocking negative sequence power direction protection will malfunction. To overcome the aforementioned drawbacks, if the protection installation location is moved to the inside of the phase-loss point, the directions of the negative-sequence powers at both ends will be positive and negative respectively, just as in the case of an external fault. In this situation, the protection will be activated, but it will not malfunction due to the locking effect of high-frequency signals. Based on the above two scenarios, it can be seen that when the voltage transformer is connected to the line side, the protection device will not malfunction; whereas when the voltage transformer is connected to the substation bus side, the protection device will malfunction. At this point, measures must be taken to secure the lock. 　　26. What is the impact of disabling the line’s high-frequency protection on the use of reclosing? Answer: When the line’s high-frequency protection is disabled, it may affect the use of reclosing for that line for two reasons: (1) Without high-frequency protection in operation, backup protection (with a delay) must be used to eliminate faults on the line; this means that faults cannot be resolved quickly, resulting in a decrease in the system’s stability. If reclosing is attempted in the presence of a permanent fault, it will further compromise the stable operation of the system. (2) The setting of the reclosing time for line reclosing is coordinated with the line’s high-frequency protection. If the high-frequency protection is disabled, it results in a mismatch between the backup delay protection of the line and the reclosing time, which may lead to unsuccessful reclosing in the case of instantaneous faults, thereby imposing an additional stress on the system. 　　27. Why do operators need to exchange signals daily while high-frequency protection is in operation in order to check the high-frequency channel? Answer: In China, it is common to use a operating mode in which no high-frequency current flows through the high-frequency channel when the power system is operating normally. Since high-frequency channels involve equipment at two substations, the transmission lines spanning areas of several kilometers to hundreds of kilometers are subject to natural climate changes as well as wind, frost, rain, snow, and lightning. The aging and failures of various processing devices and transceiver components on the high-frequency channel can all cause attenuation ； Any issue in any link of the high-frequency channel can affect the proper operation of the high-value protection. When the system is operating normally, there is no high-frequency current in the high-frequency channel, and any issues with the equipment on that channel are not easily detectable. Therefore, daily, the operators use the start button to activate the high-frequency transmitter to send high-frequency signals to the opposite side. The high-frequency channel is checked by monitoring the corresponding current and voltage levels as well as the indicator lights on the transmitter and receiver, in order to ensure that the high-frequency part of the protection device can function reliably in the event of a fault. 　　28. What is zero-sequence protection? Why is it necessary to install separate zero-sequence protection in large-current grounding systems? Answer: When a grounding fault occurs in a system with high short-circuit currents, zero-sequence current, zero-sequence voltage, and zero-sequence power appear. Relay protection devices that utilize these electrical quantities to protect against ground faults are collectively referred to as zero-sequence protection. Although overcurrent protection for three-phase star connection can also protect against ground short circuits, its sensitivity is low and its protection time delay is long. This drawback can be overcome by using zero-sequence protection, because: ① During normal operation of the system as well as in the event of inter-phase short circuits, no zero-sequence current or voltage appears. Therefore, the operating current for zero-sequence protection can be set at a lower value, which helps to improve its sensitivity ； ②In a step-down transformer connected in Y/△ configuration, a fault on the △ side does not generate a zero-sequence current on the Y side; therefore, the operating time of the zero-sequence protection does not need to be synchronized with that of the line protection connected to this type of transformer, and it can have a shorter operating time. 　　29. Briefly describe the role of zero-sequence current direction protection in ground fault protection. 　　Answer: The zero-sequence current direction protection is a multi-stage current direction protection device that responds to the magnitude and direction of the zero-sequence current component when a ground fault occurs in a line. In the power lines of power grids at different voltage levels with high short-circuit currents in China, such ground protection devices are installed as basic protection in accordance with the regulations issued by the relevant authorities. Statistics on power system accidents show that in power grids with high-current grounding systems, line grounding faults account for 80% to 90% of all line faults. The correct operation rate of zero-sequence current direction grounding protection is approximately 97%, making it the type of protection with the highest correct operation rate among high-voltage line protections. Zero-sequence current direction protection boasts a series of advantages, including simple principle, reliable operation, low equipment investment, easy operation and maintenance, and a high correct operation rate. 　　30. What are the advantages of zero-sequence current protection? Answer: Directional and non-directional zero-sequence current protection are simple and effective methods for ground fault protection, and their advantages include: (1) A simple structure and working principle, with a higher correct operation rate compared to other more complex protections. 　　(2) The overall protection system has fewer intermediate stages, which enables rapid response, especially to faults that occur nearby, thereby helping to prevent the progression of such faults. 　　(3) Under the condition that the zero-sequence network of the power grid remains basically stable, the protection range is relatively stable. 　　(4) The protection reaction depends on the absolute value of the zero-sequence current and is less affected by the fault transition resistance. 　　(5) The protection setting value is unaffected by load current, and is also largely unaffected by short-circuit faults in other ungrounded neutral systems; therefore, a higher sensitivity for the protection delay time can be adopted. 21. What is closed-loop directional high-frequency protection? Answer: In directional comparison high-frequency protection, the received signal is used for locking out the protection function; this is what is known as closed-loop directional high-frequency protection. Their positive direction detection elements do not operate, and no shutdown occurs; the receivers at both ends of the non-faulty line receive the locking signal, and the corresponding protection is locked out. 　　22. What is high-frequency blocking distance protection, and how does it work? Answer: High-frequency protection that operates by using a control transmitter to send out high-frequency blocking signals in order to disable the distance protection systems on both sides is known as high-frequency blocking distance protection. This type of protection enables fault isolation at any point along the protected line without any delay. 　　23. What are the advantages and disadvantages of high-frequency blocking distance protection? Answer: This protection has the following advantages: (1) It can respond to various symmetric and asymmetric faults in a sufficiently sensitive and rapid manner. (2) It can still maintain the function of remote backup protection (when sensitivity is available). (3) Not affected by the line distribution capacitance. 　　The disadvantages are as follows: (1) Series compensation capacitors can cause high-frequency blocking distance protection to operate erroneously or fail to operate. 　　(2) It will malfunction when the voltage secondary circuit is disconnected. Break-circuit locking measures should be taken to deactivate the protection. 　　24. What are the advantages and disadvantages of high-frequency blocking negative sequence direction protection? Answer: This protection has the following advantages: (1) The principle is relatively simple. It can correctly respond to various asymmetric short circuits under full-phase operation conditions. In the case of a three-phase short circuit, the protection can operate as long as the asymmetry time is greater than 5–7 ms. 　　(2) The system does not oscillate, nor does it exhibit stable three-phase short circuit. 　　(3) When the negative-sequence voltage and current are three times the starting value, the protection operation time is 10–15 ms. (4) Negative sequence direction elements generally have satisfactory sensitivity. (5) Lower requirements are placed on high-frequency transceivers. 　　The disadvantages are as follows: (1) In the case of a fault occurring under two-phase operation conditions (including during single-phase reclosing), the protection may fail to operate. 　　(2) The presence of line distributed capacitance causes the protection to possibly malfunction when the lines are closed under no-load conditions, as the three phases are not closed simultaneously. When the distributed capacitance is large enough, this protection will also malfunction in the event of an external short circuit, and compensation measures should be taken. 　　(3) On the series compensation line, as long as the series compensation capacitors do not experience asymmetric breakdown, the short-circuit protection in the full-phase operation mode can function correctly. When the series compensation capacitor is within its protection zone, system oscillations or external two-phase short circuits occur, and if the protection gap of the capacitor breaks down asymmetrically, the protection will malfunction. When the series compensation capacitor is located outside the protection zone, a protection failure may also occur in the event of a short circuit within the zone and asymmetric breakdown of the capacitor. 　　(4) When the voltage secondary circuit is disconnected, the protection should be taken out of service. 　　25. What is the effect of partial-phase operation on the high-frequency blocking negative-sequence power direction protection? Answer: When partial-phase operation occurs on the protected line, a longitudinal negative-sequence voltage is generated at the point of disconnection, which in turn gives rise to negative-sequence currents. At both ends of the transmission line, the direction of the negative-sequence power is negative, just as it is in the case of an internal fault. Therefore, in the condition of partial-phase operation with one side disconnected, the high-frequency blocking negative sequence power direction protection will malfunction. To overcome the aforementioned drawbacks, if the protection installation location is moved to the inside of the phase-loss point, the directions of the negative-sequence powers at both ends will be positive and negative respectively, just as in the case of an external fault. In this situation, the protection will be activated, but it will not malfunction due to the locking effect of high-frequency signals. Based on the above two scenarios, it can be seen that when the voltage transformer is connected to the line side, the protection device will not malfunction; whereas when the voltage transformer is connected to the substation bus side, the protection device will malfunction. At this point, measures must be taken to secure the lock. 　　26. What is the impact of disabling the line’s high-frequency protection on the use of reclosing? Answer: When the line’s high-frequency protection is disabled, it may affect the use of reclosing for that line for two reasons: (1) Without high-frequency protection in operation, backup protection (with a delay) must be used to eliminate faults on the line; this means that faults cannot be resolved quickly, resulting in a decrease in the system’s stability. If reclosing is attempted in the presence of a permanent fault, it will further compromise the stable operation of the system. (2) The setting of the reclosing time for line reclosing is coordinated with the line’s high-frequency protection. If the high-frequency protection is disabled, it results in a mismatch between the backup delay protection of the line and the reclosing time, which may lead to unsuccessful reclosing in the case of instantaneous faults, thereby imposing an additional stress on the system. 　　27. Why do operators need to exchange signals daily while high-frequency protection is in operation in order to check the high-frequency channel? Answer: In China, it is common to use a operating mode in which no high-frequency current flows through the high-frequency channel when the power system is operating normally. Since high-frequency channels involve equipment at two substations, the transmission lines spanning areas of several kilometers to hundreds of kilometers are subject to natural climate changes as well as wind, frost, rain, snow, and lightning. The aging and failures of various processing devices and transceiver components on the high-frequency channel can all cause attenuation ； Any issue in any link of the high-frequency channel can affect the proper operation of the high-value protection. When the system is operating normally, there is no high-frequency current in the high-frequency channel, and any issues with the equipment on that channel are not easily detectable. Therefore, daily, the operators use the start button to activate the high-frequency transmitter to send high-frequency signals to the opposite side. The high-frequency channel is checked by monitoring the corresponding current and voltage levels as well as the indicator lights on the transmitter and receiver, in order to ensure that the high-frequency part of the protection device can function reliably in the event of a fault. 　　28. What is zero-sequence protection? Why is it necessary to install separate zero-sequence protection in large-current grounding systems? Answer: When a grounding fault occurs in a system with high short-circuit currents, zero-sequence current, zero-sequence voltage, and zero-sequence power appear. Relay protection devices that utilize these electrical quantities to protect against ground faults are collectively referred to as zero-sequence protection. Although overcurrent protection for three-phase star connection can also protect against ground short circuits, its sensitivity is low and its protection time delay is long. This drawback can be overcome by using zero-sequence protection, because: ① During normal operation of the system as well as in the event of inter-phase short circuits, no zero-sequence current or voltage appears. Therefore, the operating current for zero-sequence protection can be set at a lower value, which helps to improve its sensitivity ； ②In a step-down transformer connected in Y/△ configuration, a fault on the △ side does not generate a zero-sequence current on the Y side; therefore, the operating time of the zero-sequence protection does not need to be synchronized with that of the line protection connected to this type of transformer, and it can have a shorter operating time. 　　29. Briefly describe the role of zero-sequence current direction protection in ground fault protection. 　　Answer: The zero-sequence current direction protection is a multi-stage current direction protection device that responds to the magnitude and direction of the zero-sequence current component when a ground fault occurs in a line. In the power lines of power grids at different voltage levels with high short-circuit currents in China, such ground protection devices are installed as basic protection in accordance with the regulations issued by the relevant authorities. Statistics on power system accidents show that in power grids with high-current grounding systems, line grounding faults account for 80% to 90% of all line faults. The correct operation rate of zero-sequence current direction grounding protection is approximately 97%, making it the type of protection with the highest correct operation rate among high-voltage line protections. Zero-sequence current direction protection boasts a series of advantages, including simple principle, reliable operation, low equipment investment, easy operation and maintenance, and a high correct operation rate. 　　30. What are the advantages of zero-sequence current protection? Answer: Directional and non-directional zero-sequence current protection are simple and effective methods for ground fault protection, and their advantages include: (1) A simple structure and working principle, with a higher correct operation rate compared to other more complex protections. 　　(2) The overall protection system has fewer intermediate stages, which enables rapid response, especially to faults that occur nearby, thereby helping to prevent the progression of such faults. 　　(3) Under the condition that the zero-sequence network of the power grid remains basically stable, the protection range is relatively stable. 　　(4) The protection reaction depends on the absolute value of the zero-sequence current and is less affected by the fault transition resistance. 　　(5) The protection setting value is unaffected by load current, and is also largely unaffected by short-circuit faults in other ungrounded neutral systems; therefore, a higher sensitivity for the protection delay time can be adopted. 40. What are the basic requirements for automatic reclosing devices? Answer: There are the following basic requirements. (1) The reclosing circuit should not operate under the following conditions: 1) When the circuit is tripped manually by the operator or via a remote control device ； 2) Manual closing, when the protection trips immediately due to a fault on the line. (2) Except for the two situations mentioned above, whenever the circuit breaker trips due to relay protection action or other reasons, reclosing should occur to close the circuit breaker again. (3) The number of operations of the automatic reclosing device shall comply with pre-defined specifications; for example, only one reclosing attempt should be made, and a second reclosing is not allowed. (4) After operating, the automatic reclosing device should generally be able to return to its normal state automatically, ready for another attempt at reclosing in the event of a fault. (5) It should be able to work in conjunction with relay protection to enable the isolation of faults involving forward acceleration or backward acceleration. (6) When achieving reclosing on a circuit with dual power supplies, the synchronization issue between the two power supplies at the time of reclosing must be taken into account, so that voltage-free detection and synchronization detection can be carried out. (7) When the circuit breaker is in an abnormal condition (such as low air or hydraulic pressure) that prevents reclosing, the automatic reclosing function should be automatically locked out. (8) Automatic reclosing should be initiated based on the principle that the control switch position does not correspond to the circuit breaker position. 　　41. How are automatic reclosers classified? Answer: They are classified based on various characteristics, with the following being commonly used: (1) Classified by the type of operation, they can be divided into mechanical and electrical types. 　　(2) Based on the manner in which reclosing operates on the circuit breaker, it can be divided into three-phase, single-phase, and combined reclosing. 　　(3) Based on the number of actions, they can be divided into single-action and double-action (multiple-action) types. 　　(4) Based on the operating conditions of reclosing, it can be divided into single-side power supply reclosing and double-side power supply reclosing. Dual-power source reclosing can be further divided into voltage-free detection reclosing, synchronous reclosing detection, and asynchronous reclosing. 　　42. What are the general principles for selecting the reclosing method? Answer: The principles are as follows: (1) The reclosing method must be selected after analysis, based on the specific system structure and operating conditions. 　　(2) Where a simple three-phase reclosing method can meet the specific practical requirements, three-phase reclosing should be adopted for such lines. Especially in dense ring networks located in areas with centralized power supply, where the circuits can operate stably even after a circuit trip without reclosing, it is more appropriate to use three-phase reclosing with an appropriately set time. For such ring network circuits, quickly eliminating faults is the top priority. (3) In the event of a single-phase ground fault, if three-phase reclosing cannot ensure system stability, or if it would result in widespread power outages in the regional grid, or if important loads are affected by outages on certain lines, single-phase or combined reclosing should be employed. (4) Three-phase reclosing is generally not used at the outlet of large units. 　　43. What are the conditions for selecting three-phase reclosing for a circuit? Answer: After undergoing stability calculations, the conditions for selecting three-phase reclosing for circuits with single or double power sources are as follows: (1) Assume the nature of the power source circuit. On the power supply side of a single-sided power supply line, conventional three-phase reclosing is generally employed. In a power grid composed of several series-connected lines, in order to prevent the non-selective operation of instantaneous protection devices such as current quick-break protectors, three-phase reclosing is implemented using pre-accelerated or sequential reclosing methods; in this case, the disconnected lines are reclosed in sequence starting from the power supply side. However, for single-circuit lines that supply power to critical loads, integrated reclosing can also be employed to improve the reliability of power supply. (2) Dual power supply lines. When automatic reclosing is used for circuits with power supplies at both ends, it should be carried out under the condition that the circuit breakers on both sides of the circuit have been tripped, the arc at the fault location has been extinguished, and the insulation strength has been restored. At the same time, it is necessary to consider whether the power supplies on both sides of the circuit where the circuit breaker is performing reclosing are in phase, and whether out-of-phase reclosing is permitted. Therefore, the reclosing of bilateral power supply lines can be classified into one category: synchronism-based reclosing, such as reclosing that checks for the absence of voltage on one side, and reclosing that checks for synchronism or the current in parallel lines on the other side ； Another category consists of reclosing operations that are not performed synchronously, such as asynchronous reclosing, rapid reclosing, disconnection reclosing, and self-synchronizing reclosing. 　　44. What are the conditions for selecting single-phase reclosing or composite reclosing for a circuit? Answer: Single-phase reclosing refers to the situation where, in the event of a single-phase ground fault on a circuit, the protection device operates by opening only the circuit breaker of the faulty phase and then reclosing it in single phase ； When single-phase reclosing is unsuccessful or a multi-phase fault occurs, the protection activates to open the three-phase circuit breaker, and no further reclosing takes place. When the three-phase circuit breaker is tripped for any other reason, reclosing will not take place either. Integrated reclosing refers to the use of single-phase reclosing in the event of a single-phase ground fault, and three-phase reclosing in the case of an inter-phase short circuit. In the following situations, it is necessary to consider using single-phase reclosing or composite reclosing: (1) single-circuit tie lines at 220 kV and lower voltage levels, as well as lines with weak connections between the power sources on either side (including electromagnetic loop networks connected via lines at a lower voltage level), especially the high-voltage output lines of large steam turbine generators. 　　(2) When a single-phase ground fault occurs in the power grid, lines for which three-phase reclosing cannot ensure system stability. 　　(3) For lines where three-phase reclosing is permitted, a combined reclosing method can be adopted when single-phase reclosing yields better results for the system or power restoration. For example. In double-circuit lines with close connection between the two power sources or in parallel-operating ring networks, if stability calculations show that reclosing in the presence of a three-phase permanent fault will not lead to stability failure, a composite reclosing method can be employed. When three-phase auto-reclosing is employed. A scheme that involves closing one side first, and waiting for the other side to close after synchronization is achieved before performing synchronous reclosing. 　　(4) Upon verification through stability calculations, the use of auto-reclosing is permitted. 　　45. What are the adverse effects on the power system when reclosing fails due to a permanent fault? Answer: When reclosing fails because of a permanent fault, there are mainly two adverse effects: (1) The power system is subjected to the impact of the fault once again ； (2) It makes the operating conditions of the circuit breaker more severe, as the circuit breaker has to extinguish the arc twice in a very short period of time. 　　46. What are the advantages and disadvantages of single-phase reclosure and three-phase reclosure respectively?
Answer: The advantages and disadvantages of these two reclosure methods are as follows: (1) When single-phase reclosure is used, unipolar operation occurs. Apart from the fact that some special considerations must be taken into account for pilot protection, this has a significant impact on the setting and coordination of zero-sequence current protection. As a result, zero-sequence current protection for medium- and short-length lines cannot function effectively. (2) When three-phase reclosing is used, the output circuits of various protections can directly act on the circuit breaker. When using single-phase reclosing, in addition to protective devices that have phase selection capabilities. All types of protection, such as interconnection protection, phase-to-phase distance protection, and zero-sequence current protection, must be controlled by the phase-selecting element of single-phase reclosing in order to operate the circuit breaker. (3) When three-phase reclosing is performed after a single-phase ground fault occurs in the line, it generates higher operating overvoltage compared to single-phase reclosing. This is due to three-phase tripping and power interruption at the zero crossing of current; residual charge voltage equivalent to the peak phase voltage remains on the non-faulty phases. Since the power interruption duration during reclosing is short, the voltage on these non-faulty phases does not change much, which results in high operating overvoltage during reclosing. When single-phase reclosing is used, the voltage of the faulty phase during reclosing is generally only around 17% (due to the voltage division caused by the capacitance of the line itself), so there is no issue with operating overvoltage. Based on the long-term operation experience of three-phase reclosing in 110 kV and 220 kV power grids, problems related to switching overvoltages in medium and short circuits are generally not significant. (4) When three-phase reclosing is used, under the most unfavorable conditions, it is possible for the system to reclose onto a three-phase short-circuit fault. In those circuits where stability calculations indicate that such a situation must be avoided, it is possible to incorporate simple elements for detecting inter-phase faults into the three-phase reclosing system, so that reclosing does not occur in the case of a single-phase fault, and no reclosing takes place either in the event of an inter-phase fault. 　　47. What are the various ways to initiate automatic reclosing? What are their respective characteristics? Answer: There are two startup methods for automatic reclosing devices: the startup method where the position of the circuit breaker control switch does not match the actual position of the circuit breaker, and the protection-based startup method. Advantages of not using the starting mode: It is simple and reliable; it can also correct situations where circuit breakers are accidentally operated or trip unintentionally. This helps enhance power supply reliability and the stability of system operation. It performs well in power grids at all levels, and is the fundamental starting mode for all auto-reclosing operations. Its drawback is that when the auxiliary contacts of the circuit breaker are in poor contact, the corresponding starting mode will become ineffective. The protection start mode is a supplement to the normal start mode. At the same time, during the single-phase life shutdown process, certain protective interlocks are required; the logic circuit needs to enable phase selection for the faulty phase, and a reclosing trigger element for protection activation is also needed. Its drawback is that it cannot correct false trips of circuit breakers. 　　48. Why are synchronization and voltage-free relays installed on both sides in devices for testing synchronization and voltage-free reclosing? Answer: If a wiring scheme is used in which voltage-free testing is carried out on one side while synchronization testing is done on the other side, then when the circuit breaker on the side where voltage-free testing is performed trips under normal operating conditions due to some reason (such as accidental operation or faulty protection), since the relay on the opposite side does not activate, there is still voltage in the line, and thus reclosing cannot take place. This represents a significant drawback. To solve this problem, a synchronizing relay is usually also installed on the side without pressure for simultaneous testing; the contacts of both relays operate in parallel, which allows the circuit breaker to be reactivated after an incorrect tripping. To ensure that the operating conditions of the circuit breakers on both sides are identical, a no-voltage testing relay is also installed on the testing interval side; it is used according to specific circumstances after switching. It should be noted that when a pressure-free calibration relay and a synchronization calibration relay are installed on one side, only a synchronization calibration relay can be installed on the other side. Otherwise, achieving voltage-free reclosing on both sides simultaneously will result in asynchronous closing. During the periodic testing of the relay contact circuit, contacts that are under voltage in the testing circuit must be connected in series. 　　49. What are the principles for selecting the reclosing method for single-side power supply transmission lines? Answer: The principles for selecting the reclosing method for single-side power supply transmission lines are as follows: (1) Under normal circumstances, three-phase single-reclosing is used. 　　(2) When the interrupting capacity of the circuit breaker permits, secondary reclosure may be employed under the following circumstances ； 　　1) A single-circuit line without remote control, leading from a substation without regular on-duty personnel ； 　　2) Single-circuit lines that supply power to critical loads without a backup power source. 　　(3) After verification through stability calculations, reclosing is permitted. 50. What are the special requirements for reclosing in double-fed power supply lines? Answer: In addition to meeting the basic requirements for automatic reclosing devices, reclosing in double-fed power supply lines must also ensure that: (1) when a fault occurs on the line, the protection devices on both sides may operate to trip the circuit breakers at different times; therefore, the reclosing mechanism on each side of the line must wait until both circuit breakers have tripped before attempting to restart power supply. (2) After a fault causes a trip on the line, there are often issues regarding whether the power supplies on both sides are in phase at the time of reclosing, and whether asynchronous closing is permissible. 59. If the secondary load impedance of a current transformer exceeds its allowable value, why does the accuracy decrease? Answer: The value of the secondary load impedance has a significant impact on the accuracy of the current transformer. This is because if the secondary load impedance of the current transformer increases significantly, exceeding the allowable value, the magnitude of the excitation current will **rise**, causing the core to enter a saturated state. In such a situation, a large portion of the primary current is used to supply the excitation current, which in turn leads to a substantial increase in the transformer’s error and a decrease in its accuracy. 　　60. Why is it necessary to strictly prevent an open circuit on the secondary side of a current transformer during operation? Answer: During normal operation, the magnetic flux generated by the secondary current acts to counteract the magnetic flux produced by the primary current; as a result, the excitation current is very small, the total magnetic flux in the core is minimal, and the induced electromotive force in the secondary winding does not exceed a few dozen volts. If the secondary side is open-circuited, the demagnetizing effect of the secondary current disappears, and the primary current becomes entirely an excitation current. This leads to a sharp increase in the magnetic flux within the core, causing it to reach a highly saturated state. Moreover, due to the large number of turns in the secondary winding, according to Faraday’s law of electromagnetic induction (V = 4.44/fNB), very high voltages (even several thousand volts) can be generated across the secondary winding. This not only may damage the insulation of the secondary winding but also poses a serious threat to human safety. Furthermore, the sharp increase in magnetic flux density leads to increased core losses, severe heating, and even damage to the insulation. Therefore, an open circuit on the secondary side of the current transformer is absolutely not allowed; it is a major taboo for electrical testers. For the above reasons, fuses cannot be installed in the secondary circuit of current transformers ； The secondary circuit is generally not switched. 61. Why is it necessary to strictly prevent short circuits on the secondary side of a voltage transformer during operation? Answer: A voltage transformer is a voltage source with extremely low internal resistance. Under normal operating conditions, the load impedance is very high, resulting in an open-circuit condition; thus, only a very small load current flows on the secondary side. When a short circuit occurs on the secondary side, the load impedance becomes zero, which leads to a large short-circuit current that can damage the voltage transformer. Therefore, a short circuit on the secondary side of the voltage transformer is another major pitfall for electrical testers. 　　62. For lines and transformers equipped with reclosing devices, under what circumstances is reclosing not allowed or impossible after their circuit breakers trip? Answer: There are 9 such circumstances in which reclosing is not allowed or impossible. 　　(1) Manual trip. (2) Tripping due to circuit breaker failure protection activation. (3) Remote tripping. (4) The circuit breaker trips when the operating air pressure drops below the allowable value. (5) Trip when reclosing is disabled ； (6) Reclosing is in the single-phase reclosing mode when tripping occurs on all three phases. (7) Trips again due to a permanent fault. (8) When bus protection tripping occurs and bus reclosing is not allowed. (9) Transformer differential and gas protection tripping is correct. 　　63. What are the basic technical performance requirements for the “four-unification” integrated reclosing device? Answer: The technical performance requirements for the unified wiring design of the integrated reclosing device are as follows. (1) The device, as selected by the operating crew, should be capable of implementing the following reclosing modes. 1) Single-phase reclosing mode: When a single-phase fault occurs in the line, the faulty phase is disconnected, enabling one attempt at single-phase reclosing ； When various inter-phase faults occur, the three phases are disconnected without reclosing. 2) Three-phase reclosing mode: When various types of faults occur in the line, all three phases are disconnected, enabling one-time three-phase reclosing. 3) Comprehensive reclosing mode: When a single-phase fault occurs in the line, the faulty phase is disconnected, enabling a single-phase reclosing attempt ； When various inter-phase faults occur in the circuit, the three phases are disconnected to achieve one-time three-phase reclosing. 4) Disable reclosing mode: When various faults occur in the line, the three phases are disconnected without attempting reclosing. 　　(2) There are two circuits for initiating reclosing: 1) the circuit for initiation when the circuit breaker position does not match. 2) Protect the trip start circuit. (3) Protection tripped by the reclosing device can be connected to the following circuits separately. 1) Protection trip circuits that can continue to operate during the reclosing process. 2) It is locked out during the reclosing process; the protection trip circuit is activated only after it is determined that the line has been reconnected to the fault or that both sides of the line are operating in a full-phase mode. 3) The circuit that directly cuts off the three phases after a protection action to perform a single reclosure. 4) Immediately cut off the triphasic non-coincident trip circuit after the protection action (can be installed in the operation relay box). (4) The phase selection element can be chosen by the user as one of the following two types. 1) Phase selection element: its actuator contacts can be connected directly to the wiring circuit of the reclosing device, or independent contacts can be provided as needed. 2) Phase current difference variation phase selection element: it ensures phase selection for tripping during delayed-time protection operation ； The post-acceleration contacts resulting from a re-fault of a non-faulty phase under partial-phase operation are also fed into the logic circuit of the reclosing mechanism, along with the contacts that control three-phase tripping. (5) Equipped with a three-phase current element, it can be used for time-independent current quick-break tripping, or it can be modified to function as an auxiliary phase selection element to accelerate the process after manual closing. Depending on the user’s requirements, three low-voltage components can also be used as auxiliary phase-selection elements. And for the pair of circuit breakers that trigger the final trip in case (6), the time interval from the issuance of the trip pulse to the issuance of the close pulse must also be no less than 0.3 s. The closing pulse time must be stable and should be shorter than the circuit breaker’s closing time. (7) Achieve phase-separated acceleration coinciding with the ground fault, and permanently disconnect the three phases after a short delay. (8) Current elements used to determine full-phase operation of the line should have good capability to avoid the transient currents resulting from line charging, thereby preventing contact vibration under normal conditions. (9) When selecting phase-selecting components, a circuit that operates independently during reclosing should be provided (when line voltage transformers are used, the independent operation of the phase-selecting components is not considered). When using a phase current difference transient-based phase selection element, an instantaneous post-acceleration circuit should be prepared to handle the re-fault of the non-faulty phase during single-phase reclosing. 　　(10) When single-phase reclosing is used and the phase-selecting element fails to operate, the three phases should be disconnected as soon as possible. (11) The primary reclosing function of the recloser device is composed of a capacitor charging and discharging circuit. (12) When any component in the reclosing device is damaged or malfunctioning, the wiring shall ensure that the following does not occur: 1) multiple reclosures. 2) Prohibit three-phase reclosing in a mode that does not allow three-phase reclosing. (13) There should be independent three-phase tripping elements and phase-separated tripping elements, which serve as backups for each other in terms of three-phase tripping ； The time from the start of protection (measured as the shortest time from fault occurrence, 20–25 ms) to the issuance of the phase-selective trip pulse by the reclosing device is not more than 10 ms. (14) The grounding detection element is less than 15 ms at 2 times the operating start value. (15) According to operational requirements, two different reclosing times can be set, and this can be done via toggle switches. (16) The device shall be equipped with three-phase reclosing control elements and circuits for checking synchronization and testing voltage; it can also be switched to a circuit without any control. (17) There are relevant circuits for permitted reclosing and locked reclosing, etc., adapted to the performance of the circuit breaker, along with monitoring signals; some of these components can be installed within the operating relay box. (18) Provide the contacts required for inter-phase distance protection, zero-sequence current direction protection, and high-frequency protection. (19) Output separately the single-phase and three-phase trip contacts before reclosing, as well as the trip contact after reclosing. (20) Considering the circuit for activating the breaker failure protection, which is determined by the phase-to-phase current and involves the series connection of the contacts of the outlet trip relay, the three-phase permanent trip circuit should also have an appropriate circuit to activate the failure protection. (21) The holding circuits for the circuit breaker’s opening and closing coils shall be designed in coordination with the circuit breaker’s operating circuit, and corresponding requirements shall be specified. (22) Consider the convenience and feasibility for the operating crew to disable protections by operating the push-buttons. (23) Consider the specific design of the wiring circuit in accordance with the principle of testing the reclosing device when the circuit breaker is de-energized. (24) Specify the power consumption of the current circuit and voltage circuit of the entire setup. 　　64. What issues should be considered during the comprehensive reclosing circuit testing? Answer: The wiring of the circuits for comprehensive reclosing is complex. During testing, in addition to following the device’s technical specifications and the inspection procedures for relevant components, it is essential to emphasize the need to conduct a full-scale test. This test cannot be simulated by using certain contacts or circuits in a short-circuit circuit; instead, corresponding currents and voltages must be applied at the input terminals of the voltage and current transformers to simulate various possible faults. The test should also be carried out in conjunction with the protections related to reclosing. Finally, a comprehensive test must be carried out with the protection system, reclosing device, and circuit breakers operating in phase coordination. 　　65. What are the measures for blocking reclosing in a reclosing device? Answer: The various measures for blocking reclosing are: (]) When the reclosing mode is disabled, reclosing is directly blocked. (2) During manual tripping, reclosing is directly locked out. (3) When the protection trips without a reclosing attempt, lock out reclosing. (4) When using the single-phase reclosing mode, the circuit breaker trips three times; the reclosing is locked out by the contacts of the position relay ； During protection against three-phase short circuits, the reclosing is locked out; when the air or hydraulic pressure of circuit breaker (5) drops to a level that does not permit reclosing, reclosing is blocked. 　　66. What relays are generally used to make up the “four-unification” control box? Answer: The control relay box is composed of the following relays. 　　(1) Closing position relay for monitoring the circuit that closes the circuit breaker, and relay for monitoring the tripping position of the circuit breaker. (2) Relay to prevent the circuit breaker from bouncing. 　　(3) Manual closing relay. 　　(4) Pressure monitoring or lockout relay. (5) Manual trip relay and protective phase trip relay. (6) Single reclosing pulse circuit. (7) Auxiliary intermediate relay. (8) Trip signal relay and standby signal relay. 　　67. In the integrated reclosing device. Usually, two types of reclosing times are used, namely “short delay” and “long delay”. Why is that? 　　Answer: This is to allow the synchronization times for three-phase and single-phase synchronization to be set separately. Due to the effect of stray supply current, the time required for single-phase reclosing is generally longer than that for three-phase reclosing. Additionally, different reclosing times can be used when the high-frequency protection is activated or deactivated. When high-frequency protection is activated, the reclosing time should be set to \"short delay\"” ； When the high-frequency protection is out of service, the reclosing time is set to a \"long delay\". 　　68. What is the role of voltage switching in a double-bus system? Answer: For the electrical components connected to a double-bus system, when the two bus sets operate separately (for example, when the bus tie circuit breaker is open), it is necessary to ensure that the primary and secondary systems maintain corresponding voltages, in order to prevent misoperation or failure to operate of protective and automatic devices. Therefore, the secondary voltage circuits of these protective and automatic devices must also be switched along with the main wiring. The two auxiliary contacts of the isolating switch are connected in parallel to activate the voltage switching relay, whose contacts are used to achieve automatic switching of the voltage circuit. 　69. What safety considerations should be taken into account for voltage switching circuits? What are the advantages and disadvantages of manual and automatic switching methods? Answer: When designing manual and automatic voltage switching circuits, it is necessary to effectively prevent reverse charging of voltage transformers that have lost power on the primary side during the switching process. Secondary back-charge of voltage transformers can cause serious accidents to personnel and equipment. To this end, the switching circuit should use a wiring method that first disconnects and then reconnects. While disconnecting the voltage circuit, the positive power supply for the relevant protection should also be disconnected at the same time. Voltage circuit switching can be done manually or automatically, each with its own advantages and disadvantages. Manual switching: the switch is installed indoors, offering favorable operating conditions and a high reliability for the switching circuit. However, manual switching increases the operational workload for the staff, and it is easy to cause incorrect switching or forgetting to switch, leading to accidents. To improve the reliability of manual switching, dedicated operating procedures should be established to clearly specify the operational steps to be followed by the operators. Automatic switching can reduce the operational workload for operators, and it also makes it less likely to occur errors or oversights related to switching. However, the auxiliary contacts of the isolating switch have low reliability due to the poor operating conditions, and they often fail, which affects the reliability of the switching circuit. To improve the reliability of automatic switching, high-quality auxiliary contacts for isolating switches should be used, along with regular maintenance. 70. What is the function of the trip position relay and the close position relay? 　　Answer: Their functions are as follows: 1) They can indicate the opening and closing positions of the circuit breaker; if operation is done phase by phase, they can also show the opening and closing signals for each phase. 　　2) It can indicate a mismatch in the circuit breaker’s position or show whether the circuit breaker is operating in a non-full-phase condition. 　　3) The reclosing circuit can be activated by the contacts of a certain phase of the trip position relay. 　　4) Disable the high-frequency protection signal during three-phase tripping. 　　5) In single-phase reclosing mode, three-phase reclosing is locked out. 　　6) Send out control circuit open signal and emergency audio signal. 　　71. What is the fully differential protection for busbars with fixed connection methods? What is busbar differential protection based on current phase comparison for busbars? 　　Answer: In the dual-bus operation mode, in accordance with certain requirements, the leads and branches connected to a power source are fixedly connected to the two buses; such buses are referred to as fixedly connected buses. The differential protection for this type of bus is called full differential protection for buses with fixed connections. The requirement for it is that in the event of a fault in any bus, only the components connected to that bus are disconnected, while the other bus can continue to operate; the bus differential protection has the capability to identify the faulty bus. When the fixed connection between the two buses in operation is disrupted, this protection will lose the ability to identify which bus is faulty, and instead will disconnect all components connected to both buses. The bus differential protection based on current phase comparison uses directional elements on the busbar circuit breaker to compare the phases of the currents; one of the current values taken into account is the vector sum of the currents of all components connected to the busbar, that is, the differential current. 72. What is a reactance transformer? What is the difference between it and a current transformer? Answer: A reactance transformer is an intermediate conversion device that converts input current into output voltage; it also serves as an isolation element, ensuring a linear relationship between the input current and the output voltage. A current transformer is a conversion device for changing current. It converts high voltage and large current into low voltage and small current, with a linear transformation; therefore, it requires a high excitation impedance, that is, a low excitation current and a low load impedance. A reactive transformer is exactly the opposite of that. The excitation current of a reactance transformer is high, the secondary load impedance is high, and it operates in an open-circuit condition ； The secondary load impedance of the current transformer is much smaller than its excitation impedance, resulting in a short-circuit operating condition. 　　73. What are primary electrical equipment and primary circuits? What are secondary electrical equipment and secondary circuits? Answer: Primary equipment refers to high-voltage electrical devices that directly generate, transmit, and distribute electrical energy. It includes generators, transformers, circuit breakers, isolators, automatic switches, contactors, knife switches, busbars, transmission lines, power cables, reactors, motors, etc. An electrical circuit formed by the interconnection of primary equipment for power generation, transmission, distribution, or other forms of production is referred to as a primary circuit or primary wiring system. Secondary equipment refers to low-voltage electrical devices that are used to monitor, control, regulate, and protect the operation of primary equipment, as well as to provide operators and maintenance staff with information on operating conditions or commands for production. Such as fuses, control switches, relays, control cables, etc. An electrical circuit formed by the interconnection of secondary devices, which is used to monitor, control, regulate, and protect primary devices, is referred to as a secondary circuit or secondary wiring system. 　　74. Which circuits belong to the secondary circuits connected to protection devices? Answer: The secondary circuits connected to protection devices include the following: (1) The circuits that start from the secondary side terminals of current transformers and voltage transformers and lead to the secondary circuits of the relevant relay protection devices (for multi-oil circuit breakers or transformer bushing transformers, it starts from the terminal box). (2) From the relay protection DC branch fuse to the secondary circuit of the relevant protection device. (3) The DC circuit from the protection device to the control panel and the central signal panel. (4) The trip and close circuits from the relay protection device’s output terminal block to the circuit breaker operation box’s terminal block. 　　75. Illustrate the importance of the secondary circuit with examples. 　　Answer: Failures in the secondary circuit often damage or disrupt the normal operation of power generation. For example, if there is an error in the wiring of the secondary circuit of the differential protection in a substation, false tripping will occur when the transformer is under heavy load or a transverse phase-to-phase short circuit takes place ； If there are errors in the wiring of the line protection, a system failure may cause the circuit breaker to fail to trip when it should, or to trip when it shouldn’t, resulting in equipment damage and serious disruptions to the power system ； If there are problems with the measurement circuit, it will affect metering, resulting in undercharging or overcharging users for electricity. At the same time, it becomes difficult to determine whether the power quality meets the standards. Therefore, although the secondary circuit is not the main component, it plays an extremely important role in ensuring the safety of power generation and providing qualified electric power to users. 　　76. What is secondary circuit labeling? What are the basic principles of secondary circuit labeling? Answer: To facilitate installation, operation, and maintenance, all connections between devices in the secondary circuit must be labeled; this is what is meant by secondary circuit labeling. Labels generally consist of numbers or a combination of numbers and letters; they indicate the nature and purpose of the circuit. The basic principle for circuit numbering is that wherever devices need to be connected to each other using control cables via terminal blocks, they must be numbered in accordance with the circuit principle. Furthermore, the connection between certain devices mounted on top of the panel and the devices inside the panel also requires the use of terminal blocks; in this case, the devices on top of the panel can be regarded as external devices to the panel, and their connection wires are similarly labeled according to the circuit numbering principle. For the sake of clarity, different labeling methods are used for DC and AC circuits. Within both DC and AC circuits, various individual circuits are assigned different numerical identifiers. Therefore, in the wiring diagrams of secondary circuits, upon seeing these labels, we can determine the nature of each circuit, which facilitates maintenance and repair. 　　77. What is the basic method for labeling secondary circuits? Answer: (1) It is composed of three digits or fewer; when it is necessary to indicate the phase of the circuit or certain key characteristics, alphabetical symbols can be added in front of (or after) the numerical label. (2) Marking shall be done according to the principle of “equipotentiality”; that is, in an electrical circuit, all conductors connected to a single point (including foldable wire segments with contact connections) must be marked with the same circuit number. (3) The line segments separating components such as contacts, coils, resistors, and capacitors in electrical equipment are considered separate line segments and are generally given different labels ； For circuits that are connected directly within the panel without passing through terminals in the wiring diagram, they may not be labeled. 　　78. Rules for labeling DC circuits: Answer: (1) Different numerical ranges are used for DC circuits with different purposes; for example, control and protection circuits use 001–099 and 1–599, while excitation circuits use 601–699. (2) The digital numbers used for the control and protection circuits are grouped according to the circuit to which the fuses belong; every 100 numbers form one group, such as 101–199, 201–299, 301–399, … Within each group, the positive-polarity circuits (assigned odd numbers) are listed in ascending order, while the negative-polarity circuits (even numbers) are listed in descending order, for example: 100, 101, 103, 133, …, 142, 140, …. (3) The digital numbering of the signal circuits is grouped by accident, location, warning, and command signals, and arranged in ascending order of numbers. (4) The digital numbering groups for switchgear and control circuits shall be selected according to the digital sequence numbers of the switchgear. For example, if there are 3 control switches: 1KK, 2KK, and 3KK, then the digital range for the control circuit corresponding to 1KK is 101–199, that corresponding to 2KK is 201–299, and that corresponding to 3KK is 301–399. (5) The segments of the positive circuit are numbered with odd numbers, while those of the negative circuit are numbered with even numbers ； Its polarity is changed after passing through each of the main voltage-dropping components (such as coils, windings, resistors, etc.) in the circuit, and the odd-even sequence changes accordingly. For line segments whose polarity cannot be indicated or whose polarity changes during operation, either an odd or an even number can be chosen. (6) Certain specific main circuits are usually given a dedicated set of labels. For example: the positive power supplies are 101, 201, and the negative power supplies are 102, 202 ； The green light circuits in the closing circuit are 105, 205, 305, 405 ； The red circuit numbers in the trip circuit are 35, 135, 235, …, etc. 　　79. Briefly describe the rules for labeling AC circuits. 　　Answer: (1) The AC circuits are numbered in order of phase; in addition to three-digit numbers, they are also given textual designations for identification. For example, A411, B411, C411, as shown in Table 9–1. (2) For AC circuits with different purposes, different digit sets are used, as shown in Table 9–2. The digital numbering of current circuits is generally done in groups of two digits. Such as A401～A409, B401～B409, C401～C409, …, A591～A599, B591～B599. If that is not sufficient, 20 digits can also be used as a group for one set of current transformers. For a parallel circuit of several groups of current transformers connected in parallel, the smallest numerical label among the numbers in those groups should be used first. When current transformers of different phases are connected in parallel, the parallel circuit should be labeled using the digital code of any one of the phase current transformers. The digital numbering of voltage circuits should be in groups of two digits each. Such as A601～A609, B601～B609, C601～C609, A791～A799, …, for labeling a single transformer circuit. (3) The circuits of current transformers and voltage transformers must be numbered in sequence, starting from the terminal of the transformer itself, within the digital range assigned to them. For example, the circuit numbers for ‘TA’ are 411–419, while those for ‘2TV’ are 621–629, and so on. (4) Certain specific communication circuits (such as the common circuit for busbar current differential protection and the common circuit for insulation monitoring voltage meters) are assigned dedicated sets of labels. 　80. What are the basic requirements for the circuit controlling the circuit breaker? Answer: (1) There should be a monitoring circuit for the control power supply. The control power supply for the circuit breaker is of utmost importance; once the power is lost, the circuit breaker cannot be operated. Therefore, for whatever reason, when the power supply controlling the circuit breaker is lost, acoustic and visual signals should be generated to alert the duty personnel to take action promptly. For remote substations, a remote signal should be sent when the power supply for circuit breaker control is lost. (2) The integrity of the circuit breaker tripping and closing circuits should be monitored regularly. A signal indicating a break in the circuit controlling the circuit breaker should be generated when there is a fault in the tripping or closing circuit. (3) There should be an electrical interlock device to prevent the circuit breaker from \"jumping\". A \"jump\" is extremely dangerous for the circuit breaker, as it can cause damage to its mechanism and even lead to an explosion; therefore, interlock measures must be implemented. The “jumping” phenomenon of circuit breakers generally occurs when both the tripping and closing circuits are activated simultaneously. “The design of the “anti-jump” circuit should ensure that when the circuit breaker experiences a “jump,” it is locked in the tripped position. (4) The trip and close commands should be maintained for a sufficient length of time, and the command pulses should be automatically released once the tripping or closing is completed. Since the mechanism of a circuit breaker requires some time to operate, and the main contacts also need to travel a certain distance to reach their designated positions during opening and closing, all of these factors together constitute the circuit breaker’s inherent operating time as well as its arc extinguishing time. Keeping the command in place for a sufficient length of time ensures that the circuit breaker can trip and close properly. To accelerate the operation of the circuit breaker and increase the rate of current rise in the opening and closing coils, it is necessary to minimize the inductance of these coils as much as possible. To this end, both the trip and closing coils are designed for short-term energization. Therefore, after the tripping and closing operation is completed, the tripping and closing circuit must be automatically disconnected; otherwise, the tripping or closing coil will burn out. Usually, the auxiliary contacts of the circuit breaker automatically disconnect the switching circuit. (5) There shall be distinct position signals for the closed and open states of the circuit breaker, and distinct operation signals for automatic tripping and automatic closing in case of a fault. (6) When the operating force of the circuit breaker is lost or insufficient, such as when the spring in the spring mechanism is not tightened or when the pressure in the hydraulic or pneumatic mechanism decreases, the operation of the circuit breaker should be locked out and a signal should be generated. In SF6-gas-insulated circuit breakers, when the SF6 gas pressure drops to the point where the circuit breaker can no longer operate properly, its operation should also be locked out and a signal should be generated. (7) Under the above requirements, efforts should be made to keep the wiring of the control circuit simple, using as few devices and cables as possible. 　　81. What are the hazards of grounding the positive and negative poles of a DC system? Answer: Grounding the positive pole of a DC system can lead to improper operation of the protection systems. This is because ordinary trip coils (such as the coils of outlet intermediate relays and trip/close coils) are connected to the negative power supply; if these circuits experience grounding or poor insulation, it can lead to incorrect operation of the protection system. Direct current negative grounding follows the same principle as positive grounding; if another point in the circuit is grounded, it may cause the protection system to fail to operate (leading to an expansion of the accident). Because grounding at two points shorts the trip or closing circuit, which may also cause the relay contacts to burn out. 　　82. When using the trial shutdown method to locate a DC ground fault, it is sometimes not possible to determine in which system the fault lies. What could be the reasons? Answer: When the DC ground fault occurs in the charging equipment, the batteries themselves, or the DC busbar, it is impossible to identify the location of the fault using this method. When DC power is supplied via a loop, it is impossible to locate the ground point without first breaking the loop. In addition to the situations mentioned above, there is also series connection of direct current (parasitic circuits), grounding of two points at the same pole, poor insulation in the direct current system, and multiple loose connections that result in a high ground voltage, causing a ground indication on the meters. Therefore, when pulling for inspection, it is often not possible to disconnect all the grounding points at once, so grounding still persists. 　　83. Why should the operating time of the integrated reclosing device be calculated starting from the last circuit breaker trip? Answer: After the use of integrated reclosing, the line will inevitably enter a condition of partial-phase operation. Practice has shown that during off-full-phase operation, failures can still occur in the healthy phase. Once this situation occurs, it is possible for the circuit breaker to trip due to a fault in the healthy phase, and then to be closed immediately without an appropriate interval; in the worst case, the circuit breaker is closed right after it trips. At this time, the unsuccessful reclosing is caused by insufficient de-arcing at the fault point; meanwhile, closing the circuit breaker right after it has just been opened reduces its breaking capacity. For some circuit breakers, it can also cause an explosion. To prevent this from happening, the operating time of the integrated reclosing device should be calculated starting from the last trip of the circuit breaker. 　　84. What principles should be followed in setting the phase-selecting element of the integrated reclosing device—the directional impedance relay? Answer: The principles for setting it are as follows: (1) Based on a ground short circuit at the end of the line through 2011 ； The phase selection elements must be able to operate sequentially at the very least. 　　(2) In the case of a metallic ground fault at the end of the line, its sensitivity shall not be lower than 1.5. (3) Set according to avoiding the normal maximum load. 　　(4) During the process of avoiding non-full-phase conditions and in the case of single-phase grounding at the outlet, the healthy-phase selection element should not malfunction. 　　85. Why does the phase difference high-frequency protection require a tripping stop signal when used in conjunction with single-phase reclosing? And does high-frequency blocking protection require a single-trip stop signal? Answer: On lines where single-phase reclosing is used, when operation occurs under non-full-phase conditions, the triggering elements of the phase difference high-frequency protection may not return. In such cases, if a stop signal is sent on both sides, since the timing of these stop signals cannot be identical, the side where the stop signal is sent later will experience tripping due to intermittent waves generated as a result of non-full-phase operation after a single-phase fault occurs. Therefore, the phase difference high-frequency protection signal cannot be disabled after a single-phase fault trip. After a three-phase trip, the phase difference high-frequency protection loses its operating current and begins to emit continuous waves, which will lock out the high-frequency protection on the opposite side; therefore, a three-trip stop signal must be implemented to enable the phase difference high-frequency protection on the opposite side to trip more quickly in order to eliminate the fault. Furthermore, when the busbar protection trips, if the circuit breaker fails, the three-trip stop signal can activate the high-frequency protection on the opposite side, enabling rapid removal of the fault. High-frequency blocking protection must achieve single-jump signal interruption, because in the event of a single-phase fault on one side of the line, a single jump occurs first; after that the protection returns to normal operation, but the activating element of high-frequency blocking protection does not return to its original state. The transmitter then starts to transmit signals, which will block the high-frequency protection on the opposite side. Therefore, after a single-phase trip, the signal must be stopped to accelerate the tripping of the high-frequency blocking protection on the opposite side. 　　86. Compare the advantages and disadvantages of single-phase reclosing and three-phase reclosing 　　Answer: After comparing the advantages and disadvantages of these two types of reclosing, the results are as follows: (1) When single-phase reclosing is used, non-full-phase operation occurs. Apart from some special issues that need to be considered regarding interconnection protection, this has a significant impact on the operation of zero-sequence current protection, preventing it from functioning effectively in medium and short-distance circuits. For example, in a typical three-phase reclosing circuit for ring networks, the zero-sequence current protection can operate immediately in its first stage; that is, when a single-phase ground fault occurs at one end of the circuit and the three phases trip, the zero-sequence current on the other side increases immediately, triggering operation of the protection in its first stage. Previously, by taking advantage of this feature, even when the line longitudinal protection was disabled, a high success rate could still be maintained in conjunction with three-phase rapid reclosing. However, this characteristic does not exist when single-phase reclosing is used. Moreover, to account for partial-phase operation, it is often necessary to raise the starting value of the zero-sequence current at one stage; the sensitivity of the zero-sequence current at the second stage also decreases accordingly, and the operating time may increase as well. 　　(2) When three-phase reclosing is used, the output circuits of various protections can directly act on the circuit breaker. When using single-phase reclosing, in addition to the protection devices that already possess phase selection capability, all types of interconnecting protections, inter-phase distance protections, zero-sequence current protections, etc., must be controlled by the phase selection element of the single-phase reclosing system in order to operate the circuit breaker. (3) When a single-phase ground fault occurs in the line and three-phase reclosing is performed, it generates higher operating overvoltage compared to single-phase reclosing. This is due to three-phase tripping and power interruption at the zero crossing of current; residual charge voltage equivalent to the peak phase voltage remains on the non-faulty phases. Since the power interruption duration during reclosing is short, the voltage on these non-faulty phases does not change much, which results in high operating overvoltage during reclosing. When single-phase reclosing is used, the voltage of the faulty phase during reclosing is generally only around 17% (due to the voltage division caused by the capacitance of the line itself), so there is no issue with operating overvoltage. However, based on the long-term operation experience of three-phase reclosing in 110 kV and 220 kV power grids, the issue of switching overvoltage for ordinary medium and short-distance lines is not significant. (4) When three-phase reclosing is used, under the most unfavorable conditions, it is possible to reclose onto a three-phase short-circuit fault. In those circuits where stability calculations indicate that this situation must be avoided, it is possible to incorporate simple inter-phase fault detection elements into the three-phase reclosing system, so that reclosing occurs in the case of a single-phase fault but not in the case of an inter-phase fault. 　　87. What are the various ways to initiate automatic reclosing? What are the characteristics of each? Answer: There are two ways to initiate automatic reclosing: the method based on the mismatch between the position indicated by the circuit breaker control switch and the actual position of the circuit breaker, and the protection-based method. Advantages of this startup method: it is simple to implement; it can also correct accidental activation or premature tripping of circuit breakers, thereby improving power supply reliability and the stability of system operation. It performs well in grids at all levels, and it constitutes the basic startup method for all reclosing systems. Its drawback is that when the auxiliary contacts of the circuit breaker are in poor contact, the corresponding starting mode will become ineffective. The protection start mode is a supplement to the normal start mode. At the same time, during single-phase reclosing, certain protections need to be locked out, and the fault phase needs to be identified and fixed within the logical circuits; furthermore, a reclosing initiation element activated by the protections is also required. Its disadvantage is that it cannot correct incorrect operation of the circuit breaker. 　　88. In the testing for synchronous operation and for zero-voltage reclosing devices, why are synchronous operation relays and zero-voltage relays installed on both sides? Answer: The reasons are as follows. (1) If a wiring method is adopted where voltage testing is performed on one side and synchronous testing on the other side. Therefore, on the side that uses voltage-free switching, when its circuit breaker trips under normal operating conditions due to some reason such as accidental contact or malfunctioning protection, since the circuit breaker on the opposite side does not activate, there is still voltage in the line; as a result, reclosing is not possible, which is a significant drawback. To solve this problem, a synchronizing relay is usually also installed on the side without voltage, and its contacts operate in parallel with those of the other relay; this allows the circuit breaker that has tripped accidentally to be reactivated. To ensure that the operating conditions of the circuit breakers on both sides are identical, a no-voltage testing relay is also installed on the synchronization side; it is used according to the specific circumstances after switching. It should be noted that when a pressure-free calibration relay and a synchronization calibration relay are installed on one side, only a synchronization calibration relay can be installed on the other side. Otherwise, achieving voltage-free reclosing on both sides simultaneously will result in asynchronous closing; therefore, contacts that indicate the presence of voltage in the circuit must be connected in series within the contacts of the synchronization detection relay. 　　89. Briefly describe the technical requirements for the four-unification zero-sequence current protection. 　　Answer: The technical requirements for the entire protection system are as follows: (1) The device should have 5 current elements, 4 time elements, and 1 zero-sequence power direction element. (2) The device shall be capable of implementing standard four-stage protection or three-stage protection. The latter has two first paragraphs; the paragraph with a low setting includes a 0.1s delay after reclosing, and the delay circuit should be able to maintain this delay for more than 3 seconds, so as to prevent accidental tripping due to asynchronous closing of the three phases of the circuit breaker during reclosing ； It can also be connected as a three-stage protection scheme with a time limit for the first stage. The three-stage protection for single-phase reclosing circuits consists of two first stages or two second stages. After the reclosing is initiated, the first or second section of the setting that cannot withstand the zero-sequence current under partial-phase operation can be taken out of service ； After reclosing, the second or third stage, which provides sufficient sensitivity to ground faults at the end of this line, is activated after a 0.1s delay via the full-phase operation detection circuit. In the recent period, the △t time limit can be shortened after the reclosing is initiated. (3) A sensitive current element in the device can perform the following functions according to operational requirements. 1) Connect to the zero-sequence circuit of the adjacent current transformer to implement a cut-out locking mechanism for the current circuit. Its contacts can introduce the protective section required for control locking. 2) Used as a signaling signal to initiate high-frequency blocking protection. (4) The zero-sequence power direction element should be able to control one or several of its sections as required, and its zero-sequence voltage can be directly connected to 3». Voltage, but a signal should be provided when the zero-sequence power direction element operates. (5) When the protection momentary time interval is controlled by a directional element, the contacts of the directional element should directly control the starting circuit, rather than a reset relay, in order to minimize the operating time. (6) During the protection delay period, the contacts of the mechanical time relay and those of the current element should be connected in series to activate the outlet trip relay, in order to minimize the protection return time. (7) There should be a 0.1s delay during the acceleration action after manual closing. (8) For current components with instantaneous operation, measures should be taken to reduce the impact of DC and harmonic components on the component’s operating threshold; the manufacturer shall provide transient data ； Reduce the power consumption of the zero-sequence current component. (9) The device shall have corresponding contact circuits to form high-frequency blocking zero-sequence direction protection in conjunction with the transceiver, as well as for use with integrated reclosing. 90. Why does the timing of the last stage of the zero-sequence current protection in circuits that use single-phase reclosing need to avoid the reclosing cycle? Answer: The timing of the last stage of the zero-sequence current protection must avoid the circuit’s reclosing cycle for the following reasons: (1) This stage is typically intended to serve as a remote backup protection for adjacent circuits, and it also needs to ensure sufficient sensitivity even when the circuit is grounded through a large transition resistance (100 Ω for 220 kV systems); therefore, its setting value is generally kept low. During the line reclosing process when operating in a partial-phase condition, under the influence of high load currents, the partial-phase zero-sequence current may exceed its set value, thereby triggering the protection to operate. (2) To ensure that protection can operate to isolate a ground fault in a healthy phase during the reclosing process of this line, the last stage of the zero-sequence current protection must not be locked out and taken out of service after the reclosing is initiated. Taking the above two points into account, the final stage of the zero-sequence current protection only features an *extended time delay to avoid the reclosing cycle, allowing it to remain in operation during reclosing while preventing false trips. When its set value cannot withstand the 3I flowing through this line due to the non-full-phase operation of adjacent lines. At that time, its setting time should also avoid the reclosing cycle of adjacent lines. 　　91. What issues should be considered when using zero-sequence current direction protection in conjunction with reclosing? Answer: The following issues should be taken into account. (I) Zero-sequence current direction protection used in combination with three-phase reclosing 1. For the first stage of the zero-sequence current protection, during calibration it is necessary to avoid exceeding the maximum zero-sequence current that flows through the protected circuit in the event of single-phase or two-phase ground faults under normal operating and maintenance conditions, at the end of the circuit (or at both busbars if direction detection is not used). When the zero-sequence current protection is used in conjunction with three-phase reclosing, transient non-full-phase operation occurs due to the asynchronous closing of the circuit breakers on the side where reclosing takes place; the asynchronous closing time of the three phases of the circuit breaker can actually reach 40–60 ms, and this also results in the generation of zero-sequence current. When this maximum out-of-phase zero-sequence current cannot be avoided, a time-independent protection section will malfunction. It is absolutely necessary to set the protection for terminal faults on the bypass line. If this set value is also greater than the set value for the uniphase zero-sequence current caused by the asynchronous operation of the bypass circuit breaker, then it is sufficient to install a current protection circuit without a time delay. If the zero-sequence current caused by out-of-phase operation of the circuit breakers is greater than the zero-sequence current resulting from a fault at the end of the line, or if the settings are adjusted to account for this out-of-phase condition ； Or, during three-phase reclosing, apply a time delay of 0.1 s to the first section that cannot avoid zero-sequence current under partial-phase operation ； Alternatively, use two first paragraphs: one is set without a time limit for avoiding partial-phase conditions, and the other is set for avoiding end-of-line faults; however, a 0.1s time limit is added or the function is disabled after reclosing. In summary, when three-phase reclosing is used in conjunction, the zero-sequence current direction protection device must have the capability to implement two first-stage protections (the sensitive stage and the insensitive stage), as well as the ability to provide a time-limited first-stage protection with a time delay of 0.1 seconds during reclosing. 　　2. Number of time-delayed backup protection stages in the zero-sequence current direction protection device: According to the regulations, multiple stages of zero-sequence current direction protection must be tuned in accordance with the principle of step-by-step coordination, that is, coordination is required both in terms of sensitivity and timing. To meet the requirements of power grids with different voltage levels regarding backup functions and protection for special purposes (such as the protection of bypass circuit breakers) in terms of the number of protection sections, the current configuration of existing systems requires that zero-sequence current direction protection have not only two first-stage sections but also three time-based backup sections. (II) Zero-sequence current direction protection device when used in conjunction with integrated reclosing 1. The setting of the first-stage zero-sequence current protection must meet the following requirements: (1) It must be able to withstand the maximum zero-sequence current flowing through the line in the event of single-phase or two-phase ground faults at the end of the line (or at both busbars) under normal operating conditions as well as during normal maintenance operations. (2) Avoid the maximum zero-sequence current during full-phase operation within the single-phase reclosing cycle. If unlimited-time zero-sequence current protection is required during partial-phase operation of the line, and the maximum zero-sequence current under partial-phase operation is greater than that in the case of a ground fault at one end (or both ends), then two types of unlimited-time first-stage zero-sequence current protections must be installed: one that is sensitive enough to detect faults at the ends, and another that is less sensitive, designed to handle partial-phase operation conditions. Since the zero-sequence current that occurs during partial-phase operation cannot be avoided, one of the protection sections must be taken out of service during the single-phase reclosing cycle, so that only the less sensitive protection section continues to operate during partial-phase operation. It must be noted that during partial-phase operation, it is necessary to retain a time-independent first-stage protection capable of withstanding partial-phase zero-sequence currents. This protection serves as the base level for the step-by-step coordination of the backup protections of adjacent lines, and by remaining active during partial-phase operation, it ensures that the second-stage protections associated with those adjacent lines are properly coordinated, thereby preventing unsolicited, selective tripping. Under this premise, a sensitive section is provided to expand the protection range of the time-limitless protection section in the event of the first fault. Therefore, the zero-sequence current direction protection device used in conjunction with integrated reclosing must also have the capability to implement two sections. 2. Zero-sequence current two-stage protection 1) To improve sensitivity in the event of a fault at the end of the line and to reduce the setting time, the setting can be determined with only consideration given to coordination with the less sensitive first-stage protection of adjacent lines. With such a configured two-stage current protection, if, during the single-phase reclosing cycle of this line, neither the current setting value nor the setting time can prevent operation under partial-phase conditions, then it must be taken out of service. 2) In some systems, so-called insensitive two-stage protection is installed on certain short circuits; its operating current value is set to accommodate the maximum zero-sequence current that occurs during partial-phase operation. However, since it cannot handle end-of-circuit faults, a time delay element is included. During single-phase reclosing on this line, the insensitive second stage remains in operation. Setting up a less sensitive two-stage protection is mainly aimed at improving the setting coordination conditions between adjacent backup sections. 　　In the absence of a non-sensitive second stage, the second stage of adjacent lines can only operate in conjunction with the non-sensitive first stage of the same line, whereas the third-stage protection of adjacent lines must work in coordination with the third stage protection after reclosing of that same line. If a insensitive second stage is provided, the setting of the second or third stage for adjacent lines can be coordinated with it, thereby improving the protection performance of those adjacent lines. In some cases, the effect of this improvement is quite noticeable. Therefore, the zero-sequence current protection device must consider the possibility of implementing two stages. However, for the device, although it is required to be able to have two first sections as well as two second sections, a non-sensitive section 1 and a non-sensitive section 2 cannot exist simultaneously in one protection device. 　　3. Zero-sequence current backup protection sections The various sections of the zero-sequence current direction protection device are tuned in accordance with a step-by-step coordination principle; it is necessary to have four such protection sections. Although some domestic power systems can meet the setting requirements using three-stage protection, for the protection installed on bypass circuit breakers, since these breakers are intended to replace multiple line protections, several additional stages are generally required for operational convenience. To this end, an additional current element and a time element are also provided within the protection device, allowing for further protection to be added when necessary. 　　56. In a large-short-circuit-current grounded system, why is it sometimes necessary to install direction relays to form zero-sequence current direction protection? Answer: In a large-short-circuit-current grounded system, where the neutral points of the transformers at both ends of the line are grounded, when a ground short circuit occurs on the line, zero-sequence current flows between the fault point and the neutral points of each transformer. This situation is similar to the phase-to-phase fault current protection in a radial power grid supplied by sources on both sides. To ensure selective operation of each zero-sequence current protection and reduce their setting values, it is necessary to install direction relays so that their operation is directional. This ensures that the zero-sequence directional current protection is activated when power is transmitted from the bus to the line, and deactivated when power is transmitted from the line to the bus. 　　92. What are the principles for using zero-sequence (or negative-sequence) direction relays? Answer: Since zero-sequence current protection is used as a basic protection with a high probability of activation, its circuit should be simplified as much as possible to improve its reliability in functioning. The zero-sequence power direction relay is the weak link in zero-sequence current protection. In operational practice, protective malfunctions caused by direction relays occur from time to time. Therefore, the principles for using zero-sequence (or negative-sequence) direction relays are as follows: (1) Except in cases where the use of direction elements can lead to a significant improvement in protection performance, the instant periods of zero-sequence current protection, which have the highest probability of activation—particularly the period intended to avoid partial-phase operation—and the final stage serving as a backup mechanism, should not be controlled by direction elements. (2) In the other sections, if selectivity and a certain level of sensitivity can be ensured without using direction elements, based on the actual values chosen, it is also not appropriate to control them through direction elements. (3) For parallel double-circuit lines, especially those employing single-phase auto-reclosing, if the mutual inductance is relatively large, the relevant time delays in their protection schemes should, when necessary, also include a sensitive stage. Generally, it is advisable to control this stage via zero-sequence directional elements. This approach eliminates the need to consider the coordination between the protections of the two circuits under uncompletely phased operation conditions, thereby improving the overall performance of the protection system. (4) The operating power of directional relays should be determined on the principle of not limiting the sensitivity of protection actions. Generally, it is required that when a ground fault occurs and the zero-sequence current reaches the protection’s pickup value, there should still be a sensitivity level of at least 2. 　　93. In a grounding system with high short-circuit currents, what are the main types of protection mechanisms for transmission lines in case of ground faults? Answer: In a grounding system with high short-circuit currents, the main protection mechanisms for transmission lines in such situations include interconnecting protection (such as phase difference high-frequency and direction high-frequency protection), zero-sequence current protection, and ground distance protection. 　　94. What is zero-sequence protection? Why is it necessary to install zero-sequence protection separately in a grounding system with high short-circuit currents?
Answer: After a ground fault occurs in a grounding system with high short-circuit currents, zero-sequence current, zero-sequence voltage, and zero-sequence power are generated. Relay protection devices that utilize these electrical quantities to protect against ground faults are collectively referred to as zero-sequence protection. Although overcurrent protection for three-phase star connection can also protect against ground short circuits, its sensitivity is low and its protection time delay is long. This drawback can be overcome by using zero-sequence protection, because: ① During normal operation of the system as well as in the event of inter-phase short circuits, no zero-sequence current or voltage appears; therefore, the operating current for zero-sequence protection can be set at a lower value, which helps to improve its sensitivity ； ②Well, in a Y-connected step-down transformer, faults that occur on the Δ side do not result in zero-sequence currents appearing on the Y side; therefore, the operating time of the zero-sequence protection device does not need to be set to be short in order to coordinate with the protection devices on the lines connected to this type of transformer. 　　95. What are the components of zero-sequence current protection? Answer: Zero-sequence current protection is mainly composed of a zero-sequence current (voltage) filter, a current relay, and a zero-sequence direction relay. 　　96. Briefly describe the role and significance of zero-sequence current direction protection in ground fault protection. 　　Answer: The zero-sequence current direction protection is a multi-stage current direction protection device that responds to the magnitude and direction of the zero-sequence current component when a ground fault occurs in a line. In the power lines of power grids at different voltage levels with high short-circuit currents in China, such ground protection devices are installed as basic protection in accordance with the regulations issued by the relevant authorities. Statistics on power system accidents show that in power grids with large short-circuit current grounding systems, line ground faults account for 80% to 90% of all line faults. The correct operation rate of zero-sequence current direction grounding protection is approximately 97%, making it the type of protection with the highest correct operation rate among high-voltage line protections. Zero-sequence current direction protection has a series of advantages, including simple principle, reliable operation, low equipment investment, easy operation and maintenance, and a high rate of correct operation. With the continuous development of power systems, power grids are becoming increasingly complex, with more short circuits and autotransformers appearing. Under these new conditions, zero-sequence current direction protection also reveals its inherent limitations. To this end, while the current regulations stipulate the installation of multi-stage zero-sequence current direction protection, they also add that: \"For certain lines, where directional ground distance can significantly improve the grounding protection performance of the entire power grid, ground distance protection may be installed in addition to stage-type zero-sequence current protection.\" 　　97. What are the advantages of zero-sequence current protection? Answer: Directional and non-directional zero-sequence current protection are simple and effective methods for ground fault protection, and their advantages include: (1) Simple structure and working principle. Zero-sequence current protection uses a single current value as the operating parameter, and only one relay is needed to respond to a ground fault in any of the three phases. As a result, it requires fewer relays, has simpler circuits, is easier to test and maintain, and it is simpler to ensure the quality of setting tests as well as to keep the device in good condition. Therefore, its correct operation rate is higher than that of other more complex protections. (2) The overall protection system has fewer intermediate stages, which enables rapid response, especially to faults that occur nearby, thereby helping to prevent the progression of such faults. (3) Under the condition that the zero-sequence network of the power grid remains basically stable, the protection range is relatively stable. Due to the steep slope of the zero-sequence current variation curve in line ground faults, the protection range during instantaneous periods is large; for ordinary long and medium-long lines, it can cover 70% to 80% of the entire line length, with performance comparable to that of distance protection. Moreover, on lines equipped with three-phase reclosing, the instantaneous protection mechanism generally possesses the characteristic of sequential operation; even in the case of a fault on the same line outside the range covered by the instantaneous protection, the sudden increase in zero-sequence current on this side after the three-phase circuit breaker on the opposite side trips can trigger the instantaneous protection to extinguish the fault. This is something that normal distance protection cannot achieve, and it is an advantage unique to zero-sequence current protection. (4) The protection reaction depends on the absolute value of the zero-sequence current and is less affected by the fault transition resistance. For example, when a tree discharge fault occurs on a 220 kV line, the transition resistance at the fault location can be as high as 100 Ω or more; in such cases, most other protection systems will not be able to operate, whereas the zero-sequence current protection can function even at 3I. A fixed value as high as several hundred amps (usually around 100A) is still sufficient to trigger operation, or to enable sequential operation on both sides, thereby ultimately eliminating the fault. (5) The protection setting value is unaffected by load current, and is also largely unaffected by short-circuit faults in other ungrounded neutral systems; therefore, a higher sensitivity for the protection delay time can be adopted. Furthermore, the coordination among zero-sequence current protections is determined solely by the impedance distribution in the zero-sequence network, and it is not affected by load currents or the start-up and shutdown of generators. As long as the impedance of the zero-sequence network remains relatively stable, good protection performance can be achieved. 　　98. What issues need to be considered when operating zero-sequence current protection? Answer: The following issues need to be taken into account when operating zero-sequence current protection: (1) A break in the current circuit may cause the protection to malfunction. This is a common weakness of generally sensitive protections, and care must be taken to prevent it during operation. In terms of the probability of disconnection, it is much lower than the probability of disconnection in the voltage circuit of distance protection. If necessary, the method of using the zero-sequence current from adjacent current transformers for interlock can also be employed to prevent such misoperations. (2) When the power system is operating in an asymmetric manner, zero-sequence current also appears. Examples include asymmetric operation caused by different parameters among the three phases of a transformer, two-phase operation during single-phase reclosing, asynchronous operation of the three-phase circuit breakers during three-phase reclosing or manual closing, zero-sequence circulating currents resulting from the parallel connection of circuit breakers and isolators during busbar switching operations or when circuit breakers are operating in a normal closed circuit due to inconsistent contact resistances among the isolators or circuit breakers (Figure 4–60), as well as unbalanced excitation inrush currents generated when a transformer is connected to the system without prior preparation. Especially when there is a transformer with a grounded neutral point operating on the busbar where the new transformer is connected, unbalanced excitation inrush currents and DC components may persist for an extended period of time, all of which can trigger the operation of the zero-sequence current protection. (3) For parallel lines that are geographically *close to each other, a fault in one of these lines can cause an induced zero-sequence current to appear in the other line, leading to incorrect operation of the zero-sequence direction relay on the opposite side. If such a possibility exists, a negative-sequence direction relay can be used instead to prevent misjudgments by the aforementioned direction relay. (4) Since there is no zero-sequence current or voltage in the AC circuit of the zero-sequence direction relay, a break in the circuit is not easy to detect ； When the zero-sequence voltage of the relay is taken from the open delta side of the voltage transformer, it is also difficult to use straightforward simulation methods to verify the correctness of its direction; as a result, problems in the AC circuit can easily lead to the protection failing to operate or operating incorrectly during grid failures. 　　99. What are the advantages of using ground distance protection? Answer: The greatest advantage of ground distance protection is that its protection range during instantaneous faults remains constant; moreover, it is relatively easy to implement a second stage of ground protection with short delay times and sufficient sensitivity. It is particularly suitable for stage 1 and stage 2 protection of short circuits. For short circuits, a viable grounding protection method is to use ground distance protection stages 1 and 2, supplemented by complete zero-sequence current protection. The two types of protection systems work in coordination with one another, each performing its own role: the ground distance protection is used to provide an instantaneous protection zone for this line, as well as a second protection layer for the entire line that features a shorter time delay and sufficient sensitivity ； Zero-sequence current protection is primarily designed to protect against high-resistance faults, ensuring adequate selectivity in relation to the zero-sequence current protections of adjacent lines. 100. What are the characteristics of conventional ground distance relays? Answer: These relays have the following characteristics. (1) It can accurately measure the distance during a single-phase ground fault. Adding a leading-phase voltage as an auxiliary polarization quantity and using a polarization circuit to achieve a memory effect are both highly beneficial for eliminating the voltage dead zone, enhancing the capability to tolerate grounding resistance, and ensuring the directionality of reverse-direction faults. The basic performance under such a fault is similar to that of the inter-phase direction distance element in the case of an inter-phase short circuit. (2) During a single-phase ground fault, it can perform phase selection and can be used as a phase-selection element. (3) The receiving bus loses its directionality when short-circuited in three phases through a resistor. (4) In the case of heavy-load long lines, if the setting value is too large, directionality will be lost in the event of a two-phase short circuit on the sending bus. (5) In the case of a two-phase short circuit with resistance grounding fault, the components in the leading fault phase experience overshoot; the greater the ratio of the equivalent source impedance to the line impedance, the more severe the overshoot is ； The memory effect of the polarization circuit and the effect of the leading-phase auxiliary polarization voltage further increase the overshoot. The components in the lagging fault phase need to have a reduced protection range. Therefore, if this relay is to be used as a distance measurement element, it is necessary to deactivate the component of the phase where a short circuit to ground has occurred. (6) When there is a two-phase short circuit in the forward direction, the protection range is reduced. The greater the ratio of the equivalent source impedance to the set impedance, the more severe the shortening becomes. (7) Oscillations occur during full-phase and partial-phase operation, and it may operate whenever the angular differences between the equivalent source electromotive forces on both sides are large. 　　101. What is the time characteristic of distance protection? Answer: Distance protection is generally designed in three stages; the protection range of the first stage covers 80% to 85% of the total length of the protected line, and the operating time t1 is the inherent operating time of the protection device. The protection range of Section II must be coordinated with the protection setting of the next line; it generally covers the entire length of the protected line as well as 30% to 40% of the length of the next line. The operating time tⅡ should be in line with the operating time of the first section of the distance protection for the next line, and is usually around 0.5 seconds. Paragraph III provides backup protection; its coverage area is extensive, including the entire length of the current line as well as the next line and even further areas. Its operating time threshold tⅢ is set according to a stepped principle. 　　102. Why is the protection range of the first stage of distance protection usually set at 80% to 85% of the total length of the protected line? Answer: The operating time of the first stage of distance protection is determined by the inherent operating time of the protection device itself. In order to ensure selective coordination with the first stage of distance protection of the adjacent line, their protection ranges must not overlap. Otherwise, the protection range of the first section of this line will extend to the next line, resulting in non-selective operation. Furthermore, the line parameters used for calculating protection setting values are inaccurate, and the measurements taken by voltage transformers and current transformers are also faulty. Considering the worst-case scenario, these errors are added together as positive values. If the protection range in Paragraph 1 covers the entire length of the protected line, it inevitably has to extend to the next line. At this time, if the outlet of the next line fails, the first sections of the two adjacent lines will activate simultaneously, resulting in an unselective cut-off of the fault. To address these drawbacks, the protection range in paragraph 1 usually covers 80% to 85% of the total length of the protected line. 　　103. What is a directional impedance relay? Answer: A directional impedance relay is a device that can not only measure the magnitude of impedance, but also determine the direction of the fault. In other words, this impedance relay can not only reflect the magnitude of the operating current (measured current) and operating voltage (measured voltage) applied to the relay, but also the phase relationship between them. In complex power grids with multiple power sources, it is necessary for the measuring elements to be able to determine the location of the short-circuit fault, which is why direction impedance relays have become one of the most commonly used measuring elements in distance protection devices. In principle, regardless of the operating characteristics of the relay in the impedance plane, as long as it is possible to determine the magnitude and direction of the short-circuit impedance, it can be called a directional impedance relay. However, *a habitual impedance relay refers to an impedance relay that passes through the origin in the impedance complex plane and has circular characteristics. 　　104. Why is the lower the voltage sensitivity of a multimeter (the higher its internal resistance), the smaller the error in measuring voltage? Answer: The voltage sensitivity of a multimeter refers to the internal resistance of the instrument per unit of voltage measured; for example, the MF-18 model has an internal resistance of 20,000 Ω/V. When using a multimeter’s voltage function to measure voltage, it is connected in parallel with the device being measured. High voltage sensitivity means that the internal resistance of the meter is high, resulting in minimal current division; this reduces the impact on the measurement and leads to more accurate results. Conversely, high measurement errors occur in such cases. Therefore, the higher the voltage sensitivity of a multimeter, the smaller the error in measuring voltage. 　　105. What are electrical devices in operation? Answer: Devices in operation refer to electrical devices that are under voltage overall, or partially charged, and that become charged as soon as they are operated. 　　106. What measures should be taken when working on a live protection panel or control panel? Answer: When working on panels that are partially or fully live, the equipment under maintenance must be separated from the operating equipment using clear markers such as red curtains. It is also necessary to follow the procedures related to work permits and implement a supervision system. 　　107. What are the benefits of quickly isolating faults through relay protection for the power system? Answer: The benefits of quickly isolating faults include: (1) Enhancing the stability of the power system. 　　(2) The voltage recovers quickly, allowing the motor to start up on its own and return to normal operation swiftly, thereby minimizing the impact on users. 　　(3) Reduce the degree of damage to electrical equipment and prevent further expansion of faults. 　　(4) The short-circuit point is easy to deexcite, improving the success rate of reclosing. 　　108. What is time-limited overcurrent protection? What is inverse-time overcurrent protection? Answer: In order to achieve selective operation of overcurrent protection, the operating times of various protective devices are generally set according to a stepped principle. That is, the operating time of adjacent protections increases step by step from the load toward the power source, and the operating time of each set of protections remains constant, independent of the magnitude of the short-circuit current. Overcurrent protection with such a time-limit characteristic is called time-limited overcurrent protection. Inverse-time overcurrent protection refers to a type of protection whose operating time decreases automatically as the short-circuit current increases. The inverse-time overcurrent protection used in transmission lines enables faster isolation of faults at the beginning of the protected line. 　　109. What are the maximum and minimum operating modes of a system? Answer: In the setting calculations for relay protection, it is necessary to take into account the maximum and minimum operating modes of the power system. The maximum operating mode refers to the operating condition in which the equivalent impedance of the system is at its minimum when a short circuit occurs at the end of the protected equipment, resulting in the highest short-circuit current passing through the protective device. The minimum operating mode refers to the operating mode under the same short-circuit conditions as mentioned above, in which the system’s equivalent impedance is at its maximum, resulting in the smallest short-circuit current passing through the protective devices. 　　110. What is near-backup protection? What are the advantages of near-backup protection? Answer: Near-backup protection involves installing two sets of protections, A and B, on the same electrical component; when protection A fails to operate, protection B takes over to trigger a trip. When the circuit breaker refuses to operate, the protection mechanism triggers, causing the circuit breakers connected to the various power sources on that bus to trip after a certain delay. The advantage of near-backup protection is its ability to serve as a backup in a reliable manner, with rapid operation, and to provide selective backup in complex power grids. 　　111. What is current quick-break protection? What are its characteristics? Answer: Current quick-break protection is a type of time-independent current protection that is tuned to withstand the maximum short-circuit current flowing through it during an external short circuit in the protected component, thereby ensuring its selective operation. Its features are: simple wiring, reliable operation, and fast fault removal, but it cannot protect the entire length of the circuit. The protection scope is greatly affected by changes in the system operation mode.