Q&A on Power Dispatching Technology -- Short Answer Questions Series

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Q&A on Power Dispatching Technology -- Short Answer Questions Series 1 1. What are power systems, electrical power systems, and power grids? Answer: Generally, the integrated system that comprises the power facilities and equipment of power generation enterprises, as well as the equipment for power generation, transmission, transformation, distribution, and consumption, along with the corresponding auxiliary systems, and which is responsible for the production, transmission, distribution, and utilization of electrical and thermal energy, is referred to as a power system ； 　　The unified whole that encompasses the production, transmission, distribution, and utilization of electrical energy, consisting of power generation, transmission, transformation, distribution, electrical consumption equipment, and the corresponding auxiliary systems, is called an electric power system ； 　　The unified system that connects power generation with power consumption, consisting of transmission, transformation, and distribution equipment along with the corresponding auxiliary systems, is called a power grid. 2. What are the characteristics of modern power grids? Answer: 1. The main grid structure is composed of strong ultra-high voltage systems. 2. The connections between various power grids are strong, and the voltage levels are relatively simplified. 3. It possesses sufficient capacity for peak shaving, frequency regulation, and voltage control, enables automatic generation control, and offers high power supply reliability. 4. It is equipped with appropriate safety and stability control systems, a highly automated monitoring system, and a state-of-the-art communication system. 5. It has a technical support system adapted to the operation of the electricity market, which facilitates the rational use of energy resources. 3. What is the significance and role of interconnecting regional power grids? Answer: 1. It enables the rational use of energy, promotes environmental protection, and contributes to the sustainable development of the power industry. 　　2. It is possible to install large-capacity, high-efficiency thermal power units, hydroelectric units, and nuclear power units, which helps to reduce costs, save energy, and accelerate the pace of power generation development. 　　3. Time differences and temperature differences can be utilized to stagger peak electricity usage times; by taking advantage of the asynchronous nature of electricity consumption in different regions, load balancing can be achieved, thereby reducing the need for backup capacity and installed capacity. 　　4. It is possible to share electricity among different regions, exchange resources, and serve as a backup for one another, which helps reduce the capacity required for emergency use in case of accidents, enhances the ability to withstand such accidents, and improves the safety level of the power grid as well as the reliability of power supply. 　　5. It can withstand large impact loads, which helps to improve power quality. 　　6. It is possible to regulate hydroelectric power across different river basins, and to carry out economic scheduling of water, thermal, and hydroelectric power on a larger scale, thereby achieving greater economic benefits. 4. What are the principles of reactive power compensation in power grids? Answer: The principles for reactive power compensation in power grids are that it should be carried out based on the principles of hierarchical and zonal distribution as well as local balancing. It should also be able to adjust according to changes in load or voltage, so as to ensure that the voltage at various key points in the system meets the specified requirements both under normal conditions and after accidents. This approach helps to avoid the transmission of reactive power over long distances or through multiple levels of transformers. 5. Briefly describe the difference between the voltage characteristics and frequency characteristics of a power system. Answer: The frequency characteristics of a power system depend on the frequency characteristics of the load and those of the generators (the characteristic by which the load changes with frequency is called the load’s frequency characteristic). The characteristic by which the output of a generator set changes with frequency is known as the generator’s frequency characteristic; it is determined by the balance of active load in the system, and has little to do with the network structure (network impedance). In the non-oscillating case, the steady-state frequency is the same for the same power system. Therefore, the system frequency can be centrally adjusted and controlled. 　　The voltage characteristics of a power system are different from its frequency characteristics. The voltages at various nodes in an electrical power system are generally not identical; they depend mainly on the balance between active and reactive power supply and demand in each area, and are also closely related to the network structure (network impedance). Therefore, the voltage cannot be adjusted uniformly across the entire network; it can only be controlled through zone-based adjustments. 6. What are system voltage monitoring points and central points? What’s the difference? How is the voltage reference point generally selected? Answer: The nodes that monitor the voltage levels in a power system and assess the quality of voltage are known as voltage monitoring points. Important voltage support nodes in power systems are known as voltage hubs. Therefore, a voltage hub must be a voltage monitoring point, but a voltage monitoring point is not necessarily a voltage hub. 　The selection principles for the voltage hub point are: 1) The high-voltage busbars of regional thermal and hydroelectric power plants (the high-voltage busbars have multiple outgoing lines) ； 2) For zone selection, use the 220kV substation bus with a larger short-circuit capacity ； 3) Busbars of power plants with a large amount of local load. 7. Discuss the impacts of harmonics in power systems on the electrical grid Answer: The main impacts of harmonics on the power grid are as follows: The primary harm caused by harmonics to rotating equipment and transformers is the increase in additional losses and heat generation. In addition, harmonics can also cause vibration in these devices and generate noise; prolonged vibration can lead to metal fatigue and mechanical damage. 　　The main harm of harmonics to the line is the induction of additional losses. Harmonics can cause resonance in the inductance and capacitance of a system, leading to the amplification of harmonics. When harmonics cause resonance in the system, the harmonic voltage increases and the harmonic current rises, leading to erroneous operation of relay protection and safety automation devices. This can damage system equipment such as power capacitors, cables, motors, etc., resulting in system failures and threatening the safe operation of the power system. 　　Harmonics can interfere with communication equipment, increase power losses in electrical systems (such as line losses), and prevent reactive power compensation devices from functioning properly, thereby causing harm to both the system and its users. 　　The main measures to limit grid harmonics include: increasing the pulsation frequency of the converter units ； Installation of AC filters, active power filters ； Strengthen harmonic management. 8. What is stray supply current? What impact does it have on reclosing? How can it be prevented? Answer: After the faulty phase of a faulted circuit is disconnected from both sides, the capacitive and inductive coupling existing between the non-faulty phases and the disconnected phase continues to supply current to the faulty phase; this current is known as stray supply current. 　　Due to the presence of stray supply current, it affects arc extinction at the fault point, severely hindering the deionization of the arc path during a short circuit. Automatic reclosing can only succeed once the arc at the fault point is extinguished and the insulation strength is restored. When the subfeed current value is high, the arc extinction time at the fault point is longer, which will result in the failure of the reclosing attempt. 　　To reduce the stray supply current and improve the success rate of reclosing, measures can be taken to decrease this stray supply current; for example, adding a small reactor at the neutral point of the high-voltage shunt reactors on 500 kV medium-to-long distance lines, or installing fast single-phase ground switches on both sides of the line for a short period of time ； On the other hand, the actual arc extinction time can be used to set the reclosing time. 9. What are theoretical line losses and managerial line losses in power systems? Answer: Theoretical line losses are the inevitable losses that occur during the transmission and distribution of electrical energy; they are determined by the load conditions of the power grid at that time as well as the parameters of the power supply equipment. These losses can be calculated theoretically. Managing line losses refers to other losses and various unidentified losses that occur during the actual operation of the power grid. For example, an error in the user’s electricity meter may cause the meter readings to be lower than the actual value ； The amount of electricity lost due to missed or incorrect readings of the user’s electricity meter, leakage current resulting from poor insulation of live equipment, as well as electricity use without a meter and electricity theft. 10. What is natural power? Answer: An operating transmission line can generate reactive power (due to distributed capacitance) as well as consume reactive power (due to series impedance). When a certain value of active power is transmitted through the line, these two types of reactive power in the line are precisely able to balance each other; this value of active power is referred to as the line’s \"natural power\" or \"wave impedance power\". 11. How many types of neutral point grounding methods are there in power systems? What are high-current and low-current grounding systems? What are the criteria for classifying them? Answer: There are mainly two types of neutral point grounding methods in China’s power systems, namely: 1. Direct grounding of the neutral point (including grounding of the neutral point through a small resistor). 2. Neutral point not directly grounded method (including the method where the neutral point is grounded through an arc-suppression coil). In systems with the neutral point directly grounded (including systems where the neutral point is grounded through a small resistance), a single-phase ground fault results in a very large grounding short-circuit current; such systems are referred to as high-ground-current systems. 　　In systems where the neutral point is not directly grounded (including systems where the neutral point is grounded through an arc-suppression coil), when a single-phase ground fault occurs, since no short-circuit circuit is formed, the ground fault current is usually much smaller than the load current; hence such systems are referred to as low-ground-current systems. 　　In our country, systems with a ratio of X0/X1 ≤ 4–5 are classified as large grounding current systems, while those with a ratio of X0/X1 > 4–5 are classified as small grounding current systems. Note: X0 represents the zero-sequence reactance of the system, and X1 represents its positive-sequence reactance. 12. What are the characteristics of single-phase ground faults in systems with directly grounded and indirectly grounded neutral points in power systems? Answer: The operating modes of the power system neutral point fall into two main categories, namely directly grounded and indirectly grounded. The power supply reliability of a directly grounded system is relatively low. In such a system, when a single-phase ground fault occurs, another grounding point appears in addition to the neutral point, creating a short-circuit circuit. The current in the grounded phase is very high; to prevent equipment damage, it is necessary to quickly disconnect the grounded phase or even all three phases. The power supply reliability of ungrounded systems is relatively high, but higher requirements are also placed on the insulation level. In such a system, when a single-phase ground fault occurs, it does not form a direct short-circuit circuit; the current in the grounded phase is low, so there is no need to immediately disconnect that phase. However, the voltage of the ungrounded phases with respect to ground rises to 1.7 times the line voltage. 13. In a low-current grounding system, why is it necessary to ground the neutral point through an arc-suppression coil? Answer: When a single-phase grounding fault occurs in a low-current grounding system, the grounding point will experience all the capacitive current to ground from the power grid at the corresponding voltage level along the circuit where the fault exists. If this capacitive current is relatively large, intermittent arcs will be generated at the grounding point, causing overvoltage and a significant increase in the voltage of the healthy phases with respect to ground. Under the influence of arc grounding overvoltage, insulation damage may occur, leading to two-point or multi-point grounding short circuits and thereby exacerbating the accident. To this end, the measures taken in our country are as follows: when a single-phase ground fault occurs in a low-current grounding system grid, if the ground capacitance current exceeds a certain value (10 A for 35 kV grids, 10 A for 10 kV grids, and 30 A for 3–6 kV grids), an arc-suppression coil is installed at the neutral point. The purpose of this is to use the inductive current generated by the arc-suppression coil to compensate for the capacitive current during a ground fault, thereby reducing the current at the fault location, enhancing the ability to extinguish the arc automatically, and ensuring continuous power supply. 14. Under what conditions is the current in a single-phase ground fault greater than the current in a three-phase short circuit fault? Answer: When the zero-sequence impedance at the fault location is less than the positive-sequence impedance, the current in a single-phase ground fault will be greater than that in a three-phase short circuit fault. For example, in systems that make extensive use of autotransformers, due to the large number of grounded neutral points, the zero-sequence impedance at the point of system failure is often lower than the positive-sequence impedance; as a result, the current resulting from a single-phase ground fault is greater than that resulting from a three-phase short circuit fault. 15. What are the sequence parameters of a power system? What are the characteristics of zero-sequence parameters? Answer: In a symmetric three-phase circuit, the impedance encountered by currents flowing in different phase sequences varies; however, Ohm’s law still holds true for voltages and currents within the same phase sequence. The ratio of the phase-sequence voltage across any element to the corresponding phase-sequence current flowing through that element is called the sequence parameter (impedance) of that element. The zero-sequence parameter (impedance) is related to the network structure, particularly to the wiring configuration of the transformer and the way the neutral point is grounded. Under normal circumstances, the zero-sequence parameters (impedance) and the structure of the zero-sequence network differ from those of the positive and negative-sequence networks. 16. What is the relationship between zero-sequence parameters and the transformer’s connection type, neutral point grounding method, overhead ground wires of transmission lines, and adjacent parallel lines? Answer: For transformers, the zero-sequence reactance is related to their structure (whether it is three single-phase transformer units or a three-column transformer), the way in which the windings are connected (△ or Y), and whether they are grounded or not. 　 　When one side of a three-phase transformer is connected in a triangular configuration or in a star configuration with an ungrounded neutral point, the zero-sequence reactance of the transformer appears to be infinite from that side. Because no matter what the connection on the other side is, applying zero-sequence voltage on this side never allows the zero-sequence current to flow into the transformer. Therefore, only when the transformer’s windings are connected in star configuration and the neutral point is grounded is the zero-sequence reactance finite when viewing the transformer from this star side (although it can still be quite large at times). 　　For transmission lines, the zero-sequence reactance is related to factors such as the number of circuits in parallel lines, the presence of an overhead ground wire, and the conductivity of the ground wire. In three-phase circuits, the zero-sequence currents are in phase with each other, and the mutual inductance is high; as a result, the zero-sequence reactance is greater than the positive-sequence reactance. Moreover, the zero-sequence currents return through the ground and the overhead ground wire, which acts as a shield around the three-phase conductors, thereby reducing the zero-sequence magnetic flux and consequently decreasing the zero-sequence reactance. 　　When zero-sequence currents in the same direction flow through two parallel three-phase overhead transmission lines, not only does the mutual inductance between any two phases of the first circuit and the third phase contribute to magnetization, but the mutual inductance between all three phases of the second circuit and the third phase of the first circuit also contributes to magnetization; the same is true in reverse. This results in an further increase in the zero-sequence impedance of such lines. 17. What is the stable operation of a power system? How many categories are there for power system stability? Answer: Stable operation of a power system refers to the ability of the system to automatically return to its original operating state after being disturbed, or to transition to a new stable operating state with the help of control devices. 　　From a broad perspective, the stability of power systems can be divided into: 1. The stability issues related to the synchronous operation of generators (which, depending on the magnitude of the disturbances experienced by the power system, can be further categorized into static stability, transient stability, and dynamic stability) ； 　　2. Voltage stability issues caused by insufficient reactive power in the power system ； 3. Frequency stability issues caused by insufficient active power in the power system. 18. Why does the use of single-phase reclosing improve transient stability? Answer: With single-phase reclosing, since only the faulty phase is disconnected during a fault, rather than all three phases, there is no complete loss of connection between the power supply side and the load side during the period from the disconnection of the faulty phase until reclosing occurs (the electrical distance is much smaller in this case compared to when all three phases are disconnected). This reduces the acceleration area and increases the deceleration area, thereby improving transient stability. 19. Briefly describe synchronous oscillation and asynchronous oscillation in synchronous generators. Answer: Synchronous oscillation: When the input or output power of a generator changes, the power angle δ also changes. However, due to the inertia of the rotating parts of the generator, δ cannot immediately reach the new steady-state value; it needs to oscillate several times around the new δ value before it can stabilize at that new value. This process is known as synchronous oscillation, that is, oscillation while the generator remains in a synchronous operating state. 　　Asynchronous oscillation: Due to some disturbance, the generator experiences significant fluctuations in its power angle δ, which varies periodically between 0 and 360°, resulting in the generator losing synchronization with the power grid. During asynchronous oscillation, the generator alternates between operating in generator mode and operating in motor mode. 20. How to distinguish whether oscillations that occur in a system are asynchronous or synchronous oscillations? Answer: The obvious characteristic of asynchronous oscillation is that the system frequency cannot remain constant, and all electrical and mechanical quantities fluctuate significantly away from their rated values. Such as the ammeters and power meters of generators, transformers, and tie lines experiencing periodic large fluctuations ； The voltmeter experiences periodic large fluctuations; the voltage at the center of these oscillations fluctuates the most, and it periodically drops to values close to zero ； The transmission power of the interconnection between out-of-step power plants fluctuates back and forth ； The frequency of the transmitting system increases, while the frequency of the receiving system decreases and fluctuates. 　　During synchronous oscillation, the system frequency remains constant, the fluctuations in various electrical quantities are small, and the oscillations decay within a limited time, allowing the system to reach a new state of equilibrium. 21. What is the difference between system oscillation accidents and short-circuit accidents? Answer: The main difference between power system oscillations and short circuits is as follows: 1. During oscillations, the voltage and current values at various points in the system fluctuate back and forth, whereas in the case of a short circuit, the current and voltage values change suddenly. Furthermore, during oscillation, the rate of change of current and voltage values is slow, whereas in the case of a short circuit, the changes in current and voltage values are sudden and significant. 　　2. During oscillation, the phase angle between current and voltage at any point in the system changes as the power angle changes ； During a short circuit, the angle between current and voltage remains essentially constant. 　　3. The three phases of the system are symmetric during oscillation ； During a short circuit, the system may experience three-phase asymmetry. 22. What are the main causes of asynchronous oscillations in power systems? Answer: 1. The power transmitted through the transmission lines exceeds its limit, resulting in a loss of static stability ； 　　2. Short-circuit faults in the power grid, the disconnection of large-capacity generation, transmission, or transformation equipment, and sudden large changes in load can all lead to a disruption of the transient stability of the power system ； 　　3. A sudden opening of the circular system (or parallel double-circuit system) causes the impedance connecting the two systems to increase abruptly, leading to loss of stability and synchronization ； 　　4. Tripping or loss of excitation in large-capacity units increases the load on the system interconnection lines or causes a severe drop in system voltage, thereby reducing the stability limits of these interconnection lines and increasing the risk of stability failure ； 　　5. Asynchronous closing in the power supply room failed to bring synchronization. 23. What are the general phenomena during system oscillation? Answer: 1. The voltage meters, current meters, and power meters of generators, transformers, and circuits exhibit periodic and severe fluctuations, and generators and transformers emit rhythmic humming sounds. 　　2. The ammeters and power meters on the tie lines connecting generators or systems that are out of synchronization exhibit the greatest fluctuations. The area where voltage oscillations are most intense is the center of system oscillation, where it drops to near zero approximately once per cycle. As the distance from the oscillation center increases, the voltage fluctuations gradually decrease. If the impedance of the tie line is high and the capacitance of the power plants on both sides is also large, then the voltage oscillations at the ends of the line are small. 　　3. When the grid at the same time period is lost, although there is an electrical connection, a frequency difference still exists: the frequency at the sending end is higher, while that at the receiving end is lower with slight fluctuations. 24. What is low-frequency oscillation? What is the main reason for this? Answer: The sustained oscillation phenomenon that occurs between generators operating in parallel under small disturbances, with a frequency in the range of 0.2 to 2.5 Hz, is called low-frequency oscillation. Low-frequency oscillations arise due to the negative damping effect in power systems; they often occur in weakly interconnected, long-distance, heavily loaded transmission lines, and are more likely to happen when fast, high-amplification excitation systems are used. 25. What functions do parallel reactors in ultra-high voltage power grids have for improving the operation of power systems? Answer: 1. Reduce the capacitive effect on lines under no-load or light-load conditions, in order to lower power-frequency transient overvoltages. 　　2. Improve the voltage distribution on long-distance transmission lines. 　　3. It ensures that the reactive power in the circuit is balanced as much as possible at the source under light load conditions, preventing unreasonable flow of reactive power and simultaneously reducing power losses in the circuit. 　　4. When large generators are connected in parallel with the system, the power-frequency steady-state voltage on the high-voltage bus is reduced, which facilitates the synchronous connection of the generators. 　　5. Prevent self-excitation resonance that may occur when the generator is connected to long circuits. 　　6. When a grounding device with a small reactor is used at the neutral point of the reactor, a small reactor can also be employed to compensate for the inter-phase and phase-to-ground capacitances in the circuit, thereby accelerating the automatic extinction of the stray current and facilitating the use of single-phase rapid reclosing. Q&A on Power Dispatching Technology -- Short Answer Questions Series 2 26. What is the purpose of connecting a small reactor at the neutral point of high-voltage reactors in a 500 kV power grid? Answer: Its function is to compensate for the capacitance of the compensation wire with respect to ground, thereby making the relative impedance to ground tend toward infinity and eliminating the longitudinal component of the stray supply current, thus increasing the success rate of reclosing. The size of the small reactive impedance at the neutral point of the parallel high-voltage reactor should be determined through computational analysis in order to prevent ferroresonance. 27. What is subsynchronous oscillation in generators? What is the cause of it? How to prevent it? Answer: When a generator is connected to the system via a circuit with series capacitive compensation, if the level of series compensation is high, the electrical resonance frequency of the network is more likely to resonate with the natural torsional vibration frequency of the large steam turbine generator’s shafting, resulting in damage due to torsional vibration of the generator’s shaft. This resonance frequency is usually lower than the synchronous frequency (50 Hz), and it is referred to as subsynchronous oscillation. In high-voltage direct current transmission lines (HVDC) and static var compensators (SVC), subsynchronous oscillations can also be induced when their control parameters are not selected appropriately. 　　The measures include: 1. Adding or modifying primary equipment; 2. Reducing the degree of series compensation; 3. Providing damping for torsional vibration modes through secondary equipment (similar to the principle of PSS). 28. How many categories are there for overvoltages in power systems? What are their causes and characteristics? Answer: Overvoltages in power systems are mainly classified into the following types: atmospheric overvoltages, power-frequency overvoltages, switching overvoltages, and resonance overvoltages. 　　The causes and characteristics are as follows: Atmospheric overvoltage: It is caused by direct lightning strikes; its characteristics include a short duration and high intensity. It is directly related to the intensity of lightning activity, and has no relation to the voltage level of the equipment. Therefore, the insulation level of systems below 220 KV is often determined by the need to prevent atmospheric overvoltages. 　　Power frequency overvoltage: It is caused by the capacitive effects of long transmission lines and sudden changes in the operation mode of the power grid. It is characterized by a long duration and a low level of overvoltage; generally, it poses little risk to equipment insulation. However, it plays an important role in determining the insulation levels for ultra-high voltage and long-distance power transmission. 　　Operation overvoltage: Caused by switching operations in the power grid; it is characterized by randomness, but the overvoltage magnitude is high under the most unfavorable conditions. Therefore, the insulation level of ultra-high voltage systems of 30 KV and above is often determined by the need to prevent switching overvoltages. 　　Resonant overvoltage: It is caused when a resonant circuit is formed by the system’s capacitance and inductance components. Its characteristics include a high multiple of overvoltage and a long duration. 29. What is counterstroke overvoltage? Answer: In power plants and substations, if lightning strikes the lightning rods, the lightning current flows into the ground through the grounding conductors of the framework. Due to the inductance of the framework and the resistance of the ground connection, a very high potential with respect to the ground is generated on the framework. This high potential creates a large voltage difference across nearby electrical equipment or live wires. If the distance between them is small, it will cause the lightning rod framework to discharge electricity onto other equipment or wires, leading to backflashover and resulting in accidents. 30. What is step voltage? Answer: The current that flows into the ground through the grounding grid or grounding electrode creates a spatially distributed electric field above and beneath the ground surface, and a potential difference is generated at various distances from the grounding electrode; this potential difference is known as step voltage. Step voltage is proportional to the intensity of the current flowing into the ground, and inversely proportional to the square of the distance from the grounding electrode. 　　Therefore, in the area near the grounding electrode, if a strong lightning current is present and the step voltage is high, it can easily cause harm to humans and animals. 31. What are the main causes of power system power-frequency overvoltage? Answer: 1. The capacitive effect of long unloaded lines ； 2. Voltage rise in the non-faulty phases caused by asymmetric short circuits ； 3. Rise in power frequency voltage caused by load rejection. 32. What are the main measures taken by power systems to limit power-frequency overvoltage? Answer: 1. Use parallel high-voltage reactors to compensate for the capacitive effect of unloaded lines ； 2. Use a static var compensator SVC to compensate for the capacitive effect of unloaded lines ； 3. Direct grounding of the transformer’s neutral point can reduce the increase in power-frequency voltage caused by asymmetric grounding faults ； 4. The generator is equipped with a high-performance excitation regulator or voltage regulation device, which enables it to suppress the effect of capacitive current on the generator’s field excitation armature reaction when the load is suddenly removed, thereby preventing the occurrence and progression of overvoltage. 5. The generator is equipped with a responsive speed control system, which enables effective limitation of the power-frequency overvoltage caused by an increase in the generator’s speed during sudden load rejection. 33. What is operational overvoltage? What are the main ones? Answer: Operating overvoltage is an overvoltage caused by switch operations or fault tripping in the power grid. It mainly includes: 1. Overvoltage caused by the disconnection of unloaded lines ； 2. Overvoltage caused by closing an unloaded line ； 3. Overvoltage caused by the removal of an unloaded transformer ； 4. Overvoltage caused by intermittent arc grounding ； 5. Suppress overvoltage caused by the large loop opening and closing. 34. What are the measures to limit switching overvoltages in power grids? Answer: The measures to limit switching overvoltage in power grids include: (1) Using high-voltage switches with strong arc-quenching capabilities ； (2) Improve the synchronization of switch operations ； (3) Installing parallel resistors at the switch contacts ； (4) Use surge arresters with good performance, such as zinc oxide surge arresters ； (5) Operate the grid’s neutral point in a directly grounded mode. 35. What is power system resonance overvoltage? What are the different types? Answer: In power systems, certain inductive and capacitive components can form various oscillation circuits when the system is under operation or in case of a fault. Under the influence of certain energy sources, series resonance can occur, leading to severe overvoltage in some components of the system. This phenomenon is known as resonant overvoltage in power systems. Resonant overvoltages can be classified into the following types: (1) Linear resonant overvoltage. The resonant circuit is composed of inductive elements without cores (such as the inductance of transmission lines and the leakage inductance of transformers), or inductive elements with cores whose excitation characteristics are nearly linear (such as arc suppression coils), together with capacitive elements in the system. (2) Ferromagnetic resonance overvoltage The resonance circuit is composed of inductive elements with cores (such as open-core transformers and voltage transformers) and the capacitive elements of the system. Due to the saturation phenomenon of the core inductive element, the inductance parameter of the circuit becomes nonlinear. Circuits containing such nonlinear inductive elements can experience ferromagnetic resonance when certain resonance conditions are met. (3) Parameter resonance overvoltage: A circuit is formed by inductive elements whose inductance parameters vary periodically (such as the synchronous reactance of salient-pole generators, which varies periodically between Kd and Kq), and system capacitance elements (such as unloaded lines). When these parameters are properly matched, the periodic variation of the inductance leads to a continuous supply of energy to the resonant system, resulting in parameter resonance overvoltage. 36. What are the functions of lightning conductors and lightning rods? What is the function of a lightning arrester? Answer: The function of lightning conductors and lightning rods is to prevent direct lightning strikes, thereby reducing the likelihood of such strikes affecting the electrical equipment within their protection range (such as overhead power transmission lines and substation equipment). The function of a lightning arrester is to attenuate incoming surge waves by utilizing parallel discharge gaps or nonlinear resistances, thereby reducing the voltage amplitude experienced by the protected equipment. Arresters can be used to protect against both atmospheric overvoltages and switching overvoltages. 37. What are the hazards of a grounding grid resistance that does not meet the specifications? Answer: The grounding grid serves both for operational grounding and protective grounding. When the grounding resistance is too high, (1) in the event of a grounding fault, the voltage at the neutral point increases, which can cause the voltages of the healthy phases and the neutral point to rise above the levels required by insulation standards, leading to equipment damage. (2) During a lightning strike or the impact of lightning waves, the high current generated results in very high residual voltages, which pose a threat of backflow to nearby equipment. Additionally, this reduces the ability of the grounding system to protect the live conductors of the equipment (such as overhead transmission lines and electrical equipment in substations) against lightning, failing to meet the design requirements and thus causing damage to the equipment. 38. What are the main methods for peak shaving in power grids? Answer: (1) When a pumped storage power plant is switched from generator mode to motor mode, its peak-shaving capacity is close to 200% ； (2) Hydroelectric units reduce load for peak-shaving or shut down; peak-shaving is carried out at the minimum output (taking vibration limits into account), which is close to 100% ； (3) The fuel (gas) generator set reduces its load, with a peak-shaving capacity of over 50% ； (4) For coal-fired units, the peak-shaving capabilities in cases of load reduction, start-up and shutdown for peak regulation, operation with reduced steam supply, and operation at variable parameters are 50% (which can be increased to 60% if oil is used or auxiliary burners are installed), 100%, 100%, and 40% respectively ； (5) Load reduction for peak shaving in nuclear power plants ； (6) Achieve peak shaving and load leveling through user-side load management methods. 39. What functional modules does economic dispatch software include? Answer: (1) Load forecasting; (2) Optimization of unit combinations; (3) Fitting and compilation of unit consumption characteristics and slight increase in consumption characteristics; (4) Slight increase scheduling; (5) Line loss correction. In the case of a hybrid hydro-thermal power system, it is necessary to use large-system decomposition and coordination methods or other algorithms to optimize the hydroelectric and thermal power systems separately, and then adjust the equivalent coefficients between hydroelectric and thermal power based on daily water usage limits or control conditions for the initial and final water levels in reservoirs. 40. Briefly describe what basic information is required for the economic dispatch of power systems? Answer: (1) Thermal characteristics of thermal power units – The thermal characteristics of thermal power units under different load conditions need to be determined through thermal tests, including efficiency tests for the boiler as well as tests on the heat and steam consumption of the turbine ； (2) Consumption characteristics of hydroelectric units: These characteristics represent the relationship between the unit’s output and flow rate at different head levels; they should also be determined through experiments or based on the manufacturer’s design data ； (3) Startup and shutdown losses of thermal power units ； (4) Basic parameters for line loss calculation ； (5) Water-coal conversion equivalent coefficient. 41. What is a relay protection device? Answer: It is an automated system and device designed to send warning signals to the operators on duty in a timely manner, or to issue tripping commands directly to the switches under control, when there are faults in the electrical components of the power system (such as generators, lines, etc.) or when events occur that threaten the safe operation of the system, thereby preventing the further progression of such issues. The complete set of equipment used to implement such automation measures is generally referred to as relay protection devices. 42. What is the role of relay protection in power systems? Answer: The main tasks of relay protection can be divided into two parts: 1. When a fault occurs in a component of the power system that is under protection, the relay protection device associated with that component should promptly and accurately send a tripping command to the switch closest to the faulty component, so that the faulty component can be disconnected from the power system as quickly as possible. This helps to minimize damage to the component itself, reduces the impact on the reliable supply of electricity in the power system, and meets certain specific requirements of the power system (such as maintaining its transient stability). 　2. Response: It detects abnormal operating conditions of electrical equipment, and based on these abnormal conditions as well as the conditions regarding the equipment’s operation and maintenance (such as whether there are personnel on duty at all times), it sends out signals so that the on-duty personnel can take action. Alternatively, the device can make automatic adjustments, or it can disconnect those electrical devices whose continued operation could lead to accidents. Relay protection devices that respond to abnormal operating conditions are permitted to operate with a certain delay. 43. Briefly describe the basic principles and composition of relay protection? Answer: Relay protection primarily relies on changes in electrical parameters such as current, voltage, power, and frequency that occur when components in the power system experience short circuits or other abnormalities; these changes form the basis for the operation of relay protection. There are also other physical parameters involved, 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 which physical quantity is being monitored, relay protection devices consist of a measurement section (and setting adjustment section), a logic section, and an actuation section. 44. How to ensure the reliability of relay protection? Answer: Reliability is primarily ensured by properly configured relay protection devices with excellent quality and technical performance, as well as proper operation, maintenance, and management. No electrical equipment (circuits, 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 switches. When any set of relay protection devices or any group of switches fails to operate, another set of relay protection devices can be used to operate another group of switches in order to eliminate the fault. In all cases, it is required that the DC power supplies for these two sets of relay protection devices and switches be powered by separate fuses. 45. To ensure the selectivity of power grid relay protection, what requirements must be met regarding the coordination between relay protections in higher and lower levels of the power grid? Answer: The setting values of relay protections in different levels of the power grid (including those at the same level, as well as those in the level above and 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 with those of the relay protection in the higher-level circuit or component, both in terms of sensitivity and operating time, so as to ensure that faults can be isolated selectively when they occur in the power grid. 46. Under what circumstances is it permissible to sacrifice some degree of selectivity in relay protection? Answer: 1. For the feed lines connected to the supply transformers, whether there is one transformer in operation or multiple transformers operating in parallel (including situations where there are multiple T-connected supply transformers or feed lines), it is permissible to set the quick-acting protection on the line side to avoid faults occurring on the other side of the transformer’s busbar. When necessary, the line quick-break section protection can operate with a short time delay. 　　2. For series-powered supply lines, if the operating time of the protection devices on the power supply side is excessively extended 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 points without coordination, thereby reducing the number of coordination levels and shortening the operating time. 　　3. For the coordination of the internal protection for dual-circuit systems, it can be based on the operation of the main protection for the dual circuits (such as cross-link differential protection), or 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 permissible 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 configuration, it is allowed to designate a predetermined disconnection point or a single disconnection line. 47. To ensure sensitivity, how should the setting value of the last stage of ground protection be determined? Answer: The last stage of ground 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: for 220 kV lines, 100 Ω ； 330kV line, 150Ω ； 500kV line, 300Ω. 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 the line, it is permitted for the relay protection devices on both sides of the line to operate in sequence to isolate the fault. For 110 kV lines, considering the requirements for sensitivity in the event of possible high-resistance ground faults, the current setting value of the zero-sequence current protection at the farthest section should generally not exceed 300 A. In such cases, it is permissible for the zero-sequence current protections on both sides of the line to operate in sequence to eliminate the fault. 48. Briefly describe what the configuration principles for 220 kV line protection are 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. For backup protection against 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. 49. Briefly describe the basic principle of line longitudinal protection? 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. 　　Its basic principle is to use a specific relationship between the discrimination values on both sides of the line as a criterion; that is, the discrimination values are transmitted to the opposite side via channels, and then each side determines whether a fault is within the area or outside it based on the relationship between the discrimination values on the opposite side and those on its own side. Therefore, discriminants and channels are the main components of relay protection devices. 50. What is the “far backup” of relay protection? What is “near reserve”? Answer: \"Remote backup\" refers to the situation where, when a component fails and its protection device or switch refuses to operate, the protection devices of adjacent components on the same power supply side take action to isolate the fault. 　　"\"Near-backup\" refers to the use of a dual configuration to enhance the protection of the components themselves, thereby reducing the likelihood of protection failure in the event of a fault within that area. Additionally, switch failure protection is installed; it is activated when a switch fails to trip, in order to disconnect other switches on the same bus as the faulty switch, or to remotely disconnect switches on the opposite side. Q&A on Power Dispatching Technology -- Short Answer Questions Series 3 51. Briefly describe the basic characteristics of directional high-frequency protection Answer: Directional high-frequency protection compares the fault direction as seen at each end of the line, in order to comprehensively determine whether it is an internal fault or an external fault of the line. If the direction observed in the event of an internal fault in the protected circuit is taken as the positive direction, then in the case of an external fault in the protected circuit, the direction observed on one side will always be the opposite. Its characteristics are: 1) It requires that the forward discrimination starting element have sufficient sensitivity to faults at the end of the line ； 　　2) A dual-frequency transceiver must be used. 52. Briefly describe the basic characteristics of phase difference high-frequency protection Answer: Frequency difference protection is a type of high-frequency protection that compares the phases of the power frequency currents on both sides of the line to be protected. When the phases of the fault currents on both sides are the same, the protection is locked out; when the phases of the currents on both sides are opposite, the protection operates to trip. Its features are: 1) it can detect various symmetric and asymmetric faults in the full-phase condition, 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) Not affected by voltage circuit disconnections ； 4) High requirements are placed on the transceivers and channels; coordinated testing is necessary for protection on both sides 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. 53. What are the basic characteristics of high-frequency blocking distance protection? Answer: High-frequency blocking distance protection uses directional distance protection devices installed along the line as the primary protection mechanism; corresponding transmitting and receiving equipment is added to establish a longitudinal distance protection system through the communication channels. Its features are: 1. It can respond to various symmetric and asymmetric faults in a sufficiently sensitive and rapid manner ； 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. 4. It is not an independent protection device; when distance protection is disabled or fails, and needs to be shut down due to abnormalities, this protection must also cease operating. 54. What is the main role of line longitudinal protection in power grids? Answer: Since line longitudinal protection enables rapid response across the entire line in a power grid, it helps to ensure the stability of parallel operation in power systems, increase transmission capacity, reduce the extent of damage caused by faults, and improve the coordination between backup protections. 55. What are the different types of channels for line longitudinal protection? Answer: 1. Power line carrier longitudinal 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). 56. What are the main types of signals used in line longitudinal protection? What is their function? Answer: The signals for line longitudinal protection are divided into three types: blocking signals, permission signals, and tripping signals. Their functions are as follows: 1. Blocking signals: These are signals that prevent the protection mechanism from triggering a trip; in other words, the absence of blocking signals is a necessary condition for the protection to trigger a trip. Protection will trigger a trip only when both conditions are met: the operation of the local protection device and the absence of a lockout signal. 　　2. Permit signal: It is the signal that allows the protection device to operate in tripping mode; in other words, the presence of a permit signal is a necessary condition for the protection device to trigger a trip. Protection will operate to trip only when both conditions are met: the activation of the local protection device and the presence of an allowable signal. 　　3. Tripping signal: It is the signal that directly causes tripping. At this point, it does not matter whether the protective device operates or not; as long as the tripping signal is received, the protection mechanism will trigger a trip. Remote tripping protection makes use of this tripping signal. 57. 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 external faults, 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, leading to 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 element with a lower setting value operates first than those with a higher setting value, this ensures that in the event of an external short circuit, when the element with the higher setting value activates the phase comparison element, the protection system will definitely receive a locking signal, preventing any false operations. 58. Briefly describe the basic working principle of direction comparison high-frequency protection. Answer: The basic working principle of direction comparison high-frequency protection is to compare the fault directions measured on both sides of the line, in order to determine comprehensively whether it is an internal or external fault of the protected line. If the direction of the fault measured when there is a fault inside the protected line is taken as the positive direction, then in the case of a fault outside the protected line, one of the sides will show the opposite direction. 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 forward and reverse direction faults. The so-called fault direction of the comparison circuit refers to comparing the operating behavior of specific distinguishing elements on both sides. 59. What is the impact of disabling line high-frequency protection on the use of reclosing? Answer: When all high-frequency protections on a line are disabled, two factors may affect the use of circuit reclosing: 1. Without high-frequency protection in operation, backup protections (with delay) must be used to eliminate line faults; this means that faults cannot be cleared quickly, resulting in a decrease in the system’s stability. If reclosing is attempted on 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. 60. Why do operators need to exchange signals daily while high-frequency protection is in operation to check the high-frequency channel? Answer: China’s power systems typically operate in a mode where there is no high-frequency current in the high-frequency channels under normal conditions. Since high-frequency channels involve the equipment at both substations and are also related to the operating conditions of the transmission lines, the aging and failures of various processing devices and transceiver components on these channels can cause attenuation. Any issue in any part of the high-frequency channel can affect the proper operation of high-frequency protection systems. 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, 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 transceiver, in order to ensure that the high-frequency component of the protection device can function reliably in the event of a fault. 61. What is zero-sequence protection? Why is it necessary to install separate zero-sequence protection in large-current grounding systems? Answer: In a large-short circuit current grounding system, when a grounding fault occurs, 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 the 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. Zero-sequence protection can overcome this drawback, because: ① During normal operation of the system and 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 ground fault occurring on the △ side does not generate a zero-sequence current on the Y side; therefore, the operating time of the zero-sequence protection device does not need to be synchronized with that of the line protection devices connected after such a transformer, and it can have a shorter operating time. 62. Briefly describe the characteristics of directional zero-sequence current protection and its role in ground fault protection? Answer: Directional zero-sequence current protection is a multi-stage current direction protection device that responds to the magnitude and direction of the zero-sequence current component in the event of a ground fault in a line. In the power lines of China’s high-current grounding systems at various voltage levels, such protective devices are installed in accordance with regulatory requirements as the primary form of protection. 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 directional zero-sequence current protection is approximately 97%, making it one of the protections with the highest correct operation rate among those used for high-voltage lines. Directional zero-sequence current protection has a series of advantages, including simple principle, reliable operation, low equipment investment, easy operation and maintenance, and a high correct operation rate. 63. What are the advantages of zero-sequence current protection? Answer: Directional and non-directional zero-sequence current protection represent simple yet effective methods for grounding protection. Their advantages include: 1. A simple structure and working principle, with a higher rate of correct operation compared to other more complex protections. 2. The entire protection system has fewer intermediate stages, which allows for rapid response, especially in the case of faults that occur nearby; this helps 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 coverage remains relatively stable. 4. The absolute value of the zero-sequence current in the protection reaction is less affected by the fault transition resistance. 5. The protection setting values are not affected by load current, nor are they significantly impacted by short-circuit faults in other ungrounded neutral system networks; therefore, a higher sensitivity for the protection delay time can be adopted. 64. Why are sensitive and insensitive sections provided in zero-sequence current protection? Answer: In circuits that use three-phase reclosing or combined reclosing, in order to prevent erroneous operation of the zero-sequence current protection due to oscillations that may occur when the three phases do not close simultaneously during the three-phase reclosing process, or during partial-phase operation during single-phase reclosing, a four-stage protection system consisting of two first-stage sections is often used. 　 　The sensitivity range is set based on the maximum zero-sequence current that occurs when avoiding a single-phase or two-phase ground short circuit at the end of the protected circuit. It has a low operating current and a large protection range, but it gets locked in the partial-phase operation state after a single-phase fault is cleared. At this time, if another phase fails, it is necessary to wait until the reclosing occurs, and then trigger an accelerated trip after reclosing. It prolongs the tripping time, which may cause adjacent lines in the system to trip at a higher level due to inadequate protection. Therefore, an additional set of less sensitive protection is added. 　　The setting of the less sensitive stage is based on the maximum zero-sequence current that occurs when oscillations take place despite operating in a non-full-phase condition; its operating current is high enough to allow it to overcome the zero-sequence current under such non-full-phase conditions. Both stages operate in an instantaneous manner. What are the advantages of ground distance protection? Answer: The greatest advantage of ground distance protection is that its protection range remains constant over time, and it is also possible to obtain a second stage of ground protection with a short delay 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 a 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 reliable selectivity between it and the zero-sequence current protections of adjacent lines. 65. What is the principle of hierarchical coordination for multi-stage zero-sequence current protection? What are the consequences of not adhering to the principle of step-by-step coordination? Answer: The principle of hierarchical coordination among adjacent protections requires that these protections be able to coordinate with each other in terms of sensitivity and operating time. There should be no overlap between the operating characteristics of the upper and lower levels of protections, and a certain margin should be maintained. Practice has shown that the principle of step-by-step coordination is an important one for ensuring selective operation of grid protection; otherwise, cross-level tripping of protections is inevitable, leading to serious consequences such as the escalation of grid accidents. 66. What is distance protection? What are the characteristics of distance protection? Answer: Distance protection is a protective device based on distance measurement elements. Its operation and selectivity depend on the comparison between local measurement parameters (impedance, reactance, direction) and the parameters set for the protected section. Since impedance and reactance are proportional to the length of the transmission line, it is called distance protection. 　　Distance protection is mainly used for the protection of transmission lines, and is generally of three-stage or four-stage type. The first and second sections are directional in nature and serve as the main protection for this line; the first section provides protection for 80%–90% of this line. The second section provides protection for the entire line and serves as a backup protection for adjacent busbars. The third section may have a direction or not; some also include a fourth section without a direction, which serves as a backup protection for the main line and adjacent lines. 　　The complete distance protection system includes basic components such as fault initiation, fault distance measurement, time logic circuits and AC voltage circuit open-circuit interlocks; some systems also feature oscillation interlocks and devices for continuous monitoring of the entire protection system. Some ground distance protection systems are equipped with separate phase-selection elements as well. 67. What is the impact of the errors in voltage transformers and current transformers on distance protection? Answer: The errors in voltage transformers and current transformers affect the accuracy of impedance relay-based distance measurements. Specifically, the angular error and ratio error of current transformers, the angular error and ratio error of voltage transformers, as well as the voltage drop on the secondary cables of voltage transformers, will cause phase errors and magnitude errors in the voltage and current at the terminals of the impedance relay, thereby affecting the accuracy of impedance measurement. 68. What are the blocking devices for distance protection? What is their function? Answer: Distance protection has two types of blocking devices: AC voltage loss blocking and system oscillation blocking. AC voltage loss interlock: When the secondary circuit of the voltage transformer is disconnected, the voltage applied to the relay decreases, which resembles a short-circuit condition; as a result, the protection device may operate erroneously. Therefore, an interlock mechanism is necessary. Oscillatory locking: The protection is disabled for 0.12–0.15 seconds when a negative sequence component appears due to a system fault, allowing the protective action to take place; thereafter, the protection is reactivated to prevent erroneous operation during system oscillations. 69. What are the effects of power system oscillations on relay protection devices? Answer: When the power system oscillates, it has an impact on the current relays and impedance relays of relay protection devices. 1. Impact on current relays. When the oscillating current reaches the operating current of the relay, the relay operates ； When the oscillating current drops to the relay’s return current, the relay returns. Therefore, the current quick-break protection will definitely malfunction. Under normal circumstances, the oscillation period is short; when the time delay of the protective device is greater than 1.5 seconds, it is possible to avoid oscillations and prevent incorrect operation. 2. Impact on impedance relays. During periodic oscillations, the voltage at any point in the power grid and the current flowing through the lines change as the phase angle between the electromotive forces of the sources on either side varies. As the oscillating current increases and the voltage drops, the impedance relay may operate ； The oscillating current decreases, the voltage rises, and the impedance relay returns. If the contact closure time of the impedance relay is long, it will cause the protection device to malfunction. 70. What is automatic reclosing? Why is it used in power systems? Answer: An automatic reclosing device is an automated system that re-energizes a circuit breaker that has been tripped due to some fault, as needed. Experience in power system operation shows that the vast majority of faults in overhead lines are transient, with permanent faults accounting for less than 10% in general. Therefore, after the short-circuit fault is cleared by the operation of relay protection, the arc will extinguish automatically, and in the vast majority of cases, the insulation at the short-circuit site can be restored automatically. 　　Therefore, automatic reclosing will close the switch again, which not only improves the safety and reliability of power supply and reduces power outage losses, but also enhances the transient stability of the power system and increases the transmission capacity of the lines. It can also compensate for or reduce the losses caused by incorrect operation of switches or relay protection devices that result in tripping. Therefore, overhead lines generally require automatic reclosing devices. 71. How are automatic reclosers classified? Answer: (1) Classified by the mechanism 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 types. (3) Based on the number of actions, they can be divided into single-action and multi-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 reclosing can be further divided into voltage-free detection reclosing, synchronous reclosing detection, and asynchronous reclosing. 72. 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 and reliable; it can also compensate for or reduce the impacts and losses caused by accidental activation or premature tripping of circuit breakers. It enhances the reliability of power supply and the stability of system operation, showing good performance in grids at all levels. It is the basic startup method for all reclosing systems. Its disadvantage 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; moreover, a reclosing activation element triggered by the protections is also required. Its disadvantage is that it cannot compensate for or reduce the impacts and losses caused by accidental operation of the circuit breaker. 73. What adverse effects does reclosing on a permanent fault have on the power system? Answer: 1. It exposes the power system to the impact of fault currents once again ； 2. It makes the operating conditions for the switch more severe, as the switch has to interrupt the fault current twice within a short period of time. 74. What are the selection principles for the reclosing mode of single-side powered transmission lines? Answer: 1. Under normal circumstances, three-phase single-stage reclosing is used. 　　2. When the switching capacity permits, secondary reclosing can be employed in the following situations: 　　　1) Single-circuit lines without remote control that originate from substations without regular on-site personnel ； 　　　2) Single-circuit lines that supply power to critical loads without a backup power source. 　　3. If a two-time reclosing method is used, it is necessary to conduct stability calculations for verification before reclosing is permitted. 75. What are the special requirements for reclosing in double-fed power lines? Answer: For reclosing in double-fed power lines, in addition to meeting the basic requirements that apply to automatic reclosing devices, the following requirements must also be satisfied: (1) When a fault occurs on the line, the protection devices on both sides may operate to trip the circuit at different times. Therefore, the reclosing mechanisms on both sides of the line must ensure that reclosing takes place only after the switches on both sides have been opened. (2) After a fault causes a trip on the line, there is often the issue of whether the power supplies on both sides are in sync at the time of reclosing, and whether asynchronous reclosing is permissible. Q&A on Power Dispatching Technology -- Short Answer Questions Series 4 76. Why can a capacitive automatic reclosing device only perform reclosing once? Answer: A capacitive reclosing device utilizes the instantaneous discharge and prolonged charging of capacitors to achieve one instance of reclosing. If the switch trips as a result of protection activation due to a permanent short circuit, it will trip a second time after automatic reclosing attempts once. At this point, the trip position relay is restarted; however, since the contact of the time relay remains closed for an extended period before the entire reclosing circuit returns to its normal state, the capacitor cannot continue to charge because it is connected in parallel with the coil of the intermediate relay. As a result, the intermediate relay cannot be activated again. After the entire circuit returns to normal, it takes 20–25 seconds for the capacitor to charge again, which ensures that the reclosing circuit can emit only one closing pulse. 77. What is pre-reclosure acceleration? What are its advantages and disadvantages? Answer: The pre-reclosure acceleration protection method is generally used in radial circuits with several sections connected in series, where the reclosing device is installed only on the section closest to the power source. When a fault occurs on a line (including adjacent lines and subsequent lines), the protection device located closer to the power source will first act instantaneously to trip without any selection, and then reclosing is used to compensate for this non-selective action. 　　Its disadvantage is that the time required to eliminate permanent faults is long, and the circuit breaker in the closing device operates frequently; if the circuit breaker or the reclosing mechanism fails to function, it will result in an expanded area of power outage. The pre-reclosing acceleration protection scheme is mainly applicable to direct feed lines below 35 kV that originate from power plants or main substations. 78. What is post-reclosure acceleration? Why is post-acceleration not used when performing synchronized reclosure tests? Answer: When a fault occurs in the line, the protection device acts selectively to isolate the fault, and then reclosure takes place once to restore power supply. If it coincides with a permanent fault, the protective device will operate to disconnect the circuit breaker without any time delay and without selection; this mechanism is known as post-reclosure acceleration. 　 　Synchronized reclosing involves attempting to reclose the circuit only when there is no voltage on one side of the circuit, and the frequencies at both ends of the other side are within certain allowable limits. If the line is suffering from a permanent fault and breaks down again after voltage restoration, the synchronous reclosing function will not attempt to reclose in such a situation; therefore, it makes no sense to use the accelerated reclosing method after activating the synchronous reclosing function. If it is a transient fault, after voltage-free reclosing, the line has been successfully reconnected and the fault no longer exists; therefore, there is no need for post-reclosure acceleration. Post-acceleration is not used for simultaneous reclosing during this period, which can prevent misoperation caused by the inrush current during closing. 79. A line is equipped with two sets of microcomputer-based protection systems. The line is operated in single-phase reclosing mode; how should these two sets of microcomputer-based protection systems for reclosing be used? Answer: A line is equipped with two sets of microcomputer-based protection systems. The switches for both sets of microcomputer-based reclosing devices are set to the single-operation mode, and only one set of closing output circuits is activated. If both the closing outputs of the two reclosing circuits are activated simultaneously, it may cause the circuit breaker to reclose twice in a short period of time. 80. What electrical quantities do microcomputer fault recorders usually record? Answer: For voltage systems of 220 kV and above, microcomputer-based fault recorders generally need to record voltage values (UA, UB, UC, 3U0) and current values (IA, IB, IC, 3I0) ； High-frequency protection high-frequency signal quantities, as well as on-off quantity signals such as protection operation status and switch position. 2006-4-1 15:18:07 Questions and Answers on Power Dispatching Technology -- Short Answer Questions 81. What are the characteristics of transformer inrush current? Answer: 1. It contains a large proportion of aperiodic components, which often causes the surge to lean to one side of the time axis. 2. It contains a large number of high-order harmonic components, with the second harmonic being the dominant one. 3. There are interruptions between the excitation inrush waveforms. 82. What are the current methods used in transformer differential protection to prevent the impact of inrush current? Answer: The main methods currently used to prevent the impact of excitation inrush currents are: 1. Using differential relays with rapidly saturating cores. 2. Identify the differences between the waveforms of short-circuit current and excitation inrush current, requiring an interruption angle of 60° to 65°. 3. Quadrature harmonic braking is utilized, with a braking ratio of 15%–20%. 83. What are the causes of unbalanced current under steady-state conditions in transformer differential protection? Answer: 1. The unbalanced current is caused by the different models of current transformers on each side of the transformer, that is, by the differences in their saturation characteristics and excitation currents. It must meet the requirements of the 10% error curve for current transformers. 2. Unbalanced current caused by the difference between the actual current transformer turns ratio and the calculated turns ratio. 3. Unbalanced current caused by changing the transformer tap. 84. How is the unbalanced current generated in the transformer differential protection under transient conditions? Answer: 1. The aperiodic component of the short-circuit current is mainly the excitation current of the current transformer, which causes the core to become saturated, leading to increased errors and thus unbalanced currents. 2. The inrush current during no-load switching of a transformer occurs only when there is current on one side of the transformer. 85. How is the grounding protection for the transformer’s neutral point gap implemented? Answer: The grounding protection for the transformer’s neutral point gap utilizes a combination of a zero-sequence current relay and a zero-sequence voltage relay, with a time delay of 0.5S. 　　When a ground fault occurs in the system, zero-sequence current is generated during discharge in the discharge gap, which causes the zero-sequence current relay of the special current transformer installed at the grounded end of the discharge gap to operate ； If the discharge gap does not discharge, the zero-sequence voltage relay is activated. 　　When intermittent arc grounding occurs, the time element shared by the gap protection must not return midway to ensure the reliable operation of the gap grounding protection. 86. What are the configuration principles and characteristics of the high-impedance differential protection for transformers? Answer: High-impedance differential protection for transformers is typically installed on large transformers as an additional set of primary protection mechanisms based on a different principle. Its differential CT uses the 220 KV side and the 500 KV side of the transformer (both in three-phase configuration), as well as the neutral point at 87. Explain the basic working principle of the transformer gas protection system Answer: Gas protection is the primary protection for transformers, and it can effectively detect internal faults in the transformer. The light gas relay consists of an open cup, reed contacts, etc., and is used for signaling. The heavy gas relay is composed of a baffle, spring, reed contacts, etc., and functions to trigger tripping. 　 　During normal operation, the gas relay is filled with oil; the open cup is submerged in the oil and remains in an upward position, causing the reed contacts to be disconnected. When there is an internal fault in the transformer, local overheating occurs at the fault site, causing the surrounding transformer oil to expand. The air dissolved in the oil is expelled, forming bubbles that rise to the surface. At the same time, the oil and other materials are ionized due to arcs and discharges, resulting in the generation of gas. When the fault is minor, the gas released rises slowly and enters the gas relay, causing the oil level to drop. The pivot generated by the open cup enables rotation in a counterclockwise direction around that axis, which in turn closes the reed contacts and sends a signal. 　　When there is a severe internal fault in the transformer, large amounts of gas are generated, causing the pressure inside the transformer to rise sharply. This results in a strong flow of oil in the direction of the oil conservator. As the oil flow impacts the baffle, the baffle overcomes the resistance of the spring and moves the magnet toward the reed contacts, thereby closing them and triggering the trip mechanism. 88. Why cannot the differential protection of a transformer replace gas protection? Answer: Gas protection can detect internal faults within the transformer tank, including core overheating and burning as well as a drop in oil level, but differential protection is unable to detect such faults. Another example is an inter-turn short circuit in a small number of turns of a transformer winding. Although the short-circuited turns generate very high short-circuit currents that cause severe overheating of those turns and result in strong oil flow in the direction of the oil conservator, the effect on the phase currents is not significant; as a result, the differential protection does not detect this condition. However, the gas protection can detect it sensitively. This is why differential protection cannot replace gas protection. 89. What is the transformer zero-sequence direction protection? What is its function? Answer: The transformer zero-sequence directional overcurrent protection is used in large-current grounding systems to protect the transformer against zero-sequence currents that occur when adjacent components (buses) of the transformer become grounded; its direction is toward the local bus. 　　Its function is to serve as a backup in the event of a busbar grounding fault. It features two levels of time delays: the switch is operated to disconnect the bus tie or sectionalizer at a shorter delay, while it is operated to disconnect the switch on the transformer’s own side at a longer delay. 90. Why is inter-turn protection required in large generators? Answer: In the stator windings of modern large generators, since there are stator bars of different turns but in the same phase located in the upper and lower layers of the same stator slot, inter-turn short-circuit faults can occur in these windings. Therefore, large generators are equipped with inter-turn protection. 91. How many common configurations are there for the inter-turn protection of large generators? Answer: The configurations for inter-turn protection in large generators usually include the following methods: 1. Differential protection: This is used when there are parallel branches in the stator windings and there are six terminals on the generator’s neutral point side. Transverse differential protection features simple wiring, reliable operation, and high sensitivity. 　　2. Inter-winding protection based on the zero-sequence voltage principle: A dedicated voltage transformer is used to measure the zero-sequence voltage generated as a result of the asymmetry in the voltages of the generator’s three phases. This protection type improves the sensitivity and reliability of protection thanks to the use of third-harmonic braking. 　　3. Negative sequence power direction inter-turn protection: This protection uses the direction of negative sequence power to determine whether there is an internal asymmetry in the generator or an asymmetrical fault in the system. It has high sensitivity; however, operational experience in recent years has shown that it tends to trigger erroneously in the case of faults outside the area it covers, which necessitates an increase in the operating delay and thus limits its use. 92. Why is single-phase grounding protection for the stator windings installed in generators? Answer: Generators are one of the most important devices in power systems, and their enclosures are safely grounded. A breakdown in the insulation between the generator’s stator windings and the core results in a single-phase ground fault in the stator, which is one of the most common types of generator failures. After a single-phase ground fault in the stator, the grounding current forms a path through the fault point, the three-phase to-ground capacitance, and the three-phase stator windings. When the ground current is high enough to cause an arc at the fault point, it can damage the insulation of the stator windings as well as the stator core; it can also lead to more serious faults such as inter-phase or turn-to-turn short circuits in the stator windings. Therefore, single-phase ground fault protection for the generator’s stator windings should be installed. 93. What are the characteristics and shortcomings of the stator single-phase ground protection using the fundamental zero-sequence voltage in generators? Answer: The features are: 1. Simple, reliable ； 2. A third harmonic filter is provided to reduce unbalanced voltage ； 3. Due to the small number of components in electrical contact with the generator, the grounding current is low, making it suitable for generator-transformer units. The drawback is that it cannot be used as 100% stator ground protection, as there is a dead zone with a range of 5% to 15%. 94. Why is rotor grounding protection installed in generators? Answer: A single-point ground fault in the generator’s excitation circuit is one of the common types of faults. Such a fault does not cause any harm to the generator. However, if a second ground fault occurs, that is, when there are two points of grounding on the rotor, a considerable fault current flows through these fault points, which can burn the rotor itself. Additionally, it increases the current in the magnetic excitation windings, and excessive heat may lead to damage as well ； Since some windings are short-circuited, the flux in the air gap becomes unbalanced, which causes vibration; it can even magnetize the shafting and the turbine. The consequences of a two-point grounding fault are severe, therefore rotor grounding protection must be installed. 95. Why is overvoltage protection installed on hydrogenerators? Answer: Due to the large inertia of the speed control system in hydro-turbine generators, which results in slow response, when the load is suddenly removed, the rotational speed can exceed the rated value; at such times, the terminal voltage can reach 1.8 to 2 times the rated value. To prevent damage to the insulation of the stator windings in hydrogenerators, overvoltage protection should be installed on them. 96. Why is reverse power protection required for large steam turbine generators? Answer: On a steam turbine generator set, when the boiler and turbine control system activates to close the main steam valve, or when the main steam valve closes accidentally due to a fault in the control circuit, the generator will switch to operating as a motor before its switch opens. At this time, reverse power is harmless to the generator itself; however, the steam remaining at the back of the turbine frictionates against the long blades, causing them to overheat. Therefore, reverse power operation cannot exceed 3 minutes, which is why reverse power protection must be installed. 97. Why is frequency anomaly protection installed in large steam turbine generators? Answer: The blades of a turbine all have a natural vibration frequency. If the operating frequency of the generator is below or above the rated value, and it approaches or equals the blade’s natural vibration frequency, resonance will occur, leading to material fatigue. When this fatigue reaches an unacceptable level, the blades may break, resulting in serious accidents. Material fatigue is an irreversible cumulative process; therefore, turbines specify a maximum allowable cumulative operating time at certain frequencies. Low-frequency operation often occurs under heavy loads, posing a more serious threat to the turbine. In addition, in cases of extremely low frequencies, it can also endanger the safety of the plant’s auxiliary power supply; therefore, generators should be equipped with protection against abnormal frequency operation. 98. What are the requirements for protection against abnormal frequency operation of large turbogenerators? Answer: The following requirements are applicable to the protection against abnormal operation of generator frequency: 1. A circuit for measuring frequency with high precision. 2. It features a frequency-segmented start-up circuit that automatically accumulates the abnormal operation time for each frequency segment, displays the cumulative time for each segment, and allows the start-up frequency to be adjusted. 3. The allowable operating time for each segment can be set; when the cumulative time for a segment exceeds this allowable value, a signal is sent or a trip occurs via the outlet. 4. It can monitor the current frequency. 99. Why are negative-sequence inverse-time overcurrent protections installed in large turbogenerators? Answer: When an asymmetric short circuit occurs in the power system, negative-sequence currents are generated in the stator windings of the generator. These negative-sequence currents induce harmonic currents in the rotor, leading to localized scorching of the rotor. Large steam turbines, due to their smaller size, have poor heat tolerance; their allowable overheating time constant, given by A(I²*t), is low. To protect the generator rotor, it is necessary to use a reverse-time negative-sequence overcurrent protection system that is compatible with the negative-sequence current levels permitted by the generator. 100. Why should modern ** type generator-transformer units be equipped with protection against operation under unbalanced phase conditions? Answer: The circuit breakers on the high-voltage side of large generator-transformer units at 220KV and above are mostly phase-separated operation circuit breakers. Misoperation or mechanical issues can often prevent all three phases from being closed or tripped simultaneously, or one phase may suddenly trip during normal operation. Under such abnormal operating conditions, negative-sequence currents flow through the generator in the generator-transformer unit. If protection devices that respond to negative-sequence currents are activated (or, in the case of tie transformers, backup protection devices that respond to short-circuit faults), the longer activation time may cause protection devices on the opposite side of the adjacent lines to also activate, thereby expanding the scope of the fault and even leading to a system collapse. Therefore, for large generator-transformer units, when the circuit breakers on the 220KV and higher voltage sides operate in a phase-separated manner, it is required to install protection against operation under non-full-phase conditions. Q&A on Power Dispatching Technology -- Short Answer Questions Series 5 101. Why is it necessary to install protection against unexpected voltage increases in generators? Answer: During the barring process of the generator, accidental closing of the outlet circuit breaker results in a sudden application of voltage, causing the generator to start asynchronously, which can damage the unit. Therefore, appropriate protection is needed to quickly cut off the power supply when such events occur. Generally, dedicated protection against accidental overvoltage is provided, with a combination of low-frequency components that can return after a delay and overcurrent components serving as the criteria for detection. This protection is disabled during normal operation and activated only after the unit is shut down. Of course, during abnormal startup, reverse power protection, loss of flux protection, and impedance protection may also activate, but their response time is relatively long; it is better to implement dedicated protection against incorrect switching. 102. Why is arc flash protection for generator circuit breaker contacts necessary? Answer: In large generator-transformer units connected to voltage systems of 220 KV or higher, during the process of synchronous paralleling, the voltage applied across the connection point changes continuously as the phase angle difference δ between the potential of the generator to be connected and the potential of the equivalent generator in the system varies. This voltage reaches its maximum value when δ = 180°, at which point it equals the sum of the potentials of the two generators. When the two potentials are equal, twice the phase voltage acts on the break, which sometimes leads to flashover accidents at the break. 　　Breakdown arcing not only causes damage to the circuit breaker itself but may also lead to an expansion of the accident, disrupting the stable operation of the system. Generally, it is single-phase or two-phase flashover, which generates negative-sequence current and threatens the safety of the generator. 　　To eliminate flashover faults at the fracture point as quickly as possible, fracture-point flashover protection can be installed on large-scale units. The condition for the fracture flashover protection to activate is the presence of negative-sequence current when the circuit breaker is in the tripped position. Breakdown flashover protection first activates to de-excite the magnet; in the event of failure, it activates the circuit breaker failure protection. 103. Why is it necessary to install protection for starting and stopping generators? Answer: For generators for which excitation voltage may be applied during startup or shutdown at low speeds, if the existing protection does not function properly under such conditions, it is necessary to install generator startup and shutdown protection, which should be able to operate correctly at low frequencies. For example, as protection for the start-up and shutdown processes of the generator-transformer unit, one set of inter-phase short-circuit protection and one set of stator ground protection can be installed. The setting values should be reduced so that these protections function only as auxiliary protections under low-frequency operating conditions; they should be disabled during normal operation at the rated frequency to avoid false trips. To this end, the outlet of the auxiliary protection is controlled by the auxiliary contacts of the circuit breaker or the contacts of the low-frequency relay. 104. Why is a voltage blocking element used in busbar current differential protection? How to achieve it? Answer: Voltage blocking elements are used to prevent the differential relay from operating erroneously, or to avoid false operations of the busbar protection caused by accidental activation of the output intermediate relay. The voltage locking element is implemented using low-voltage relays and zero-sequence voltage relays connected to the secondary sides of the voltage transformers on each busbar. The three low-voltage relays respond to various phase-to-phase short-circuit faults, while the zero-sequence overvoltage relay responds to various ground faults. 105. Why is bus charging protection provided? Answer: To more reliably remove faults on the charged busbar, phase current or zero-sequence current protection is installed on the busbar tie switch or busbar sectionalizing switch as a dedicated protection for busbar charging. 　　The bus charging protection has a simple wiring scheme, and high sensitivity can be ensured through appropriate setting values. Where conditions permit, this protection can be used as a dedicated bus to serve as temporary protection for charging new circuits. 　　The bus charging protection is activated only when the bus is being charged, and it should be disabled promptly once the charging is complete. 106. What is switch failure protection? Answer: When a system fails and the protection device of the faulty component activates but its switch fails to operate and refuse to trip, the protection mechanism of that faulty component causes the switches located on the adjacent busbars to trip. Under suitable conditions, channels can also be utilized to cause the relevant remote switches to trip simultaneously; such protection or wiring is known as switch failure protection. Switch failure protection is an effective measure within \"near backup\" to prevent the switch from failing to operate. 107. What are the configuration principles for circuit breaker failure protection? Answer: In important sections of 220–500 KV power grids, as well as some 110 KV power grids, circuit breaker failure protection is installed under the following circumstances: 1. When the circuit breaker fails to operate, the backup protections of adjacent equipment and lines do not have a sensitivity level high enough to act reliably in order to eliminate the fault. 　　2. When the circuit breaker fails to operate, although the backup protections of adjacent equipment and lines can be activated to trip, the time required to eliminate the fault is too long, leading to serious consequences. 　　3. When the distance between the circuit breaker and the current transformer is large, and a short-circuit fault occurring between them cannot be cleared by the main protection of that electrical equipment but must be cleared by other backup protections, this will expand the scope of the power outage and lead to serious consequences. 108. What are the principles for setting the failure protection time value of circuit breakers? Answer: The basic requirement for the setting of the protection time for breaker failure is that the delay required for this protection mechanism to act must ensure that the protective devices of the faulty circuit or equipment can operate and trip first. This delay should be equal to the sum of the time it takes for the breaker to trip and the time it takes for the protection system to return to normal, plus an additional margin of time, so that the busbar breaker or sectionalizer breaker can be disconnected as quickly as possible; thereafter, after a certain delay, the breakers of all circuits connected to the same busbar that are still powered can be disconnected. 109. What are the requirements for failure protection in circuit breakers with a 3/2 wiring configuration or a polygonal wiring configuration? Answer: 1) The circuit breaker failure protection is set according to the circuit breaker settings. 　　2) The identification element uses a phase current element that reflects the position status of the circuit breaker; it is necessary to check the current of each circuit breaker separately in order to determine which one is not functioning properly. 　　3) When the intermediate circuit breaker in a string connected using a 3/2 circuit breaker configuration fails to operate, or when one of the adjacent circuit breakers in a polygonal wiring configuration fails to operate, a remote tripping device should be used to cause the circuit breaker at the other end of the line to trip and to lock out its reclosing function. 110. What protections are typically installed in 110 kV and 500 kV circuit breaker housings? Answer: The 500KV circuit breaker itself is typically equipped with circuit breaker failure protection and three-phase imbalance protection. The failure protection for 500KV circuit breakers is divided into phase-by-phase and three-phase types. The phase-separated type uses phase-by-phase starting and tripping methods; phase-separated failure protection is installed only on the circuit breakers in 3/2 circuit breaker wiring ； In the three-phase system, there is no distinction between starting and tripping operations; in all cases, the circuit breaker trips in all three phases. The three-phase failure protection is installed only on the circuit breaker of the main transformer. 　　The three-phase inconsistency protection operates by triggering a delayed trip after connecting the normally open and normally closed auxiliary contacts of the same phase in series; during single-phase reclosing, the incomplete-phase protection is locked out by the reclosing process. 111. What is the function of the short-circuit lead protection for a 3/2 circuit breaker? Answer: The main wiring uses a series of circuit breakers arranged in a 3/2 breaker configuration. When one of the circuits in this series is taken out of service, the isolating switch on that circuit side will be disconnected; at that point, the voltage transformer used for protection is also deactivated, and the main protection for that circuit is disabled. As a result, in the event of a fault within the range of the short-circuit leads, there will be no rapid protection to eliminate the fault. To this end, short-circuit lead protection is required, namely short-circuit lead longitudinal differential protection. In the aforementioned fault conditions, this protection can act quickly to isolate the fault. When the line is in operation and the isolating switch on the line side is closed, this short-circuit lead protection will operate indiscriminately in the event of a fault on the line side; therefore, it is necessary to deactivate this short-circuit lead protection. It can generally be controlled by the auxiliary contacts of the circuit-side isolator, to deactivate the short-circuit lead protection when closing. 112. What is an automatic low-frequency load shedding device? What is its function? Answer: To improve the quality of power supply and ensure the reliability of power supply to critical users, when a deficiency in active power in the system causes the frequency to drop, this device automatically disconnects some of the users, depending on the extent of the frequency drop, in order to prevent further drops and enable the frequency to return to normal levels quickly. Such a device is called an automatic low-frequency load shedding device. It can not only ensure power supply to important users but also prevent system collapse accidents caused by frequency drops. 113. What are the setting principles for automatic low-frequency load shedding devices? Answer: 1. When the automatic low-frequency load shedding device is activated, it is necessary to ensure that the frequency of the entire power grid as well as that of the local network after isolation is restored to above 49.50 Hz, with it not exceeding 51 Hz. 　　2. The automatic low-frequency load shedding device should activate under various operating conditions, without causing overload of other equipment in the system or exceeding the stability limits of the interconnection lines. 　　3. When the automatic low-frequency load shedding device activates, the low-frequency protection of large units should not be triggered as a result of a frequency drop caused by a power deficit in the system. 　　4. The automatic low-frequency load shedding sequence should prioritize the shutdown of less important loads, with more critical users being shut down last. 　　5. The load disconnected by the automatic low-frequency load shedding device should not be reconnected by automatic reclosing, and it should be used in coordination with other safety automatic devices. 　　6. The amount of load to be disconnected by the automatic low-frequency load shedding device across the entire network should be calculated based on the annual forecast of the maximum average load, with adjustments made for possible power supply failures. 114. Briefly describe the principle of operation of the electrical braking system in generators? What are the principles for setting the timing of activating the braking resistor? Answer: When the generator’s speed increases due to excess power, braking resistors can be quickly connected at the generator’s outlet or on its high-voltage bus to absorb the excess power generated by the generator. Braking resistors can be water-cooled resistors or resistors made of alloy materials. The closing time of the switch that connects the braking resistor should be as short as possible to enhance the braking effect. The principle for setting the timing at which the braking resistor is activated should be to avoid excessive braking of the system as well as overloading of the braking resistor; it should be disconnected immediately when the generator’s dP/dt value reaches zero. 115. How many ways are there to quickly close the turbine valve? What is its function? Answer: The turbine can achieve two types of power reduction through quick-shut valves: temporary power reduction and continuous power reduction. 　　1. Brief power reduction is used during the initial transient phase of a system fault, in order to reduce the excess kinetic energy of the generator rotor caused by disturbances and thus prevent a loss of transient stability in the system. 　　2. Continuous power reduction is used to prevent loss of static stability in the system, eliminate out-of-step conditions, limit equipment overload, and restrict frequency increases. 116. What are low-frequency self-starting and phase-modulated power generation? Answer: Low-frequency self-starting refers to the automatic and rapid startup of hydrogenerators and gas turbines when they detect that the system frequency has dropped to a specified value, so that they can connect to the power grid to generate electricity. Phase-regulation mode to power generation mode conversion refers to the process in which, when the grid frequency drops to a specified value, automatic systems switch the generator from phase-regulation mode to power generation mode, or in the case of pump-storage units, they stop pumping water and quickly switch to power generation mode. 117. Explain the function of the low-frequency and low-voltage disconnection devices in power systems Answer: In power systems, the removal of a large power source can lead to a severe imbalance in power generation and supply, resulting in a drop in frequency or voltage. When automatic low-frequency load shedding devices (or measures) are not sufficient to meet the requirements for safe operation, it is necessary to install low-frequency and low-voltage disconnection devices at certain locations. This allows the isolated local power grid to operate safely and stably, ensuring a reliable power supply to important users. 118. What is an oscillation disconnection device? Answer: When the power system is subjected to significant disturbances that cause asynchronous oscillations, in order to prevent the stability of the entire system from being compromised, the system is disconnected at a predetermined location after a certain period of time or after a specified number of oscillation cycles. The automatic device that carries out this disconnection is known as an oscillation disconnection device. 119. What is a regional stability control system? Answer: For the stable control of a complex power grid, it is necessary to rely on the coordinated operation of the stable control devices in several stations within the regional grid to achieve this goal. That is, the stable control system of each plant or station relies not only on locally measured signals but also on signals transmitted from other plants or stations; only by making a comprehensive assessment can proper stable control be achieved. We collectively refer to this combination of decentralized stability control devices as a regional stability control system. 120. What are the main functions of the power system communication network? Answer: The power system communication network serves aspects such as the operation, management, and capital construction of power grids. Its main functions should meet the requirements of various services such as dispatching calls, administrative calls, power grid automation, relay protection, safety automatic devices, computer networking, faxing, and image transmission.