Phase advance operation
Reducing the generator excitation current decreases the generator potential, causing the power factor angle to become leading. The generator load current generates an auxiliary armature reaction, and the generator delivers active power to the system but absorbs reactive power. This operating state is called leading-phase operation.
During normal operation, a generator provides both active and reactive power to the system. The stator current lags behind the terminal voltage by an angle; this state is called lagging operation. When the excitation current is gradually reduced, causing the generator to absorb reactive power from the system instead of providing it, the stator current changes from lagging to leading the generator terminal voltage by an angle; this state is called leading operation. In leading operation, the excitation current is significantly reduced compared to lagging operation, and the generator electromotive force (Eq) also decreases accordingly. From the P-power angle relationship, with constant active power, the power angle will inevitably increase, and the ratio of total step power will decrease accordingly, leading to a decline in the generator's static stability. Its stability limit is related to the generator's short-circuit ratio, external reactance, the performance of the automatic excitation regulator, and whether it is in operation.
During leading-phase operation, the leakage flux at the stator terminals of the generator increases compared to lagging-phase operation. This is especially true for large generators with high line loads; under normal operation, the leakage flux at the terminals is already relatively large, causing the temperature of the core contact points to rise. During leading-phase operation, the increased leakage flux exacerbates this temperature rise. The generator terminal voltage decreases during leading-phase operation, resulting in a corresponding decrease in the plant auxiliary power voltage. If this decrease exceeds 10%, it will affect the operation of the plant auxiliary power supply.
Therefore, the depth of leading-phase operation of a synchronous generator must be determined through testing. This means determining how much reactive power needs to be absorbed to maintain the system's static and transient stability, ensure that the temperature rise of each component does not exceed limits, and meet voltage requirements under a given active power supply.
What factors limit the operation of a generator in the leading phase?
When the inductive reactive power supplied by the system exceeds the demand, it will cause the system voltage to rise, requiring the generator to generate less reactive power or even absorb reactive power. At this time, the generator can switch from lagging phase operation to leading phase operation.
What is the leading phase operation of a generator?
What is the leading phase operation of a generator? Under normal circumstances, due to a large amount of inductive load, the generator generally generates power when it is in leading phase operation. When a generator is in leading phase operation, the output voltage is low, and the plant's auxiliary voltage is also low. What are the leading phase operation, underexcitation, and loss of excitation of a generator? What is the relationship between these three? Since power grids below 500KV generally require a large amount of inductive reactive power, but when the grid voltage is very high and the transmission distance is very long, the transmission line itself... What is the power factor of a generator? Generators generate electricity through electromagnetic conversion, and a portion of the reactive power is used...
Inductive reactive power must also be generated to meet the requirements. At this time, the generator increases the excitation voltage and current, and the generator power factor lags. However, in high-voltage and ultra-high-voltage transmission lines, because the capacitive effect of the line is greater than the inductive effect of the load, the generator is required to generate capacitive reactive power to meet the requirements. At this time, the generator will reduce the excitation voltage and current, and the generator power factor will lead, also known as leading-phase operation.
When the generator is operating in leading-edge mode, the output voltage is low, and the plant's auxiliary voltage is also low. Not all generators can achieve this; it needs to be specified when ordering.
What are leading phase operation, underexcitation, and loss of excitation in a generator? What is the relationship between these three?
Since power grids below 500kV generally require a large amount of inductive reactive power, generators operating on grids below this voltage are expected to output inductive reactive power. To do this, the excitation current needs to be increased. At this voltage, the generator's power factor is positive.
However, when the grid voltage is high and the transmission distance is long, the capacitance effect generated by the transmission line itself can compensate for the aforementioned inductive reactive power, with a surplus. Therefore, the generator needs to output capacitive reactive power for compensation. This requires reducing the generator's excitation current to output capacitive reactive power. Due to the reduced excitation current, the generator is in an under-excitation state. At this time, the generator power factor is negative, and the generator is operating in a leading-phase state. If the generator excitation system fails and stops working, the generator will be in a state without excitation current. In this case, the generator is operating without excitation and needs to be shut down immediately.
What does the power factor of a generator mean?
Generators generate electricity through electromagnetic conversion. A portion of the reactive power is used to generate a magnetic field through electromagnetic conversion, while the remaining active power is transmitted to users. The proportion of the total power supplied to users is called the power factor.
The cosine of the phase difference (Φ) between generator voltage and current is called the power factor, denoted by the symbol cosΦ. Numerically, the power factor is the ratio of active power to apparent power, i.e., cosΦ = P/S
The stator and rotor of a generator are two completely independent and non-interfering parts, except for being driven by a prime mover.
The stator of a generator is an active power source that generates induced electromotive force and current, which, driven by the prime mover, outputs alternating current.
The rotor of the generator is the reactive power source, and the windings introduce direct current from the outside to establish a magnetic field. Under the drive of the prime mover, it transmits reactive power to the outside.
What should be considered when adjusting the power factor of a generator?
Try to adjust it as close to 1 as possible.
First, the power factor must meet the power supply department's requirements for grid connection. Second, the allowable rotor current must not be exceeded. Third, the stator current must not exceed the limit. Fourth, if you want to reduce reactive power generation, reduce the excitation current while ensuring the generator does not lead or oscillate. For generators operating as stand-alone units, there is no issue of adjusting the power factor; the prerequisite is to maintain a suitable and stable voltage for the generator.
The power factor of a typical generator is between 0.8 (lagging) and 1. You can adjust it within this range; generators generally don't operate in a leading-edge state. Additionally, you should set the power factor according to your dispatching requirements.
What do the active power, reactive power, and power factor of a generator mean? Please explain in simple terms.
Power is divided into three types: active power P, reactive power Q, and apparent power S.
The cosine of the phase difference (Φ) between voltage and current is called the power factor, denoted by the symbol cosΦ. Numerically, the power factor is the ratio of active power to apparent power, i.e., cosΦ = P/S. The three types of power and the power factor cosΦ form a right-angled power triangle relationship: the two legs are active power and reactive power, and the hypotenuse is apparent power.
Active power squared + reactive power squared = apparent power squared. In a three-phase load, these three types of power always exist simultaneously, and the electricity generated by the engine must include all three types of power:
Apparent power S = 1.732UI
Active power P = 1.732UIcosΦ (power generated by doing work and heating)
Reactive power Q = 1.732UIsinΦ (power to establish a magnetic field and transfer energy) Power factor cosΦ = P/S (active power/apparent power) sinΦ = Q/S (reactive power/apparent power)
What is the difference between transformer zero-sequence overcurrent protection and single-phase grounding protection?
Additional information:
However, a single-phase ground fault will result in zero-sequence current, and both protection measures will be activated simultaneously on the same transformer.
When a short circuit occurs between turns inside a transformer, or when the three-phase load imbalance exceeds a certain allowable range, zero-sequence current will appear. At this time, there is no grounding anywhere in the transformer. This is the difference between transformer zero-sequence overcurrent protection and single-phase grounding protection.
What is the main protection circuit of a transformer?
This mainly refers to the two main protections of the transformer! One is electrical quantity protection, which is the differential protection used for short-circuit faults in the transformer winding cable leads. The other is gas protection, divided into light gas and heavy gas protection. This is mainly used to monitor the large amounts of gas produced by the decomposition of transformer oil in internal transformer faults. The main protection circuit is simply the secondary wiring of these two protections.
What are the working principles of differential protection for power transformers and differential protection for transmission lines?
First, understand the principle of differential protection. Differential protection works based on Kirchhoff's current theorem, which treats the protected electrical equipment as a contact. Under normal conditions, the current flowing into the protected equipment is equal to the current flowing out, and the differential current is zero. When a fault occurs, the current flowing into the protected equipment is not equal to the current flowing out, and the differential current is greater than zero. When the differential current exceeds the setting value of the differential protection device, the protection trips, disconnecting the circuit breakers on both sides of the protected equipment and cutting off the power supply to the faulty equipment. Its protection range covers equipment between the current transformers at both ends of the input (which can be lines, generators, motors, transformers, etc.). For differential protection of power transformers, the current is taken from the transformer current transformers on the high and low voltage sides of the transformer.
The differential protection of a transmission line draws its current from the current transformers used in the substations at both ends of the line.
What is the basic principle of primary frequency regulation in a power system?
Primary frequency regulation refers to the function of automatically adjusting the power output of generating units participating in primary frequency regulation when the grid frequency exceeds the prescribed normal range. This adjustment causes the power output of these units to increase or decrease accordingly, achieving a new equilibrium and limiting grid frequency fluctuations within a certain range. Primary frequency regulation is a crucial means of maintaining grid stability.
Load fluctuations cause frequency changes, which can be controlled by primary and secondary frequency regulation to keep the system frequency within a specified range. For frequency deviations caused by small load fluctuations and short periods, the generator speed governor is generally used for adjustment; this is called primary frequency regulation. For frequency deviations caused by large load fluctuations and long periods, the speed governor alone cannot limit them to the specified range, so a frequency regulator is used for frequency regulation; this is called secondary frequency regulation.
To ensure the frequency stability of the power grid, frequency regulation is generally performed on the power sector, namely primary and secondary frequency regulation. Secondary frequency regulation refers to the adjustment made by the frequency regulator of the generator set for frequency deviations with large fluctuation ranges (0.5~1.5%) and long fluctuation periods (10s~30min). This work is usually carried out by the frequency regulation plant.
The power grid frequency is a random variable that changes dynamically over time and contains different frequency components. The primary frequency regulation of the power grid is a random process. This is because the system load can be considered as composed of the following three types of variable loads with different changing patterns [1]: ① random load components with small amplitude and short period of change (generally within 10s); ② load components with large amplitude and long period of change (generally 10s to 3min), such as electric furnaces and rolling mills; ③ slow-changing continuous variable loads, the main reasons for which load changes are the factory's work and rest schedule and people's daily routines. The primary frequency regulation regulates the random component superimposed on the long-period variable component, which determines the random nature of the primary frequency regulation of the power grid.
When the system size is small, research on power system peak shaving and frequency regulation is mainly conducted from a static perspective. For example, before the mid-1980s, the focus of research was mainly on the static economic allocation of power plant loads, safe and economical static dispatching, and static optimal power flow. These studies did not pay enough attention to the dynamic information of the system, especially the dynamic constraints in many time directions. This was particularly relevant when the system size and load development were relatively limited.
In the early stages, this was acceptable. However, with the rapid development of system scale and load, many new problems and characteristics have emerged in power grid peak shaving and frequency regulation. At this point, it is difficult to achieve the desired effect of multi-party coordination by solving the problem from a static perspective.
The concept of primary frequency regulation characteristics based on static characteristics simplifies the load distribution pattern of various generating units in the power grid to an inverse relationship with the inequality rate. However, the reality is not so simple. When examining the primary frequency regulation response of steam turbine generator units to frequency variations, it is necessary to consider not only the amplitude of the frequency variation but also its rate. This involves the differences in the adaptability of different units to load disturbances of different frequencies, such as reheat units versus non-reheat units. This aspect cannot be described using the static characteristic concept, so the problem must be reconsidered from a dynamic perspective.
Furthermore, the response capabilities of turbine regulation systems to different frequency components of frequency variations vary. For example, even if the static characteristics of a reheat unit with a dynamic over-opening capability of a high-pressure regulating valve are completely identical, their power output responses to frequency variations may differ. Therefore, this issue also needs to be reconsidered from a dynamic perspective.
What is the difference between primary frequency regulation and secondary frequency regulation in a power system?
Primary frequency regulation involves adjusting the power grid frequency, with certain amplitude limits and dead zones. Secondary frequency regulation is based on receiving commands from the central dispatch center or manual instructions.
Primary frequency modulation is achieved using a speed controller, and its narrow frequency range constitutes fine-tuning. Secondary frequency modulation is achieved using a frequency modulator, and its wide frequency range constitutes coarse-tuning. Primary frequency modulation:
When generating units are connected to the grid, the grid frequency changes due to fluctuations in external load. At this time, the regulating systems of each unit participate in the regulation, changing the load carried by each unit to balance it with the external load. At the same time, efforts are made to minimize the changes in grid frequency. This process is called primary frequency regulation.
Secondary frequency modulation:
Primary frequency regulation is differential regulation; it cannot maintain a constant grid frequency, but can only mitigate the degree of change in the grid frequency. Therefore, it is also necessary to use synchronizers to increase or decrease the load of certain generating units to restore the grid frequency. This process is called secondary frequency regulation.
Only after secondary frequency regulation can the power grid frequency be precisely maintained at a constant value. There are currently two methods for secondary frequency regulation:
1. The central dispatching authority orders each plant to adjust its load. 2. The generating units adopt AGC (Automatic Generation Control) to achieve automatic load scheduling. Simply put, primary frequency regulation involves the turbine speed control system automatically adjusting the unit load to restore the grid frequency based on changes in the grid frequency. Secondary frequency regulation involves manually adjusting the unit load based on the grid frequency.
The main differences are:
Frequency modulation is performed by a speed controller, which cannot achieve error-free frequency modulation.
Secondary frequency modulation is performed by a frequency modulator, enabling error-free frequency modulation.
