Mobile gas turbine generator set rapid grid-connected transient stability control system

Abstract

The present application belongs to the field of distributed power generation grid-connected control technology, and discloses a mobile gas turbine generator set rapid grid-connected transient stability control system, which comprises: calculating the expected impact current at the grid-connected moment and the self-induced phase offset amount caused thereby; acquiring the grid impedance parameters in real time by injecting a non-characteristic frequency detection signal, and calculating the coupling interaction factor under the multi-machine parallel scene; performing feedforward compensation reconstruction based on the self-induced phase offset amount, and implementing adaptive damping remodeling according to the coupling interaction factor; extracting the subsynchronous frequency band component in the power oscillation signal at the grid-connected point, and generating a targeted damping instruction; superimposing the damping instruction to the excitation and inverter control loop; continuously monitoring the power oscillation attenuation characteristics after grid connection and dynamically adjusting the control parameters. The present application effectively suppresses shaft torsional vibration, cuts off the interactive coupling path between multiple machines, and realizes stable and rapid grid connection of the mobile gas turbine under the condition of extremely weak power grid.

Description

Technical Field

[0001] This invention relates to the field of distributed generation grid connection control technology, and more specifically, to a transient stability control system for rapid grid connection of mobile gas turbine generator sets. Background Technology

[0002] In existing technologies, the grid connection control of mobile gas turbine generator sets in weak grid environments faces a complex technical problem—the self-excited oscillation instability of the phase-locked loop (PLL) system. In practical applications, these mobile units are often urgently deployed to remote areas at the end of the grid, disaster reconstruction sites, or temporary industrial parks—environments with weak grid infrastructure. These locations have extremely low short-circuit capacity, and the grid impedance exhibits strong inductive characteristics. When the unit attempts to connect to the grid, its fast grid connection controller heavily relies on the PLL to track the phase information of the grid voltage in real time. However, under weak grid conditions, the large inrush current generated at the moment of grid connection directly causes a sudden drop in voltage amplitude and a sudden phase shift at the point of common coupling. The core problem is that the PLL system mistakenly identifies this phase disturbance caused by its own grid connection behavior as a real change in the grid phase, thereby driving the excitation system and inverter control system to make incorrect compensation actions, forming a fatal positive feedback loop—the current surge causes a phase jump, and the PLL's tracking of the phase jump exacerbates the current disturbance, thus creating a continuous "tug-of-war" effect. More seriously, the frequency of these uncontrolled oscillations often falls in the low to medium frequency range, resonating and coupling with the inherent torsional vibration frequency of the gas turbine shaft system. This not only causes severe mechanical vibration and shaft fatigue damage to the unit, but in extreme cases, it can even lead to catastrophic failures such as transmission shaft breakage. When multiple mobile gas turbines attempt to connect to the same vulnerable power distribution network simultaneously, the phase-locked loops of each unit generate a strong interactive coupling effect through the common grid impedance. The grid connection disturbance of one unit will instantly propagate to other units, triggering a chain reaction of instability. Ultimately, this will cause the entire temporary power grid system to experience a series of trips at the moment of grid connection, seriously affecting the execution effect of emergency power supply tasks and the reliability of the power supply system.

[0003] In view of this, the present invention proposes a mobile gas turbine generator set rapid grid connection transient stability control system to solve the above problems. Summary of the Invention

[0004] To overcome the aforementioned deficiencies of the prior art and to achieve the above objectives, the present invention provides the following technical solution: a mobile gas turbine generator set rapid grid connection transient stability control system, comprising: The inrush current prediction module is used to obtain the current electrical parameters of the grid connection point and the current operating parameters of the gas turbine generator set after receiving the grid connection command. Based on the current electrical parameters and the current operating parameters, it calculates the expected inrush current at the moment of grid connection and calculates the self-induced phase offset caused by the expected inrush current based on the expected inrush current and the estimated grid impedance. The grid impedance measurement unit is used to inject a non-characteristic frequency detection signal into the grid connection point during the grid connection pre-synchronization stage, extract grid impedance parameters based on the voltage response of the grid connection point to the detection signal, and calculate the coupling interaction factor in the multi-machine parallel scenario based on the grid impedance parameters. The phase-locked loop (PLL) reconfiguration controller is used to perform feedforward compensation reconfiguration of the input phase of the PLL based on the self-achieved phase offset, and to perform adaptive damping reshaping of the control parameters of the PLL based on the coupling interaction factor, thereby generating a reconfigured PLL reference signal. The subsynchronous oscillation suppression unit is used to collect the actual power oscillation signal at the grid connection point at the moment of grid connection execution, extract the target oscillation component in the preset subsynchronous frequency band from the actual power oscillation signal, and generate a subsynchronous damping command based on the target oscillation component and the shaft torsional vibration characteristics of the gas turbine generator set. The grid connection execution controller is used to superimpose the subsynchronous damping command onto the excitation control circuit and inverter control circuit of the gas turbine generator set, and perform fast grid connection operation under the phase constraint of the reconstructed phase-locked loop reference signal; The transient monitoring and adjustment unit is used to continuously monitor the power oscillation attenuation characteristics of the grid connection point during the transient transition period after grid connection, and dynamically adjust the control parameters of the phase-locked loop and the damping strength of the subsynchronous damping command based on the power oscillation attenuation characteristics until the gas turbine generator set enters steady-state operation.

[0005] The technical effects and advantages of the mobile gas turbine generator set rapid grid connection transient stability control system of this invention are as follows: This invention suppresses the propagation and amplification of low- and medium-frequency oscillations during grid connection to the torsional vibration frequency band of the gas turbine shaft system, effectively avoiding fatigue damage and potential fracture risks caused by resonant coupling to the mechanical shaft system, and significantly extending the service life of key transmission components. In multi-unit parallel operation scenarios, the invention successfully cuts off the interactive coupling path formed by the grid impedance between the phase-locked loops of each unit, eliminating the phenomenon that grid connection disturbances of one unit can cause cascading instability in other units, and realizing coordinated and stable operation of multiple mobile gas turbines in the same fragile power grid. The adaptive capability of this invention can sense changes in grid strength in real time and dynamically adjust the control strategy, maintaining high robustness and anti-interference capability when facing large fluctuations in grid parameters, sudden load changes, or fault disturbances. The invention also realizes intelligent management and control of the grid connection transient process, ensuring that the system can smoothly transition to steady-state operation without long-term oscillations or instability, improving the success rate of emergency power supply tasks and the reliability of power supply quality. Attached Figure Description

[0006] Figure 1 This is a schematic diagram of the mobile gas turbine generator set rapid grid connection transient stability control system of the present invention. Detailed Implementation

[0007] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0008] This application provides a mobile gas turbine generator set rapid grid connection transient stability control system. The execution entities of the system include, but are not limited to, distributed energy management platforms, mobile power station control centers, power grid dispatching systems, and intelligent grid connection devices, which can be regarded as general computing nodes of this application. The control system includes, but is not limited to, at least one of the following: gas turbine generator set controller, grid connection switch control device, and power quality monitoring equipment.

[0009] Please see Figure 1 In this embodiment of the invention, the mobile gas turbine generator set rapid grid connection transient stability control system includes: The inrush current prediction module, upon receiving a grid connection command, acquires the current electrical parameters of the grid connection point and the current operating parameters of the gas turbine generator set. Based on these parameters, it calculates the expected inrush current at the moment of grid connection and, based on the expected inrush current and the estimated grid impedance, calculates the self-induced phase shift caused by the expected inrush current. The current electrical parameters of the grid connection point include key information such as voltage amplitude, voltage phase, frequency, and short-circuit capacity. The current operating parameters of the gas turbine generator set include state variables such as terminal voltage, power generation, speed, and excitation current, acquired in real-time through a high-speed data acquisition interface. The calculation of the expected inrush current considers the voltage difference, phase difference, and system equivalent impedance at the moment of grid connection, reflecting the electromagnetic transient characteristics at the moment of connection. The self-induced phase shift describes the phase jump caused by the voltage drop across the grid impedance due to the inrush current itself. This jump further affects the stability of the phase-locked loop, forming a positive feedback effect. This module provides feedforward signals for subsequent compensation control through accurate prediction, forming the foundation for achieving low-impact grid connection.

[0010] The grid impedance measurement unit is used during the grid pre-synchronization phase to inject a non-characteristic frequency probe signal into the grid connection point. Based on the voltage response of the grid connection point to the probe signal, grid impedance parameters are extracted, and the coupling interaction factor in multi-unit parallel scenarios is calculated based on these parameters. Grid impedance parameters include resistive components, inductive components, and impedance angle. These parameters dynamically change with grid operating conditions and directly affect grid stability. The non-characteristic frequency probe signal is typically a sinusoidal or pseudo-random signal with a non-fundamental frequency to avoid interference with the system's inherent frequency. The amplitude-frequency and phase-frequency characteristics of the voltage and current responses are extracted through frequency domain analysis, and the broadband impedance parameters are calculated inversely. In multi-unit parallel scenarios, the phase-locked loops (PLLs) of different units are electrically coupled through the common grid impedance, leading to interactive effects of oscillation modes. The coupling interaction factor is obtained through characteristic analysis of the impedance network matrix, quantifying the interaction strength between units and providing a basis for the coordinated optimization of PLL parameters.

[0011] The phase-locked loop (PLL) reconfiguration controller is used to perform feedforward compensation reconfiguration of the PLL's input phase based on self-induced phase offset, and adaptive damping reshaping of the PLL's control parameters based on coupling interaction factors, generating a reconfigured PLL reference signal. Traditional PLLs are prone to loss of synchronization or continuous oscillation due to phase jumps in weak grid conditions. Feedforward compensation avoids PLL misjudgments by preemptively offsetting anticipated phase offsets. Adaptive damping reshaping dynamically adjusts the proportional and integral gains according to grid strength and multi-machine coupling, suppressing oscillation trends while ensuring tracking speed. The reconfigured PLL reference signal contains compensated phase angles and frequencies, serving as a reference for subsequent power control and coordinate transformation, ensuring phase synchronization accuracy and dynamic stability at grid connection.

[0012] The subsynchronous oscillation suppression unit is used to acquire the actual power oscillation signal at the grid connection point at the instant of grid connection execution. It extracts the target oscillation component within a preset subsynchronous frequency band from the actual power oscillation signal and generates a subsynchronous damping command based on the target oscillation component and the torsional vibration characteristics of the gas turbine generator set's shaft system. The gas turbine generator set's shaft system has an inherent torsional vibration frequency, typically in the range of 10-50Hz, which overlaps with the subsynchronous frequency range of the power system. The electromagnetic torque impact at the moment of grid connection easily excites shaft torsional vibration. If the oscillation frequency is close to the natural frequency, it may cause resonance, leading to shaft fatigue damage or even fracture. Subsynchronous oscillation suppression accurately extracts the oscillation component of the target frequency band by real-time monitoring of the power oscillation waveform, and then calculates the required electrical damping torque based on the shaft system's mechanical characteristics. The phase of the damping command must be out of phase with the oscillation component, and the amplitude is determined based on the oscillation intensity and insufficient mechanical damping, ensuring that the oscillation energy is effectively dissipated rather than amplified.

[0013] The grid-connection execution controller is used to superimpose subsynchronous damping commands onto the excitation control loop and inverter control loop of the gas turbine generator set, performing rapid grid connection operations under the phase constraints of the reconstructed phase-locked loop reference signal. The superposition of damping commands employs a decoupling control strategy, injecting the active damping component into the inner current loop and the reactive damping component into the outer voltage loop to avoid mutual interference between the two. The excitation control loop adjusts the excitation current to change the generator terminal voltage, providing dynamic reactive power support; the inverter control loop adjusts the active current to achieve rapid power response. While superimposing the damping commands, the phase reference given by the reconstructed phase-locked loop is strictly followed to ensure phase matching accuracy at grid connection. The grid-connection trigger pulse is issued near the voltage zero-crossing point, and combined with feedforward phase compensation, the closing angle error is controlled within a small range, achieving low-impact closing. After grid connection, the damping commands gradually withdraw according to a preset attenuation curve, smoothly transitioning to normal operation.

[0014] The transient monitoring and adjustment unit continuously monitors the power oscillation decay characteristics at the grid connection point during the transient transition period after grid connection. Based on these characteristics, it dynamically adjusts the control parameters of the phase-locked loop (PLL) and the damping strength of the subsynchronous damping command until the gas turbine generator unit enters steady-state operation. The transient process after grid connection typically lasts from several seconds to tens of seconds, during which electromagnetic and mechanical variables exhibit oscillation decay. The power oscillation decay characteristics are obtained through envelope analysis and logarithmic decay rate calculation, reflecting the system's damping level and stability margin. When oscillation divergence or excessively slow decay is detected, the damping control strength is promptly increased or the PLL gain is reduced to prevent instability. When the oscillation converges rapidly, normal parameters are gradually restored to improve dynamic response capability. This closed-loop adaptive adjustment mechanism significantly improves the system's adaptability to different grid conditions, ensuring rapid and stable grid connection under various operating conditions. When the power oscillation amplitude drops to within 5% of the rated value and remains stable for more than a set time window, the unit is determined to have entered steady-state operation, completing the grid connection process.

[0015] In this embodiment of the invention, the detailed implementation steps of obtaining the current electrical parameters of the grid connection point and the current operating parameters of the gas turbine generator set, calculating the expected inrush current at the moment of grid connection based on the current electrical parameters and the current operating parameters, and calculating the self-induced phase offset caused by the expected inrush current based on the expected inrush current and the estimated grid impedance include: The process involves acquiring the voltage amplitude and phase at the grid connection point, as well as the voltage amplitude and phase at the generator terminals of the gas turbine generator set. The static phase difference between these two voltages is then calculated. Voltage parameters are acquired using high-precision voltage transformers and fast analog-to-digital converters, with sampling frequencies typically above 10kHz to ensure phase measurement accuracy within 0.5 degrees. The grid connection point voltage represents the electrical state of the grid side, while the generator terminal voltage represents the electrical state of the generator side. The phase difference between the two is the primary driving force behind the inrush current. The static phase difference is calculated using phase-locked loop (PLL) technology or discrete Fourier transform (DFT) to extract the phase information of the fundamental component, ignoring the influence of higher harmonics. The sign of the phase difference indicates whether it is leading or lagging, and the absolute value reflects the degree of synchronization deviation. Under ideal pre-synchronization conditions, the static phase difference should be close to zero. However, due to slight frequency differences and measurement delays, a certain deviation always exists in practice, directly determining the severity of the transient at the moment of closing the circuit.

[0016] Based on the grid connection point voltage amplitude, the gas turbine generator terminal voltage amplitude, and the static phase difference, combined with the equivalent transient reactance of the gas turbine generator set, the expected inrush current at the moment of grid connection is calculated. The equivalent transient reactance is a key parameter of the generator, reflecting the electromagnetic coupling characteristics between the stator winding and the rotor excitation winding, and is usually obtained through generator parameter identification or data provided by the manufacturer. The calculation of the expected inrush current is based on transient circuit analysis, considering the current response generated across the equivalent impedance by the vector difference in voltages on both sides at the moment of connection. The calculation formula is: ; in, The expected magnitude of the inrush current. The voltage amplitude at the grid connection point. This refers to the amplitude of the terminal voltage. For static phase difference, This is the equivalent transient reactance of the generator. The formula is based on the vector operation principle of AC circuits. The numerator represents the amplitude difference between two voltage vectors, reflecting the equivalent voltage source at the moment of closing the circuit breaker, while the denominator is the current-limiting impedance. When the phase difference is large or the voltage amplitude difference is significant, the inrush current may reach several times the rated current, causing severe impact on electrical equipment and mechanical structures. Accurate calculation of the expected inrush current provides a quantitative basis for subsequent compensation control and protection setting.

[0017] The pre-stored grid impedance estimate is read, and the voltage drop generated by the expected inrush current on the grid impedance estimate is projected onto a synchronous rotating coordinate system to separate the q-axis component of the voltage drop. The grid impedance estimate can be derived from historical measurement data, grid operation information, or preliminary impedance scan results as initial conditions for the calculation. The voltage drop is calculated based on Ohm's law, multiplying the inrush current by the grid impedance to obtain a vector form of the voltage drop. Projecting to the synchronous rotating coordinate system is to convert AC quantities into DC quantities for easier analysis and control. The synchronous rotating coordinate system uses the direction of the grid voltage vector as the d-axis and the direction leading by 90 degrees as the q-axis. In this coordinate system, the q-axis component of the steady-state voltage vector is zero. The q-axis component of the voltage drop reflects the voltage change perpendicular to the voltage vector direction, and this component directly causes a phase shift in the composite voltage vector. The process of separating the q-axis component uses the Park transform to convert the voltage drop in the three-phase stationary coordinate system into a component in the dq coordinate system. Mathematically, this is achieved through matrix operations to ensure the accuracy and real-time performance of the transformation.

[0018] Based on the ratio of the q-axis component of the voltage drop to the grid-connected voltage amplitude, the self-induced phase shift caused by the expected inrush current is calculated. This self-induced phase shift characterizes the degree of phase jump caused by the grid-connected operation itself. The calculation of the self-induced phase shift is based on the small-angle approximation theory. Under the condition that the voltage amplitude is much larger than the voltage drop, the phase shift angle is approximately equal to the ratio of the q-axis voltage drop to the d-axis voltage. The calculation formula is: ; in, This is the self-induced phase offset. This represents the q-axis component of the voltage drop. This represents the voltage amplitude at the grid connection point. In practical applications, when the ratio is small (less than 0.1), a linear approximation can be used directly, resulting in higher computational efficiency; when the ratio is large, the complete arctangent function is used to ensure accuracy. The physical meaning of the self-induced phase shift lies in the fact that the voltage drop caused by the inrush current flowing through the grid impedance changes the actual voltage phase at the grid connection point, and the phase-locked loop (PLL) locks this changed phase, thus generating additional phase error. This positive feedback between phase, current, and voltage is an important mechanism for PLL instability under weak grid conditions. By accurately calculating the self-induced phase shift, compensation can be made in advance in PLL control, breaking the positive feedback chain and significantly improving grid connection stability.

[0019] In this embodiment of the invention, during the grid pre-synchronization stage, a non-characteristic frequency detection signal is injected into the grid connection point. The grid impedance parameters are extracted based on the voltage response of the grid connection point to the detection signal. The detailed implementation steps for calculating the coupling interaction factor in a multi-machine parallel scenario based on the grid impedance parameters include: During the grid connection pre-synchronization phase, a non-characteristic frequency detection signal within a preset frequency band is generated. This signal is then superimposed on the current reference value of the gas turbine generator set and injected into the grid connection point. The preset frequency band is typically chosen between 150Hz and 500Hz to avoid the fundamental frequency and its lower harmonics, minimizing interference to the power grid. The detection signal can be a single-frequency sine wave or a pseudo-random sequence of multiple superimposed frequencies; the latter can acquire wide-band impedance characteristics in a single pass, improving measurement efficiency. The signal amplitude is set at 3%-8% of the rated current to ensure sufficient signal-to-noise ratio without significantly impacting system operation. The injection process is implemented through the inverter's current control loop. After superimposing the detection signal with the normal current reference value, the signal is processed by a current regulator and PWM modulation before being output to the grid connection point. The injection time is typically 5 to 10 power frequency cycles, sufficient to acquire complete response data. This active injection method offers higher measurement accuracy and anti-interference capabilities compared to passive observation, enabling reliable operation in complex power grid environments.

[0020] The voltage and current response signals at the grid connection point corresponding to the non-characteristic frequency probe signal are collected. The current grid impedance parameters are calculated based on the ratio of the voltage and current response signals in the frequency domain. These parameters include the resistance component, the inductance component, and the corresponding angle-dependent characteristics. High-speed synchronous sampling technology is used to acquire the response signals, ensuring the time alignment accuracy of voltage and current is within 1 microsecond. The acquired time-domain signal is converted to the frequency domain using a Fast Fourier Transform, and the voltage and current phasors at the probe frequency point are extracted, including amplitude and phase information. The grid impedance is calculated based on the frequency domain form of Ohm's law: impedance equals the voltage phasor divided by the current phasor. The calculation formula is: ; in, For frequency The power grid impedance at that location, and These are the voltage and current phasors at that frequency, respectively. For resistance components, The imaginary unit, For inductive components, The angular frequency is used. By separating the real and imaginary parts of the impedance, the resistance and inductance parameters are obtained. The angle-dependent characteristics are described by the relationship between the impedance phase angle and frequency, reflecting the frequency characteristics of the power grid and potential resonant points. Under weak power grid conditions, the grid impedance is relatively large and exhibits capacitive or inductive characteristics; this information is crucial for phase-locked loop (PLL) parameter design and stability analysis. Multi-frequency measurements can construct a complete impedance spectrum, providing a comprehensive understanding of the power grid's dynamic characteristics.

[0021] In scenarios involving multiple gas turbine generator units operating in parallel, it is crucial to obtain the equivalent output impedance of adjacent units and the line impedance from the point of common coupling (PCC) to the unit ports. The equivalent output impedance of adjacent units can be measured using similar detection methods or shared through communication protocols between unit controllers. The equivalent output impedance includes the generator's internal impedance and the inverter's output impedance, reflecting the unit's external electrical characteristics. The line impedance from the PCC to the unit ports primarily consists of the resistance, inductance, and capacitance of the cables or transmission lines, and can be calculated or measured based on line parameters. In mobile power station applications, line lengths and configurations may change frequently, requiring rapid measurement and updating capabilities. These impedance parameters collectively constitute the electrical topology of the multi-unit parallel system and are fundamental data for analyzing inter-unit coupling.

[0022] Based on the current grid impedance parameters, the equivalent output impedance of adjacent generating units, and the line impedance, a multi-unit port impedance network matrix is ​​constructed. Eigenvalue decomposition is performed on this matrix to extract the eigenvectors corresponding to the dominant oscillation mode as coupling interaction factors. These interaction factors quantify the interaction strength between the phase-locked loops (PLLs) of different generating units through the grid impedance. The multi-unit port impedance network matrix is ​​a mathematical model describing the electrical connection relationships of the system. The matrix elements include the self-impedance of each generating unit and the mutual impedance between units, expressed in the form of a node admittance matrix or impedance matrix. The construction process is based on circuit network theory, equating the multi-unit parallel system to a multi-port network, with each port corresponding to the connection point of one generating unit. After matrix construction, eigenvalue decomposition is performed to identify the system's oscillation modes. The real part of the eigenvalue reflects the damping characteristics of the mode, while the imaginary part reflects the oscillation frequency; the eigenvectors describe the participation degree and phase relationship of each generating unit under this mode. The dominant oscillation mode usually corresponds to the eigenvalue with the weakest damping or the frequency closest to the PLL bandwidth, and is most prone to stability problems. The coupling interaction factors are extracted from the corresponding eigenvectors, quantifying the electrical coupling strength between the PLLs of different generating units. The stronger the coupling, the easier it is for disturbances in one unit to propagate to other units, triggering a chain reaction. By analyzing the coupling interaction factor, critical coupling paths can be identified, providing a basis for the coordinated design of phase-locked loop parameters and ensuring the overall stability of multi-unit systems.

[0023] In this embodiment of the invention, the detailed implementation steps for generating a reconstructed PLL reference signal include: reconstructing the input phase of the phase-locked loop (PLL) based on the self-induced phase offset using feedforward compensation, and reshaping the control parameters of the PLL based on the coupling interaction factor using adaptive damping. At the output of the phase detection stage of the phase-locked loop (PLL), the original phase detection signal is extracted, and the self-induced phase offset is superimposed on the original phase detection signal as a feedforward compensation to cancel the phase shift or lag caused by the grid-connected inrush current, generating a compensated phase signal. The phase detection stage of the PLL typically uses a PLL phase detector or synchronous rotating coordinate transformation method to output a signal reflecting the grid voltage phase. The original phase detection signal will jump during the grid-connected inrush, causing phase reference distortion in the PLL output. The principle of feedforward compensation is to apply a reverse compensation signal to the phase detection output based on the pre-calculated self-induced phase offset, so that the phase change "seen" by the PLL is canceled in advance. The sign of the compensation amount is determined according to the direction of the inrush current, and the amplitude is calculated based on the grid impedance and current magnitude. The superposition operation is implemented in the digital controller through simple addition, with a response speed faster than the dynamic process of the PLL itself, thus effectively suppressing the influence of phase jumps. The compensated phase signal is smoother and more accurate, providing a more reliable input for the PLL controller and significantly reducing phase error and frequency oscillation at the moment of grid connection.

[0024] The initial proportional gain and initial integral gain of the phase-locked loop (PLL) are obtained. Based on the eigenvalue decomposition results of the multi-machine port impedance network matrix, the eigenvalues ​​corresponding to the dominant oscillation mode are extracted, and the damping ratio corresponding to the dominant oscillation mode is calculated based on the eigenvalues. The initial proportional gain and integral gain are fundamental parameters of the PLL PI controller, typically designed according to the grid strength and desired dynamic response speed. Under strong grid conditions, a larger gain can be used to improve tracking speed; however, under weak grid conditions, excessive gain will amplify the influence of grid impedance, leading to oscillation or even instability. The eigenvalue decomposition results provide quantitative information on the system oscillation modes, and the real part of the eigenvalues... and the virtual part These correspond to the damping coefficient and the damping oscillation frequency, respectively. The formula for calculating the damping ratio is: ; in, For the damping ratio, is the real part of the eigenvalue (usually a negative value). The damping ratio is the imaginary part of the eigenvalues. It is a key indicator for evaluating the stability margin of a system, typically requiring a ratio greater than 0.05 to ensure sufficient stability. When the damping ratio is too low, it indicates that the system is highly sensitive to disturbances and prone to sustained oscillations or divergence. By calculating the damping ratio of the dominant oscillation mode, the stability under the current phase-locked loop parameters can be quantitatively assessed, providing a clear target for parameter adjustment.

[0025] The system determines whether the damping ratio is lower than a preset damping threshold. If so, a gain adjustment coefficient is generated based on the difference between the damping ratio and the preset damping threshold. This coefficient is used to reduce the initial proportional gain, and the initial integral gain is adjusted based on a preset mapping relationship to suppress the positive feedback gain of the phase-locked loop (PLL) under weak power grid conditions. The preset damping threshold is typically set between 0.1 and 0.15 to ensure sufficient stability margin for the system. When the calculated damping ratio falls below this threshold, the gain adjustment mechanism is triggered. The gain adjustment coefficient is determined based on the degree of damping insufficiency; the lower the damping ratio, the greater the gain reduction. Specific calculation methods employ proportional control or more complex nonlinear mapping to ensure the adjusted damping ratio reaches the desired value. The reduction in proportional gain directly decreases the PLL's loop bandwidth, reducing its sensitivity to high-frequency disturbances and suppressing the positive feedback effect caused by grid impedance. The adjustment of the integral gain is based on a preset mapping relationship, typically maintaining the ratio of proportional gain to integral gain within a reasonable range to ensure that the steady-state error performance of the PLL does not severely degrade. This adaptive damping reshaping mechanism enables the phase-locked loop to dynamically adjust its parameters according to grid conditions, maintaining a fast response under strong grid conditions and ensuring stability under weak grid conditions.

[0026] The compensated phase signal is input to the gain-adjusted phase-locked loop (PLL) controller, which outputs a reconstructed PLL reference signal. This reconstructed PLL reference signal includes the reconstructed phase angle and reconstructed frequency. The core of the PLL controller is a PI regulator, which generates a frequency control quantity based on the phase error and then integrates it to obtain the phase output. The compensated phase signal serves as the PLL input, is compared with the feedback phase to generate an error signal, which is processed by the adjusted PI controller to output a frequency correction. The frequency correction is added to the rated angular frequency to obtain the reconstructed angular frequency, and then integrated to obtain the reconstructed phase angle. The reconstructed PLL reference signal exhibits better transient performance and stability, maintaining accurate tracking under grid-connection impacts and grid disturbances, providing a reliable phase reference for power control and grid synchronization. The reconstructed frequency is also used to detect grid frequency changes, enabling adaptive frequency control. The entire reconstruction process integrates feedforward compensation and feedback regulation, utilizing predictive information to proactively offset known disturbances and eliminating unknown errors through closed-loop control.

[0027] In this embodiment of the invention, at the instant of grid connection execution, the actual power oscillation signal at the grid connection point is collected, the target oscillation component in the preset subsynchronous frequency band is extracted from the actual power oscillation signal, and the detailed implementation steps for generating a subsynchronous damping command based on the target oscillation component and the shaft torsional vibration characteristics of the gas turbine generator set include: At the instant of grid connection execution, the active power signal at the grid connection point is acquired at a preset sampling frequency as the actual power oscillation signal. The preset sampling frequency needs to satisfy the Nyquist sampling theorem and be at least twice the target frequency; in practical applications, it is usually set to 2kHz to 5kHz to ensure accurate capture of the oscillation components in the subsynchronous frequency band. The active power signal is obtained by measuring the voltage and current at the grid connection point and processing it through the power calculation module, reflecting the real-time changes in electromagnetic power. At the instant of grid connection execution, due to the coupling of electromagnetic transients and mechanical inertia, the power will generate a complex oscillation waveform containing multiple frequency components. The actual power oscillation signal includes low-frequency power angle oscillations (0.1-2Hz), high-frequency electromagnetic transients (above several hundred Hz), and shaft torsional vibration response in the subsynchronous frequency band, which need to be separated using filtering techniques. High-speed acquisition and real-time processing are the foundation for subsynchronous oscillation suppression and must have low-latency signal processing capabilities.

[0028] The actual power oscillation signal is input to a pre-constructed bandpass filter bank. The passband of the bandpass filter bank covers the torsional vibration frequency range of the gas turbine generator set's shaft system, filtering out high-frequency transient components and low-frequency steady-state components, and extracting the target oscillation component within the shaft system torsional vibration frequency range. The bandpass filter bank is typically implemented using digital filters, such as Butterworth or Chebyshev filters, and its design requires balancing passband flatness and stopband attenuation. The shaft system torsional vibration frequency range is determined based on the gas turbine type and shaft system design, typically ranging from 15Hz to 45Hz, and may contain multiple torsional vibration modes. The filter bank can be designed as multiple parallel bandpass filters, each corresponding to a different torsional vibration mode, or as a single broadband filter covering the entire range. Filtering out high-frequency transient components removes interference from switching frequencies and electromagnetic noise, while filtering out low-frequency steady-state components removes the influence of fundamental power and slow power angle oscillations. The final target oscillation component purely reflects the electrical performance of the shaft system torsional vibration. The phase delay of the filter must be compensated to ensure the phase accuracy of subsequent damping control.

[0029] The torsional vibration characteristics of the shaft system in a gas turbine generator set are obtained. These characteristics include the natural torsional frequency and the mechanical damping coefficient. The natural torsional frequency is determined by the distribution of the shaft's moment of inertia and the torsional stiffness of the shaft segments, and can be obtained through mechanical analysis or experimental testing. A gas turbine typically consists of multiple rotor segments, such as the compressor, combustion chamber, turbine, and generator rotor, which are connected by shafts to form a complex multi-mass elastic system with multiple torsional vibration modes. The mechanical damping coefficient reflects the energy dissipation capacity within the shaft system, mainly derived from the material's internal damping and frictional damping. It is usually relatively small (damping ratio between 0.01 and 0.03), insufficient to effectively suppress oscillations caused by external excitation. The torsional vibration characteristics of the shaft system are key parameters for designing damping control, determining the frequency and phase of the applied electrical damping torque. These parameters are typically obtained during the unit commissioning phase through frequency sweep tests or impact response tests and stored in the control system for real-time retrieval.

[0030] The real-time frequency and phase of the target oscillation component are calculated, and the required phase and amplitude of the electrical damping torque are determined based on the deviation between the shaft system's natural torsional vibration frequency and the real-time frequency, as well as the mechanical damping coefficient. The real-time frequency is calculated using zero-crossing detection or phase difference methods, reflecting the dominant frequency component of the current oscillation. The real-time phase is extracted using Hilbert transform or phase-locked loop technology to determine the phase angle of the oscillation waveform. The frequency deviation indicates how close the actual oscillation frequency is to the natural frequency; the smaller the deviation, the closer the oscillation is to resonance, requiring stronger damping. The phase of the electrical damping torque must lag the oscillation velocity by 90 degrees or lead the oscillation displacement by 90 degrees to effectively dissipate oscillation energy. The phase determination is based on the shaft system dynamics model, considering compensation for control and execution delays. The amplitude of the damping torque is calculated based on the oscillation amplitude and insufficient mechanical damping, using the following formula: ; in, For electrical damping torque, This is the damping gain coefficient. The amplitude of the target oscillation component. For real-time oscillation angular frequency, The optimal phase angle is determined based on the target system damping ratio and oscillation energy, and is optimized through simulation or field tests. The calculation of the optimal phase angle takes into account the dynamic characteristics of the shaft system and the delay of the control system, ensuring that the damping torque is in phase with the oscillation velocity and maximizing energy dissipation efficiency.

[0031] Based on the phase and amplitude of the electrical damping torque, a subsynchronous damping command is generated. This command includes a damping compensation component that is out of phase with the target oscillation component, used to counteract the electromagnetic torque excitation caused by the phase jump of the phase-locked loop and falling near the torsional vibration frequency of the shaft system. Generating the subsynchronous damping command requires converting the torque demand into an electrical control quantity, such as active current or excitation voltage. The conversion process is based on the generator's torque-current relationship; the electromagnetic torque is proportional to the q-axis component of the stator current, therefore the damping torque can be achieved by adjusting the q-axis current. The damping compensation component uses a sinusoidal signal out of phase with the target oscillation component, with its amplitude and phase determined according to the aforementioned calculations. The command signal undergoes amplitude limiting and filtering to avoid excessive control actions causing new problems. The subsynchronous damping command, as an additional control signal, is activated at the moment of grid connection and gradually withdraws as the oscillation decays, ensuring minimal impact on normal operation.

[0032] In this embodiment of the invention, the detailed implementation steps for superimposing the subsynchronous damping command onto the excitation control circuit and inverter control circuit of the gas turbine generator set, and performing rapid grid connection operation under the phase constraint of the reconstructed phase-locked loop reference signal, include: The subsynchronous damping command is analyzed to extract the first damping component corresponding to electromagnetic power control and the second damping component corresponding to reactive power control. Subsynchronous damping can be achieved through two paths: the active power path and the reactive power path. The active power path directly affects the electromagnetic torque, while the reactive power path indirectly affects the torque by changing the air gap magnetic field. The first damping component corresponds to the modulation of the active current, directly regulating the fluctuation of electromagnetic power, with a fast response and significant damping effect. The second damping component corresponds to the modulation of the excitation current or the terminal voltage, affecting the electromagnetic torque by changing the magnetic flux. Its response is relatively slower, but it can provide additional damping contribution. The extraction of the two components is based on the power decoupling principle, decomposing the total damping demand into two orthogonal components, active and reactive, which are implemented through different control loops. The analysis process is completed in the digital controller through coordinate transformation and component projection, ensuring that there is no coupling interference between the two components. Appropriately allocating the ratio of the two damping components can optimize the damping effect and avoid overload or saturation of a single channel.

[0033] In the excitation control circuit of a gas turbine generator set, a second damping component is superimposed on the voltage reference value of the automatic voltage regulator (AVR) to dynamically adjust the generator terminal voltage at the moment of grid connection, providing reactive power damping. The AVR is the core of the excitation system, controlling the generator terminal voltage and reactive power output by adjusting the excitation current. The second damping component, as an additional signal, is superimposed on the voltage reference value, forming dynamic voltage modulation. This modulation causes small fluctuations in the generator terminal voltage, thereby altering the reactive component of the electromagnetic torque and producing a damping effect. The superposition operation is performed at the input of the AVR, passing through the voltage regulator and the excitation power unit, and is ultimately reflected in the excitation winding current. Due to the time constant of the excitation system (typically on the order of tens of milliseconds), the response speed of reactive power damping is slower than that of active power damping, but it can provide continuous damping support. The amplitude of the second damping component needs to be limited within a reasonable range to avoid voltage fluctuations exceeding the allowable voltage deviation (typically ±5%), which could affect power quality or trigger protection devices. The superposition control is implemented in software, offering high flexibility and allowing for dynamic adjustment based on actual conditions.

[0034] In the inverter control loop of a gas turbine generator set, a first damping component is superimposed on the active current reference value to dynamically adjust the active current and provide active damping at the moment of grid connection. The inverter control loop adopts a dual closed-loop control structure with an inner current loop and an outer power loop. The active current reference value is generated by the outer power loop according to the power command. The first damping component, superimposed on the active current reference value, directly modulates the active current output by the inverter, causing rapid changes in active power. The fluctuations in active power act on the generator rotor through electromagnetic torque, generating a damping torque opposite to the torsional vibration speed, effectively suppressing oscillations. Due to the high bandwidth of the inner current loop (typically in the hundreds of Hz), the active damping response speed is very fast, enabling real-time tracking of the dynamic changes in subsynchronous oscillations. The superposition operation is performed in the current reference value generation stage and does not affect the normal power control logic. The frequency of the first damping component is consistent with the torsional vibration frequency, and the phase is precisely adjusted to ensure optimal damping effect. The fast response capability of the inverter control loop is the key to achieving effective subsynchronous damping, and the advancement of modern power electronics technology has made this active damping strategy possible.

[0035] Based on the reconstructed phase angle in the reconstructed phase-locked loop (PLL) reference signal, coordinate transformation and pulse width modulation (PWM) are performed on the control loop, which superimposed with the first and second damping components. This outputs a grid-connection trigger pulse to execute the grid-connection closing operation. The first and second damping components gradually decrease according to a preset attenuation curve within a preset time window after grid-connection closing. Coordinate transformation converts the control quantity in the dq rotating coordinate system into a modulated signal in the three-phase stationary coordinate system, requiring accurate phase angle information. The reconstructed phase angle provided by the reconstructed PLL reference signal undergoes feedforward compensation and adaptive adjustment, resulting in higher accuracy and stability, ensuring the accuracy of the coordinate transformation. Pulse width modulation (PWM) generates drive pulses for the switching devices based on the modulated signal, controlling the inverter's output voltage waveform. The grid-connection trigger pulse closes the grid-connection switch at an appropriate time, achieving synchronous connection between the generator and the grid. The closing time is selected based on phase synchronization conditions, ideally near the voltage zero-crossing point, and minimizes inrush current through feedforward compensation. After grid-connection closing, the damping component cannot disappear immediately, otherwise it would cause a sudden control change; instead, it gradually decreases according to a preset attenuation curve. The decay curve typically employs an exponential function or a linear ramp, with a time window set to 3 to 10 seconds, dynamically adjusted according to the oscillation decay rate. This smooth exit mechanism ensures a seamless transition from transient damping control to normal operation, avoiding the generation of secondary disturbances.

[0036] In this embodiment of the invention, during the transient transition period after grid connection, the power oscillation attenuation characteristics at the grid connection point are continuously monitored. Based on the power oscillation attenuation characteristics, the control parameters of the phase-locked loop and the damping strength of the subsynchronous damping command are dynamically adjusted until the gas turbine generator set enters steady-state operation. The detailed implementation steps include: During the transient transition period after grid connection, the envelope of the power oscillation waveform at the grid connection point is extracted according to a sliding time window. The attenuation ratio of adjacent peaks is calculated based on the envelope as a characteristic of power oscillation attenuation. The sliding time window needs to cover several oscillation cycles, typically 0.5 to 2 seconds, to ensure the complete oscillation waveform is captured. Envelope extraction uses Hilbert transform or peak detection algorithms, connecting the peaks of the power oscillation waveform to form an attenuation envelope curve. The attenuation ratio of adjacent peaks is defined as the ratio of the amplitude of the subsequent peak to the amplitude of the preceding peak, reflecting the rate of attenuation of oscillation energy. The formula for calculating the attenuation ratio is: ; in, The attenuation ratio, and The first The and the first The amplitude of each peak. An attenuation ratio less than 1 indicates oscillation attenuation, equal to 1 indicates constant amplitude oscillation, and greater than 1 indicates oscillation divergence. By continuously calculating multiple attenuation ratios, the attenuation trend and stability of the oscillation can be evaluated. Power oscillation attenuation characteristics are a key indicator for evaluating grid-connected transient performance, directly reflecting the system's damping level and stability margin. Real-time monitoring of this characteristic provides feedback for dynamically adjusting control parameters.

[0037] The system determines whether the attenuation ratio meets the preset convergence condition. If the attenuation ratio indicates oscillation divergence or critical oscillation, the current adjusted control parameters of the phase-locked loop (PLL) are maintained, and the damping strength of the subsynchronous damping command is increased by a preset step size. The preset convergence condition is typically set to an attenuation ratio less than 0.9 and showing a decreasing trend, indicating that the oscillation is effectively attenuating. If the attenuation ratio is greater than or equal to 0.95 or shows an increasing trend, it indicates oscillation divergence or critical oscillation, requiring enhanced damping control. Maintaining the current parameters of the PLL is to maintain the stability of phase tracking and avoid new disturbances caused by frequent parameter changes. Increasing the damping strength of the subsynchronous damping command is achieved by increasing the damping gain coefficient. The preset step size is usually 10%-20% of the initial value, dynamically adjusted according to the severity of the oscillation. Increasing the damping strength will increase the amplitude of the control output and accelerate the dissipation of oscillation energy, but it will also increase the output load of the controller. Therefore, the upper limit needs to be set carefully (usually not exceeding 3 times the initial value). This adaptive enhancement mechanism ensures that the system can achieve stability through active control even under the worst grid connection conditions.

[0038] If the attenuation ratio indicates rapid oscillation convergence, the proportional gain of the phase-locked loop (PLL) is gradually restored to its initial value according to the magnitude of the attenuation ratio to improve the dynamic response speed of the PLL. Simultaneously, the damping strength of the subsynchronous damping command is reduced proportionally. Rapid oscillation convergence typically refers to an attenuation ratio less than 0.7 and continuously decreasing, indicating sufficient system damping and the imminent end of the transient process. At this point, the proportional gain of the PLL can be gradually restored to improve the speed and accuracy of phase tracking, preparing for subsequent dynamic adjustment. The restoration process employs a gradual strategy, increasing the gain by a certain percentage (typically 5%-10%) each control cycle until the initial design value is reached. Simultaneously, the damping strength of the subsynchronous damping command is reduced at the same or faster rate to avoid over-damping affecting the system's dynamic performance. The reduction ratio is adaptively determined based on the attenuation rate; the faster the attenuation, the faster the reduction rate. This coordinated adjustment mechanism maximizes the system's dynamic performance while ensuring stability, achieving an optimal balance between stability and speed.

[0039] When the power oscillation attenuation characteristics meet the steady-state determination threshold and the duration exceeds the steady-state confirmation window, the output of the subsynchronous damping command is cut off, and the control parameters of the phase-locked loop (PLL) are fixed to the rated operating parameters, confirming that the gas turbine generator unit has entered steady-state operation. The steady-state determination threshold is typically set when the power oscillation amplitude is less than 5% of the rated power and the attenuation ratio is less than 0.5, indicating that the oscillation has essentially disappeared. The steady-state confirmation window is set to 3 to 5 seconds to ensure that the steady state is not a temporary phenomenon but a continuous state. When both conditions are met simultaneously, the transient determination process ends, and the additional damping control can be safely cut off. The cutoff of the subsynchronous damping command adopts a zero-crossing method, disconnecting at the moment the signal crosses zero to avoid new disturbances caused by sudden changes. The control parameters of the PLL are fixed to the rated operating parameters, which are optimized for steady-state operation and can provide the best control performance under normal conditions. After confirming entry into steady-state operation, the system can accept new dispatch commands, participate in power regulation and frequency support of the power grid, and complete the complete transition from independent operation to grid-connected operation. This confirmation mechanism provides clear status feedback for operators and upper-level control systems, facilitating coordinated management and optimized dispatch.

[0040] In this embodiment of the invention, after constructing a multi-unit port impedance network matrix based on the current grid impedance parameters, the equivalent output impedance of adjacent units, and the line impedance, the method further includes: Based on the multi-machine port impedance network matrix, the apparent impedance of the local machine port and the dominant cross-linking impedance with the strongest coupling to the local machine are calculated. The apparent impedance of the local machine port is the equivalent impedance seen into the entire system from the local machine port, integrating the combined effects of grid impedance, line impedance, and impedances from other units. The calculation method is based on network simplification theory, equating the multi-port network to a single-port network, and calculating it using the determinant and cofactor of the impedance matrix. The magnitude of the port apparent impedance reflects the strength of the grid; a larger impedance indicates a weaker grid. The dominant cross-linking impedance refers to the equivalent impedance of other units or grid components that have the greatest impact on the local machine, identified through sensitivity analysis or impedance contribution calculation. Identifying the dominant cross-linking impedance helps to find the critical coupling path, providing a basis for targeted decoupling control.

[0041] The system determines whether the per-unit value of the apparent impedance at the local port is greater than a preset weak grid threshold. If it is, the current grid-connected scenario is marked as an extremely weak grid scenario. The per-unit value is a dimensionless quantity obtained by dividing the actual impedance by the reference impedance, facilitating comparisons between different systems. The reference impedance is usually chosen as the system's rated impedance, determined by the rated voltage and rated power. The preset weak grid threshold is determined based on engineering experience and stability analysis, typically set to 0.15 to 0.3 per-unit values. Exceeding this threshold indicates a significantly insufficient grid strength, classifying it as an extremely weak grid. Under extremely weak grid conditions, the cross-impedance ratio between the inverter and the grid is close to or greater than 1, making traditional control strategies prone to instability and requiring special control measures. Marking the scenario as extremely weak triggers subsequent virtual impedance reshaping control, a crucial means of dealing with extreme operating conditions. Accurately determining grid strength is essential for selecting an appropriate control strategy.

[0042] In extremely weak grid scenarios, a virtual impedance injection command is generated based on the phase angle of the dominant cross-linking impedance. This virtual impedance command is converted into a virtual voltage drop, which is then superimposed on the voltage reference command of the gas turbine generator set. This reshapes the amplitude-frequency characteristics of the unit's equivalent output impedance, causing the reshaped equivalent output impedance to exhibit impedance decoupling characteristics with the grid impedance parameters at the cutoff frequency of the phase-locked loop (PLL), thus cutting off the cross-linking path between multiple PLLs. Virtual impedance technology simulates the effect of physical impedance through control algorithms, altering the electrical characteristics presented by the inverter. The virtual impedance injection command is designed based on the phase angle of the dominant cross-linking impedance, typically selecting an impedance type with the opposite phase to the cross-linking impedance to achieve impedance cancellation or decoupling. For example, if the cross-linking impedance is inductive, a capacitive virtual impedance is injected; if it is capacitive, an inductive virtual impedance is injected. The formula for converting virtual impedance into a virtual voltage drop is: ; in, For virtual voltage drop, For virtual impedance, This represents the inverter output current. A virtual voltage drop superimposed on the voltage reference command is equivalent to having a virtual impedance connected in series at the output. This superposition alters the inverter's output impedance characteristics, causing it to exhibit the desired impedance value within a specific frequency range. The goal of this reshaping is to decouple the local equivalent output impedance from the grid impedance at the PLL cutoff frequency (typically 10Hz to 50Hz), meaning the impedance ratio of the two meets the stability condition. The decoupling characteristic can be verified using the Nyquist criterion or impedance ratio criterion, ensuring that the system's open-loop transfer function does not encircle the point (-1, j0). Cutting off the interactive coupling path between multiple PLLs means that disturbances from one unit will not be transmitted to other units through the impedance network, avoiding the cascading propagation of oscillations. Virtual impedance reshaping technology is an advanced control method for dealing with extremely weak grids and complex operating conditions of multiple units in parallel, significantly improving system stability and robustness.

[0043] In this embodiment of the invention, after calculating the self-induced phase shift caused by the expected surge current, the method further includes: The self-induced phase shift is compared with a preset phase transition threshold. This threshold is determined based on the stability margin of the phase-locked loop (PLL) and the system's tolerance, and is typically set to 5 to 10 degrees. Phase transitions exceeding this threshold may cause the PLL to lose synchronization, power oscillations, or protection activation, jeopardizing grid connection safety. The comparison is performed in real-time in the controller, providing a basis for subsequent decision-making. This step is a crucial part of grid connection risk assessment, allowing for the anticipation of potential problems and the implementation of preventative measures.

[0044] If the self-induced phase offset exceeds the phase jump threshold, it is determined that there is a risk of phase jump instability under the current grid connection conditions. This determination triggers risk warnings and response measures to prevent accidents caused by blind grid connection. The risk of phase jump instability indicates that the current electrical conditions are not suitable for direct grid connection, requiring adjustments to the grid connection strategy or improvements to the initial conditions, thus avoiding problems caused by human error or insufficient condition assessment.

[0045] When there is a risk of phase jump instability, a grid connection timing correction command is generated. This command is used to postpone the closing phase angle to near the zero-crossing point of the grid connection point voltage, or to adjust the excitation current before closing to reduce the static phase difference to a preset safe phase difference range. Grid connection timing correction is a proactive measure to optimize grid connection conditions. By adjusting the closing time or regulating the unit status, it reduces inrush current and phase jump. Postponing the closing phase angle to near the zero-crossing point of the voltage utilizes the natural characteristics of the voltage waveform, closing the circuit when the instantaneous voltage value is at its minimum. At this time, even if a phase difference exists, the voltage difference is small, and the inrush current is correspondingly reduced. Adjusting the excitation current changes the amplitude and phase of the generator terminal voltage. Through excitation control, the generator terminal voltage is made closer to the grid connection point voltage in amplitude and phase, reducing the static phase difference. The preset safe phase difference range is usually within ±3 degrees. Within this range, grid connection can control the inrush current and phase jump to an acceptable level. The execution of the correction command requires coordination of multiple subsystems such as circuit breaker control, excitation system, and power control to ensure the timing and accuracy of each component's actions.

[0046] After the static phase difference meets the preset safe phase difference range, the expected inrush current and self-induced phase offset are recalculated until the self-induced phase offset is less than or equal to the preset phase jump threshold. This is an iterative optimization process that ensures optimal grid connection conditions through repeated adjustments and verifications. The recalculation uses the same method and formulas, deriving new prediction results based on the adjusted electrical parameters. The iterative process typically converges within 2 to 5 iterations because the adjustment direction is clear. Once the self-induced phase offset meets the threshold condition, the grid connection conditions are confirmed to be safe, and grid connection operation can be performed. This closed-loop optimization mechanism significantly improves the success rate and safety of grid connection, demonstrating the advantages of intelligent control.

[0047] In this embodiment of the invention, the detailed implementation steps of inputting the compensated phase signal into the phase-locked loop controller after gain adjustment, and the phase-locked loop controller outputting the reconstructed phase-locked loop reference signal include: The phase error signal is generated by subtracting the compensated phase signal from the feedback phase signal of the phase-locked loop (PLL). The basic principle of a PLL is to use phase error feedback control to make the output phase track the input phase. The feedback phase signal is the phase angle output by the PLL, representing the current tracking state. The compensated phase signal serves as the desired phase reference; the difference between the two is the phase error, which drives the PLL to adjust. The calculation of the phase error signal needs to consider the periodicity of the phase. Phase transitions are handled through modulo arithmetic or phase unwrapping techniques to ensure the error signal is within ±180 degrees. The phase error is the core variable of PLL control, directly determining the controller's output and the system's dynamic response.

[0048] The phase error signal is input to the proportional and integral components of the phase-locked loop (PLL) controller after gain adjustment, generating the frequency control increment. PLL controllers typically employ a PI structure, with the proportional component providing fast response and the integral component eliminating steady-state error. The gain-adjusted controller exhibits adaptive characteristics, dynamically adjusting the control strength according to grid conditions. The output of the proportional component is the phase error multiplied by the proportional gain, and the output of the integral component is the integral of the phase error multiplied by the integral gain; the sum of these two values ​​yields the frequency control increment. The unit of the frequency control increment is radians per second, representing the correction amount to the PLL output frequency. The design of a PI controller requires a balance between speed and stability; excessive gain leads to oscillation, while insufficient gain results in slow response. The adaptive gain adjustment mechanism optimizes parameters in real time, achieving good control performance under various operating conditions.

[0049] The frequency control increment is added to the rated grid angular frequency to obtain the reconstructed angular frequency. Integrating this reconstructed angular frequency generates the reconstructed phase angle in the reconstructed phase-locked loop (PLL) reference signal. The rated grid angular frequency is the system's reference frequency, typically [value missing]. or Radius per second corresponds to a grid frequency of 50Hz or 60Hz. The frequency control increment is superimposed on the reference frequency to form a dynamically adjusted angular frequency. The reconstructed angular frequency reflects the phase-locked loop's tracking of grid frequency changes, enabling timely response to grid frequency deviations. Integration converts the angular frequency into a phase angle; the integral formula is: ; in, for Reconstructed phase angle at time step The initial phase angle, To reconstruct the angular frequency, For the current moment, This is the initial time (lower limit of integration). As dummy variables in integration, intermediate variables in the integration process, The frequency range continuously changes from the lower limit to the upper limit within the interval. The integral in the digital controller employs a discretization method, such as the Euler method or trapezoidal rule, to accumulate the frequency increment for each control cycle. The reconstructed phase angle, as the final output of the phase-locked loop (PLL), is provided for coordinate transformation and power control, serving as the phase reference for the entire control system. The generated reconstructed PLL reference signal includes both phase angle and frequency, providing the necessary information for different control elements.

[0050] During the generation of the reconstructed phase angle, a frequency change rate limiter is set for the reconstructed angular frequency. This limiter restricts the maximum change in the reconstructed angular frequency per unit time to suppress PLL frequency overshoot caused by voltage phase abrupt changes under weak grid conditions. Frequency change rate limiting is a protective measure to prevent excessive PLL response and avoid abnormal frequency fluctuations caused by transient disturbances. The limiter is set to a maximum frequency change rate, typically 2%-5% of the rated frequency per second, i.e., 1Hz / s to 2.5Hz / s. When the calculated frequency control increment causes the frequency change rate to exceed the limit value, it is reduced to the limit boundary to prevent frequency abrupt changes. The limiting operation is performed before integration to ensure a smooth and continuous output reconstructed angular frequency. This limiting mechanism is particularly important under weak grid conditions because the grid voltage phase may jump rapidly due to impedance voltage drops. If the PLL completely follows these jumps, it will cause significant frequency overshoot, leading to power oscillations or even loss of synchronization. By limiting the frequency change rate, the PLL can filter out high-frequency disturbances, maintain a stable frequency output, and significantly improve robustness under weak grid conditions. The parameters of the frequency change rate limiter need to be optimized according to the system characteristics and power grid conditions. Too small a limit will reduce the dynamic response speed, while too large a limit will not play a protective role.

[0051] This invention achieves rapid and stable grid connection of mobile gas turbine generator sets in weak grid and multi-unit parallel scenarios through inrush current prediction, real-time grid impedance measurement, phase-locked loop reconstruction control, subsynchronous oscillation suppression, and transient dynamic adjustment. It features precision and robustness, enabling refined control and risk prediction throughout the entire grid connection process, effectively suppressing inrush current and subsynchronous oscillations, and providing comprehensive transient stability assurance.

[0052] The above are merely preferred embodiments of the present invention and are not intended to limit the present invention. Although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art can still modify the technical solutions described in the foregoing embodiments or make equivalent substitutions for some of the technical features. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

[0053] It should be noted that all formulas in this manual are calculated by removing dimensions and taking their numerical values. The formulas are derived from software simulations based on a large amount of collected data to obtain the most recent real-world results. The preset parameters and thresholds in the formulas are set by those skilled in the art according to the actual situation.

[0054] Although embodiments of the invention have been shown and described, those skilled in the art will understand that various changes, modifications, substitutions and alterations can be made to these embodiments without departing from the principles and spirit of the invention, the scope of which is defined by the claims and their equivalents.

Claims

1. A mobile gas turbine generator set rapid grid connection transient stability control system, characterized in that, include: The inrush current prediction module is used to obtain the current electrical parameters of the grid connection point and the current operating parameters of the gas turbine generator set after receiving the grid connection command, calculate the expected inrush current at the moment of grid connection based on the current electrical parameters and the current operating parameters, and calculate the self-induced phase offset caused by the expected inrush current based on the expected inrush current and the estimated grid impedance. The grid impedance measurement unit is used to inject a non-characteristic frequency detection signal into the grid connection point during the grid connection pre-synchronization stage, extract grid impedance parameters based on the voltage response of the grid connection point to the detection signal, and calculate the coupling interaction factor in the multi-machine parallel scenario based on the grid impedance parameters. A phase-locked loop (PLL) reconfiguration controller is used to perform feedforward compensation reconfiguration of the input phase of the PLL based on the self-achieved phase offset, and to perform adaptive damping reshaping of the control parameters of the PLL based on the coupling interaction factor, thereby generating a reconfigured PLL reference signal. The subsynchronous oscillation suppression unit is used to collect the actual power oscillation signal of the grid connection point at the moment of grid connection execution, extract the target oscillation component in the preset subsynchronous frequency band from the actual power oscillation signal, and generate a subsynchronous damping command based on the target oscillation component and the shaft torsional vibration characteristics of the gas turbine generator set. The grid-connection execution controller is used to superimpose the subsynchronous damping command onto the excitation control circuit and inverter control circuit of the gas turbine generator set, and perform fast grid-connection operation under the phase constraint of the reconstructed phase-locked loop reference signal; The transient monitoring and adjustment unit is used to continuously monitor the power oscillation attenuation characteristics of the grid connection point during the transient transition period after grid connection, and dynamically adjust the control parameters of the phase-locked loop and the damping strength of the subsynchronous damping command based on the power oscillation attenuation characteristics until the gas turbine generator set enters steady-state operation.

2. The system according to claim 1, characterized in that, The process of acquiring the current electrical parameters of the grid connection point and the current operating parameters of the gas turbine generator set, calculating the expected inrush current at the moment of grid connection based on the current electrical parameters and the current operating parameters, and calculating the self-induced phase offset caused by the expected inrush current based on the expected inrush current and the estimated grid impedance, includes: Obtain the voltage amplitude at the grid connection point, the voltage phase at the grid connection point, the voltage amplitude at the generator terminal of the gas turbine generator set, and the voltage phase at the generator terminal of the gas turbine generator set; calculate the static phase difference between the voltage phase at the grid connection point and the voltage phase at the generator terminal of the gas turbine generator set. Based on the voltage amplitude at the grid connection point, the voltage amplitude at the generator terminal of the gas turbine generator set, and the static phase difference, combined with the equivalent transient reactance of the gas turbine generator set, the expected inrush current at the moment of grid connection is calculated. Read the pre-stored grid impedance estimate, project the voltage drop generated by the expected inrush current on the grid impedance estimate onto the synchronous rotating coordinate system, and separate the q-axis component of the voltage drop; The self-induced phase shift caused by the expected inrush current is calculated based on the ratio of the q-axis component of the voltage drop to the voltage amplitude at the grid connection point.

3. The system according to claim 1, characterized in that, In the pre-synchronization phase of grid connection, a non-characteristic frequency detection signal is injected into the grid connection point. Based on the voltage response of the grid connection point to the detection signal, grid impedance parameters are extracted. Based on the grid impedance parameters, the coupling interaction factor in a multi-machine parallel scenario is calculated, including: During the grid connection pre-synchronization stage, a non-characteristic frequency detection signal with a frequency within a preset frequency band is generated, and the non-characteristic frequency detection signal is superimposed on the current reference value of the gas turbine generator set and injected into the grid connection point. The voltage response signal and current response signal corresponding to the non-characteristic frequency detection signal at the grid connection point are collected. The current grid impedance parameter is calculated based on the ratio of the voltage response signal and the current response signal in the frequency domain. The current grid impedance parameter includes the resistance component, the inductance component and the corresponding angle-dependent characteristics. In scenarios where multiple gas turbine generator sets operate in parallel, obtain the equivalent output impedance of adjacent units and the line impedance from the common connection point to the unit port; Based on the current grid impedance parameters, the equivalent output impedance of the adjacent generating units, and the line impedance, a multi-unit port impedance network matrix is ​​constructed. The multi-unit port impedance network matrix is ​​then subjected to eigenvalue decomposition, and the eigenvectors corresponding to the dominant oscillation mode are extracted as coupling interaction factors.

4. The system according to claim 3, characterized in that, The process of reconstructing the input phase of the phase-locked loop (PLL) based on the self-achieved phase offset and adaptively damping the control parameters of the PLL based on the coupling interaction factor to generate a reconstructed PLL reference signal includes: At the output of the phase detection stage of the phase-locked loop, the original phase detection signal is extracted, and the self-induced phase offset is superimposed on the original phase detection signal as a feedforward compensation amount to offset the phase forward or lag caused by the grid-connected inrush current and generate a compensated phase signal. Obtain the initial proportional gain and initial integral gain of the phase-locked loop, extract the eigenvalues ​​corresponding to the dominant oscillation mode based on the eigenvalue decomposition results of the multi-machine port impedance network matrix, and calculate the damping ratio corresponding to the dominant oscillation mode based on the eigenvalues. Determine whether the damping ratio is lower than a preset damping threshold. If so, generate a gain adjustment coefficient based on the difference between the damping ratio and the preset damping threshold. Use the gain adjustment coefficient to reduce the initial proportional gain and adjust the initial integral gain based on a preset mapping relationship to suppress the positive feedback gain of the phase-locked loop under a weak power grid. The compensated phase signal is input to the phase-locked loop controller after gain adjustment, and the phase-locked loop controller outputs a reconstructed phase-locked loop reference signal, which includes a reconstructed phase angle and a reconstructed frequency.

5. The system according to claim 1, characterized in that, At the instant of grid connection execution, the actual power oscillation signal of the grid connection point is collected, a target oscillation component in a preset subsynchronous frequency band is extracted from the actual power oscillation signal, and a subsynchronous damping command is generated based on the target oscillation component and the shaft torsional vibration characteristics of the gas turbine generator set, including: At the moment of grid connection execution, the active power signal of the grid connection point is collected at a preset sampling frequency as the actual power oscillation signal; The actual power oscillation signal is input to a pre-constructed bandpass filter group. The passband range of the bandpass filter group covers the shaft torsional vibration frequency range of the gas turbine generator set, filtering out high-frequency transient components and low-frequency steady-state components, and extracting the target oscillation component within the shaft torsional vibration frequency range. The torsional vibration characteristics of the shaft system of the gas turbine generator set are obtained, including the natural torsional vibration frequency and mechanical damping coefficient of the shaft system. Calculate the real-time frequency and phase of the target oscillation component, and determine the required electrical damping torque phase and amplitude based on the deviation between the natural torsional vibration frequency of the shaft system and the real-time frequency, as well as the mechanical damping coefficient. Based on the phase and amplitude of the electrical damping torque, a subsynchronous damping command is generated, which includes a damping compensation component that is out of phase with the target oscillation component.

6. The system according to claim 1, characterized in that, The step of superimposing the subsynchronous damping command onto the excitation control circuit and inverter control circuit of the gas turbine generator set, and performing a fast grid connection operation under the phase constraint of the reconstructed phase-locked loop reference signal, includes: The subsynchronous damping command is analyzed to extract the first damping component corresponding to electromagnetic power control and the second damping component corresponding to reactive power control. In the excitation control circuit of the gas turbine generator set, the second damping component is superimposed on the voltage reference value of the automatic voltage regulator; In the inverter control circuit of the gas turbine generator set, the first damping component is superimposed on the active current reference value; Based on the reconstructed phase angle in the reconstructed phase-locked loop reference signal, coordinate transformation and pulse width modulation are performed on the control loop superimposed with the first damping component and the second damping component to output a grid-connected trigger pulse and execute the grid-connected closing operation. The first damping component and the second damping component gradually decrease according to a preset attenuation curve within a preset time window after grid-connected closing.

7. The system according to claim 1, characterized in that, During the transient transition period after grid connection, the power oscillation attenuation characteristics of the grid connection point are continuously monitored, and the control parameters of the phase-locked loop and the damping strength of the subsynchronous damping command are dynamically adjusted based on the power oscillation attenuation characteristics until the gas turbine generator set enters steady-state operation, including: During the transient transition period after grid connection, the envelope of the power oscillation waveform at the grid connection point is extracted according to the sliding time window, and the attenuation ratio of adjacent peaks is calculated based on the envelope as the power oscillation attenuation characteristic. Determine whether the attenuation ratio meets the preset convergence condition. If the attenuation ratio indicates oscillation divergence or critical oscillation, maintain the current adjusted control parameters of the phase-locked loop and increase the damping strength of the subsynchronous damping command by a preset step size. If the attenuation ratio indicates that the oscillation converges rapidly, the proportional gain of the phase-locked loop is gradually restored to the initial value according to the magnitude of the attenuation ratio, while the damping strength of the subsynchronous damping command is reduced according to the corresponding ratio. When the power oscillation attenuation characteristic meets the steady-state determination threshold and the duration exceeds the steady-state confirmation window, the output of the subsynchronous damping command is cut off, and the control parameters of the phase-locked loop are fixed to the rated operating parameters to confirm that the gas turbine generator set has entered steady-state operation.

8. The system according to claim 3, characterized in that, After constructing the multi-unit port impedance network matrix based on the current grid impedance parameters, the equivalent output impedance of the adjacent units, and the line impedance, the method further includes: Based on the multi-machine port impedance network matrix, calculate the apparent impedance of the local port and the dominant interactive impedance that is most strongly coupled to the local machine. Determine whether the per-unit value of the apparent impedance of the local port is greater than a preset weak grid threshold. If it is greater, mark the current grid connection scenario as an extremely weak grid scenario. In the scenario of extremely weak power grid, a virtual impedance injection command is generated based on the phase angle of the dominant interactive impedance. The virtual impedance command is converted into a virtual voltage drop and then superimposed on the voltage reference command of the gas turbine generator set to cut off the interactive coupling path between the multi-machine phase-locked loops.

9. The system according to claim 2, characterized in that, After calculating the self-induced phase shift caused by the expected surge current, the method further includes: The self-induced phase offset is compared with a preset phase jump threshold. If the self-induced phase offset exceeds the phase jump threshold, it is determined that there is a risk of phase jump instability under the current grid connection conditions; When there is a risk of phase jump instability, a grid connection timing correction command is generated; After the static phase difference meets the preset safe phase difference range, the expected impact current and self-induced phase offset are recalculated until the self-induced phase offset is less than or equal to the preset phase jump threshold.

10. The system according to claim 4, characterized in that, The step of inputting the compensated phase signal into the gain-adjusted phase-locked loop (PLL) controller, and having the PLL controller output a reconstructed PLL reference signal, includes: The phase error signal is generated by subtracting the compensated phase signal from the feedback phase signal of the phase-locked loop. The phase error signal is input to the proportional and integral components of the phase-locked loop controller after gain adjustment to generate frequency control increments. The frequency control increment is added to the rated grid angular frequency to obtain the reconstructed angular frequency. The reconstructed angular frequency is then integrated to generate the reconstructed phase angle in the reconstructed phase-locked loop reference signal. During the process of generating the reconstructed phase angle, a frequency change rate limiter is set for the reconstructed angular frequency.

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