Inertia collaborative regulation method for power distribution network source-storage combined system based on frequency dynamic partitioning

Abstract

The application discloses a kind of frequency dynamic partition-based power distribution network source storage combined system inertia collaborative control methods, it is related to new energy grid-connected power generation technical field.The method includes: calculating active power disturbance amount;Based on the first minimum inertia requirement of frequency change rate and deviation constraint and the second minimum inertia requirement, the larger value is determined to determine the comprehensive minimum inertia requirement;Accordingly determine the participation device combination and inertia setting value and calculate system equivalent total inertia;Build time domain frequency response analytical expression, utilize the extreme condition that first derivative is zero to solve inertia response duration;Control each device responds in stages, and when reaching the duration, additional differential adjustment gain related to frequency change rate is zero to lock differential control channel.The application is used to solve the problem that traditional frequency modulation is out of place due to single constraint evaluation, lack of cooperation leads to support not continuous and frequency secondary drop is caused by active power reverse absorption in recovery period differential lag.

Description

Technical Field

[0001] This invention relates to the field of new energy grid-connected power generation technology, and more specifically, to a method for coordinated control of inertia in a distribution network source-storage integrated system based on frequency dynamic zoning. Background Technology

[0002] The high proportion of renewable energy integration has led to increasingly prominent low inertia and weak damping characteristics in distribution networks. Traditional inertia support mechanisms, which rely on the physical kinetic energy released by the rotating rotors of synchronous generators, are prone to exceeding safety margins in the face of sudden power deficit disturbances, with the rate of frequency change (RoCoF) and transient frequency deviation amplitude easily exceeding safety margins. To ensure the transient stability of distribution networks under high renewable energy integration, it is urgent to introduce novel virtual inertia control technology to achieve multi-source collaborative active inertia response from distributed converters and other energy-storage frequency regulation assets.

[0003] Regarding the inertia coordination of multi-source assets, existing technologies, such as CN 120357492 A, disclose a method for coordinating the inertia and frequency of wind, solar, energy storage, and regulation. This method, while meeting the safety requirements of grid frequency changes, calculates the minimum inertia time constant requirement of the power system in the initial stage of frequency disturbance based on the minimum inertia time constant demand formula. Furthermore, by calculating the inertia time constants of generators, wind turbines, energy storage, photovoltaic systems, and synchronous condensers, it determines the inertia support time required when the frequency drops to its lowest value. Finally, it controls the participation and mechanized withdrawal of each device's inertia support based on the magnitude of the disturbance power.

[0004] However, the above-mentioned scheme still has the following limitations in practical applications: First, its minimum inertia requirement is only calculated in one dimension based on a single first-order frequency change rate constraint, failing to take into account the absolute safety boundary of the frequency deviation constraint, which is prone to inaccurate inertia configuration; Second, after the support time is reached, it only controls the corresponding equipment to exit directly, failing to implement precise extreme point dynamic blocking of the differential channel from the transient characteristics of the control loop, which makes it very easy for power reverse absorption to occur due to the lag in the response of the differential link during the frequency recovery stage, causing secondary frequency drop and over-adjustment oscillation; Third, there is a lack of dynamic partitioning and timing coordination between multi-source heterogeneous units based on the disturbance magnitude, which is very easy to cause frequent wear and tear of energy storage assets under small disturbances, while under large disturbances, due to the lack of orderly timing handover at the source energy storage level, the transient continuity of the system's active power support is seriously insufficient. Summary of the Invention

[0005] To overcome the aforementioned deficiencies of the prior art, embodiments of the present invention provide a method for coordinated inertia control of a distribution network source-storage integrated system based on frequency dynamic zoning. This method combines active power disturbance with dual safety constraints to adaptively tune the inertia setpoint of multi-source assets and calculate the duration in advance. It also precisely blocks the converter differential control channel at the lowest frequency extreme point in transient mode. This addresses the technical problems of inaccurate inertia configuration due to single constraint evaluation in traditional frequency regulation strategies, excessive asset wear and unsustainable support due to the lack of coordination mechanism among multi-source heterogeneous units, and the reverse active power absorption caused by the lag in differential transient response during the frequency recovery period, which leads to a secondary frequency drop.

[0006] To achieve the above objectives, the present invention provides the following technical solution: A method for coordinated inertia control of a power distribution network source-storage joint system based on frequency dynamic zoning includes the following steps: monitoring frequency disturbances in the power distribution network and calculating active power disturbances; The minimum inertia requirement is obtained based on the active power disturbance; the minimum inertia requirement and the active power disturbance are combined to determine the combination of participating equipment and the inertia setting value of each equipment; the equivalent total inertia of the system is calculated based on the inertia setting value and the inertia response duration is solved; each equipment is controlled to perform a phased response, and its differential control channel is locked when the disturbance duration reaches the inertia response duration.

[0007] The present invention provides a method for coordinated inertia control of a power distribution network source-storage integrated system based on dynamic frequency zoning, which has the following technical effects and advantages: This invention achieves precise quantitative assessment of the grid's overall minimum inertia requirement by real-time monitoring of frequency disturbances and reverse calculation of active power disturbances. This overcomes the technical obstacle of inaccurate inertia configuration caused by single-dimensional assessment in traditional frequency regulation strategies. By combining active power disturbances and inertia requirements to adaptively select equipment combinations participating in frequency regulation and dynamically adjust their inertia setpoints, it drives traditional rotating units and distributed energy storage assets to perform orderly, phased frequency regulation responses. This effectively solves the technical pain points of frequent resource wear and tear under small disturbances and severe insufficient support continuity under large disturbances caused by the lack of coordination mechanisms among heterogeneous units. Based on this, the invention uses real-time calculation of the system's equivalent total inertia to predict and solve for the theoretical inertia response duration required for the frequency to drop to the extreme point. At the instant the disturbance duration reaches this critical node, it precisely triggers the dynamic blocking of the differential control channel in the distributed energy storage control loop. This completely blocks the reverse active power absorption caused by the response lag of the differential link during the frequency recovery period from the perspective of loop transient characteristics, successfully eliminating the negative effects of frequency regulation and preventing the risk of secondary drops and underdamped oscillations during the frequency recovery phase.

[0008] Simulation results demonstrate that, under the combined effect of dual security constraint assessment, dynamic zoning and timing coordination of energy source and storage assets, and a forward-looking and precise blocking differential channel control mechanism, the transient frequency characteristics of the distribution network during sudden active power deficit disturbances are fundamentally improved. Compared to the traditional synchronous machine-supported operating condition, the transient frequency drop amplitude is reduced by more than 35%, RoCoF is reduced by more than 40%, and the frequency steady-state recovery time is significantly shortened by more than 35%. This scheme eliminates the hidden danger of reverse frequency regulation power backflow during the recovery period, maximizes the energy utilization efficiency of multi-heterogeneous energy source and storage frequency regulation, effectively avoids excessive operating losses of energy storage equipment, and has a significant technical driving effect on extending the operational benefits of its assets throughout their entire life cycle. Attached Figure Description

[0009] Figure 1 This is a schematic diagram of the inertia coordinated control method of a distribution network source-storage joint system based on frequency dynamic zoning provided in an embodiment of the present invention; Figure 2 This is a schematic diagram of the joint system frequency response model provided in an embodiment of the present invention; Figure 3 The waveform diagram of the response of the synchronizing machine participating in inertia support provided in the embodiment of the present invention; Figure 4 The photovoltaic system and energy storage system provided in the embodiments of the present invention do not participate in the inertia support response waveform diagram; Figure 5 The waveform diagram of the synchronous machine and photovoltaic system participating in inertia support provided in the embodiments of the present invention; Figure 6 The photovoltaic system participating in inertia support response waveform diagram provided in the embodiments of the present invention; Figure 7 The waveform diagrams of the inertia support participation of the synchronizing machine, photovoltaic system and energy storage system provided in the embodiments of the present invention are shown. Figure 8 Frequency response curves of a synchronous machine, a photovoltaic system, and an energy storage system provided in embodiments of the present invention; Figure 9 The photovoltaic system and energy storage system sequentially participate in the inertia support response waveform diagram provided in the embodiments of the present invention; Figure 10 This is a block diagram of an inertia coordinated control system for a power distribution network source-storage integrated system based on frequency dynamic zoning, provided in an embodiment of the present invention. Detailed Implementation

[0010] 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 of ordinary skill in the art without creative effort are within the scope of protection of the present invention.

[0011] Example 1, Figure 1 The present invention provides a method for coordinated inertia control of a power distribution network source-storage integrated system based on frequency dynamic zoning, comprising the following steps: S1 monitors frequency disturbances in the distribution network and calculates active power disturbances.

[0012] In this embodiment, the bus voltage frequency signal at the distribution network connection point is first acquired. Specifically, the voltage waveform can be captured in real time and the current fundamental frequency value can be calculated through a phase-locked loop circuit at the grid connection point or a microprocessor timer interrupt. Based on this, the bus voltage frequency signal is used... Further calculate the current rate of change of frequency. and frequency deviation Specifically, this involves: converting the bus voltage frequency signal... The current frequency deviation is obtained by taking the absolute value of the difference between the current frequency and the preset system rated frequency. Simultaneously, by analyzing the bus voltage frequency signal in adjacent sampling periods... The difference is then differentiated in the time domain to calculate the current rate of change of frequency. In the real-time monitoring cycle, the control chip will measure the absolute value of the frequency change rate. The frequency perturbation trigger threshold is compared online. When the absolute value of the frequency change rate is detected, the comparison is performed. When the set threshold is exceeded, a frequency disturbance event is determined to have occurred, and the start time of the disturbance is recorded. .

[0013] To suppress false triggering caused by measurement noise, grid-side harmonics, or transient load fluctuations, a time-domain window filtering buffer mechanism is introduced. Specifically, a sliding window with a length of 3 to 5 sampling periods is set. Only when the absolute value of the frequency change rate corresponding to all sampling points within the sliding window continuously exceeds a set threshold (typically 0.05 Hz / s) is a genuine frequency disturbance event confirmed, and the starting boundary of the sliding window is locked as the disturbance initiation time. .

[0014] After confirming the occurrence of a frequency disturbance event, in order to accurately quantify and assess the magnitude of the power imbalance causing the frequency drop, it is necessary to back-calculate the current disturbance power based on the initial frequency response equation of the disturbance. In the initial transient process of the disturbance (i.e. In an instant, due to the sampling delay at a microscale in the internal control loop and the electromagnetic response delay of the inverter physical group, the active power support actively provided by the distributed photovoltaic and energy storage systems within the distribution network has not yet been substantially output. That is, at this moment, the participation ratio of the dynamic virtual inertia responses of both the energy storage and photovoltaic systems is at an initial zero state. Under this initial boundary condition of the step response, the active power imbalance of the entire network is passively supported entirely by the inherent reference inertia determined by the existing physical architecture of the distribution network. To satisfy the closure and uniqueness of the control variable definitions throughout this paper, a unified standard superposition calculation formula for the equivalent total inertia of the system is introduced. The equivalent total inertia of the system The standard superposition calculation formula is as follows: (1) In the formula, The equivalent total inertial time constant of the system is expressed in seconds (s). is the inherent inertia constant of the synchronous generator, expressed in seconds (s). The equivalent inertial time constant of the synchronous generator, in seconds (s), is calculated to account for photovoltaic penetration and satisfies the following relationship. ,in The rated inertial time constant of the synchronous machine without considering photovoltaic penetration rate; The virtual inertia reference value introduced for the virtual synchronous machine control of the photovoltaic inverter, in seconds (s); Photovoltaic penetration rate, dimensionless; The virtual inertia reference value introduced for variable droop inertia control of energy storage system, in seconds (s). The energy storage inertial response participation factor is dimensionless and ranges from 0 to 1. The equivalent additional inertia reference value introduced in the control loop of the photovoltaic system, in seconds (s); is the photovoltaic inertial response participation factor, which is dimensionless and ranges from 0 to 1.

[0015] At the start of the disturbance Due to the time delay boundary limitations of the aforementioned control loop, the participation ratio of the virtual inertial response of the energy storage system is limited. and the proportion of virtual inertial response participation of photovoltaic systems All are in a zero state that has not yet been triggered, specifically satisfying the following conditions: , The initial boundary conditions are then substituted into the standard superposition calculation formula to decouple and extract the transient reference inertia value of the distribution network at this time, which is numerically simplified to the inherent inertia constant of the synchronous generator. Equivalent inertial time constant of synchronous generator after taking photovoltaic penetration rate into account The sum. In the specific reverse calculation of the current active power disturbance. At that time, the simplified reference inertia value under the initial boundary conditions is substituted as a known parameter into the calculation. Specifically, the instantaneous inertia value is multiplied by a coefficient of negative two, and then compared with the recorded frequency disturbance start time. The measured values ​​of the rate of change of frequency are multiplied together.

[0016] The active power disturbance The calculation formula is as follows: (2) In the formula, This represents the current active power disturbance, expressed in per-unit (pu). Take the standard superposition calculation formula at the initial transient moment The reference inertia value under boundary conditions, in seconds (s); To record the start time of the frequency disturbance The measured value of the frequency change rate is given in Hertz per second (Hz / s). Through the aforementioned calculation formula, the decoupled calculation of the external active power deficit impact magnitude and the internal active control power is achieved at the physical level, providing independently deterministic basic input data for calculating the ideal target inertia requirement in subsequent steps.

[0017] S2, obtain the comprehensive minimum inertia requirement based on the active power disturbance.

[0018] In this embodiment, obtaining the comprehensive minimum inertia requirement based on the active power disturbance includes: establishing a set of equations relating frequency deviation and power disturbance; calculating a first minimum inertia requirement based on the frequency change rate constraint and the active power disturbance; calculating a second minimum inertia requirement based on the frequency deviation constraint and the set of equations relating frequency deviation and power disturbance; and comparing the first minimum inertia requirement and the second minimum inertia requirement, and determining the larger of the two as the comprehensive minimum inertia requirement.

[0019] Furthermore, the set of equations relating frequency deviation and power disturbance includes a first mapping equation and a second mapping equation that are predetermined; the first mapping equation and the second mapping equation are constructed by prefitting the time-domain frequency response analytical expression under the maximum allowable frequency deviation corresponding to the frequency deviation constraint.

[0020] Specifically, the minimum inertia requirement is first calculated based on the system minimum inertia requirement assessment dimension constrained by the frequency change rate, and the first minimum inertia requirement is calculated based on the active power disturbance. In the initial stage of frequency disturbance, the system imbalance power mainly comes from the calculated active power disturbance. According to the rotor motion equation, the dynamic slope of the frequency drop across the entire network is completely dominated by the passive fundamental inertia such as the physical rotor kinetic energy. By limiting the maximum permissible slope boundary, the first minimum inertia requirement that meets the first-order safety constraint can be directly calculated.

[0021] The formula for calculating the first minimum inertia requirement is as follows: (3) In the formula, The minimum inertial time constant of the system based on the frequency change rate constraint is expressed in seconds (s). This represents the active power disturbance, expressed in per-unit (pu). This is the maximum permissible rate of frequency change, expressed in Hz / s, and is determined by the power grid frequency safety regulations. Specifically, it is usually taken as 0.05 Hz / s to 0.5 Hz / s in relevant standards. Subsequently, the minimum inertia requirement of the system is calculated based on the frequency deviation constraint, and the second minimum inertia requirement is calculated according to the active power disturbance. During the dynamic transition process following the initial disturbance, the maximum permissible frequency deviation of the system... Compared with the current steady-state photovoltaic penetration rate of the power distribution network The active power disturbance Equivalent total inertia of the system The amplitude is closely related to multiple factors, including synchronous generator parameters. To accurately assess the amplitude safety boundary and establish a clear theoretical mathematical mapping, the time-domain frequency response analytical expression constructed in subsequent steps is constrained by boundary conditions regarding the lowest drop extreme point. Specifically, when the frequency deviation... To reach the maximum permissible frequency deviation And time variable The duration of the inertial response is reached Then, the implicit function mapping characteristic relationship between disturbance and inertia requirement can be derived, and the first type of function under frequency deviation constraint can be constructed respectively. (First mapping equation) and second type of function (Second mapping equation). Wherein, the first type of function is used respectively. The system inertial requirements when the frequency deviation reaches the maximum allowable value are obtained. and using the second type of function The reference value of the active power disturbance of the system is obtained. The second minimum inertia requirement is obtained by solving the pre-constructed set of equations relating frequency deviation and power disturbance, which are input into the maximum allowable frequency deviation and the active power disturbance. The specific calculation formulas for the coupling relationship equations between frequency deviation and power disturbance are as follows: (4) In the formula, The minimum inertial time constant of the system based on frequency deviation constraints is expressed in seconds (s). This is the maximum permissible frequency deviation of the system, expressed in Hz, and is determined by frequency safety regulations. It is typically taken as ±0.2 Hz in relevant standards. It is a first-class function describing the coupling relationship between system frequency deviation and power disturbance, and describes the mapping relationship for solving the minimum inertia of the system under a given maximum frequency deviation and power disturbance. This is a second-class function describing the coupling relationship between system frequency deviation and power disturbance, and it describes the mapping relationship for back-deriving the disturbance reference power given the maximum frequency deviation and the minimum system inertia.

[0022] The steps for constructing the implicit function equation system are as follows: A multi-scenario, fully dynamic simulation model of a high-order distributed source-storage integrated system is pre-constructed offline. Under various preset photovoltaic penetration rates and distributed unit capacity configurations, active power disturbances of different magnitudes are applied in a stepwise manner, and the lowest extreme point of the system frequency response is recorded to obtain a dynamic boundary sample dataset. A multivariate nonlinear regression fitting algorithm is used to perform polynomial surface fitting on the sample dataset to obtain the surface algebraic equation, or the sample dataset is constructed as a multidimensional offline numerical retrieval matrix and pre-stored in the microcontroller's memory. When the power grid is operating online and a frequency disturbance event is detected, the solution unit will use the pre-set dynamic boundary sample dataset... With the real-time calculation of the As the input index value, the determined second minimum inertia requirement is calculated by performing multidimensional interpolation lookup calculations in the numerical retrieval matrix or by directly calling the polynomial-fitted surface equation. The value.

[0023] After obtaining the independent evaluation results of the two dimensions mentioned above, in order to simultaneously satisfy the frequency change rate constraint and the frequency deviation constraint, and to ensure that the system meets the inertia support requirements under any type of frequency safety constraint, the maximum value selection and numerical comparison logic is executed. That is, the first minimum inertia requirement and the second minimum inertia requirement are compared, and the larger value of the two is determined as the comprehensive minimum inertia requirement of the system.

[0024] The formula for calculating the overall minimum inertia requirement of the system is as follows: (5) In the formula, The value of the system's comprehensive minimum inertia requirement is taken as the final evaluation result to ensure that the system meets the requirements under both types of frequency security constraints.

[0025] By using the maximum value selection operation, the safety hazards or resource waste caused by single constraint evaluation can be avoided. The equivalent inertia baseline value that the distribution network can safely bear and smoothly transition under the current specific active power impact is locked, thereby providing a precise quantitative control benchmark for subsequent multi-asset dynamic zoning allocation.

[0026] S3, combining the comprehensive minimum inertia requirement and the active power disturbance, determines the inertia setting value of the participating equipment combination and each equipment.

[0027] In this embodiment, determining the inertia setting value of the participating equipment combination and each equipment includes: If the active power disturbance is less than or equal to the first critical value If the current disturbance is determined to be a small disturbance range, the participating equipment combination is determined to include only the synchronous generator, and the inertia setting value of the synchronous generator is set to the maximum value, and the inertia participation coefficients of the photovoltaic inverter and the energy storage system are both set to zero. If the active power disturbance is greater than the first critical value And less than or equal to the second critical value If the current disturbance is determined to be in the medium disturbance range, the participating equipment combination is determined to include a synchronous generator and a photovoltaic inverter, and the inertia setting value of the synchronous generator and the virtual inertia setting value of the photovoltaic inverter are both set to the maximum value, the inertia participation coefficient of the energy storage system is set to zero, and the inertia participation coefficient of the photovoltaic inverter is set to be greater than zero. If the active power disturbance is greater than the second critical value If the current disturbance is determined to be a large disturbance range, the participating equipment combination is determined to include a synchronous generator, a photovoltaic inverter, and an energy storage system, and the virtual inertia setting values ​​of the synchronous generator, the photovoltaic inverter, and the energy storage system are all set to the maximum value, and the inertia participation coefficients of the energy storage system and the photovoltaic inverter are all set to be greater than zero.

[0028] The following is a detailed explanation of the specific implementation details of S3: Specifically, after obtaining the current active power disturbance through the aforementioned steps... Subsequently, in order to provide a clear hierarchical control boundary for the power distribution network's source-storage integrated active power coordination circuit, and to avoid frequent operation of inverter-type frequency regulation equipment under small impacts causing active power loss, or insufficient support capacity under large impacts leading to system instability, the control unit calls the comparator circuit online to convert the real-time calculated active power disturbance into a signal. With the first threshold value stored in the register Second critical value Real-time size comparisons are performed to determine the current disturbance's level range. The control mechanism of the dynamic zoning lies in activating the multi-source active power defense regulation chain within the distribution network as needed, based on the severity of the power imbalance deficit across the entire network, and adaptively adjusting the virtual inertia constants of various devices.

[0029] For the small disturbance range, when the active power disturbance is less than or equal to the first critical value... When the first critical value is determined based on the statistical law of historical normal load disturbance, usually 0.05 pu), it indicates that the disturbance is small and the inherent physical inertia of the synchronous generator is sufficient to meet the minimum inertia requirement of the system, and the photovoltaic storage equipment does not participate. At this time, a passive support command is directly issued to determine that the participating equipment combination only includes the synchronous generator, and the inertia setting value of the synchronous generator is directly set to the maximum value (specifically, the synchronous generator inertia setting value is set to the maximum value). Let's assume the maximum value of the inherent inertia constant that a synchronous generator can provide. This fully leverages the passive response capability of the rotor's rotational kinetic energy in traditional frequency regulation units, while the control logic automatically sets the inertia participation coefficients of both the photovoltaic inverter and the energy storage system to zero. and This causes the virtual inertia supplementary control loop of the distributed new energy grid-side inverter to be in a closed and unresponsive state.

[0030] For the medium disturbance range, when the active power disturbance is greater than the first critical value... And less than or equal to the second critical value When the second critical value is determined based on the distribution network's safe voltage operating limit and active power regulation dead zone, typically set to 0.15 pu, it indicates that the synchronous generator's inherent inertia is insufficient under moderate disturbances, requiring the photovoltaic inverter to provide additional virtual inertia through VSG control to support the synchronous generator. In this case, the participating equipment combination is determined to include both the synchronous generator and the photovoltaic inverter. To quickly release the inertia response potential of local distributed photovoltaic power, the inertia setpoint of the synchronous generator and the virtual inertia setpoint of the photovoltaic inverter are both set to their maximum values. Specifically, the values ​​are set as follows: And set the photovoltaic virtual inertia setting value. Maximum permissible virtual inertia of photovoltaic system Under this operating condition, since the energy storage system converter still does not need to be switched on, the inertia participation factor of the energy storage system is set to zero, i.e. In order to quantitatively compensate for the minimum inertial time constant of the system at this point... The algebraic difference between the inertia of the photovoltaic inverter and the basic inertia of the synchronous machine requires setting the inertia participation factor of the photovoltaic inverter to be greater than zero.

[0031] To ensure the engineering feasibility of determining the photovoltaic participation factor in the moderate disturbance range and to guarantee sufficient disclosure in the specification, the inertia participation factor of the photovoltaic inverter is given here. The specific quantification steps are as follows: The calculation unit evaluates and obtains the system's comprehensive minimum inertial time constant based on the aforementioned step S2. Subtract the current synchronous generator's inherent inertia constant. Equivalent inertial time constant of synchronous generator after taking photovoltaic penetration rate into account Then, the grid-side inertia demand deficit of the distribution network is obtained, and this net inertia demand deficit is divided by the constant product corresponding to the maximum additional inertia support capacity that the current photovoltaic system can provide, thereby calculating the coefficient value that accurately meets the current safety lower limit online. The inertia participation factor of the photovoltaic inverter The calculation formula is as follows: (6) In the formula, The photovoltaic inertial response participation factor is dimensionless. The obtained system-wide minimum inertial time constant is used for evaluation, and the unit is seconds (s). is the inherent inertia constant of the synchronous generator, expressed in seconds (s). The equivalent inertial time constant of the synchronous generator after taking into account photovoltaic penetration rate is expressed in seconds (s). The virtual inertia introduced for the virtual synchronous machine control of the photovoltaic inverter, in seconds (s); Photovoltaic penetration rate, dimensionless; This refers to the equivalent additional inertia introduced into the control loop of the photovoltaic system, expressed in seconds (s). If, during the calculation process, the obtained... If the online calculation result is greater than 1, it will be forcibly limited to 1, at which point the photovoltaic system will output the maximum active inertia.

[0032] For large disturbance ranges, when the active power disturbance is greater than the second critical value... The determination condition indicates a sudden and severe active power deficit shock, resulting in a significant system inertia deficit. This necessitates the involvement of an energy storage system, which, together with the photovoltaic inverter and synchronous generator, provides full-scale inertia support. In this case, the participating equipment combination is determined to include the synchronous generator, photovoltaic inverter, and energy storage system. To mobilize all grid-connected and available frequency regulation assets across the entire network, the virtual inertia setpoints for the synchronous generator, photovoltaic inverter, and energy storage system are set to their maximum values. Specifically, the synchronous generator inertia setpoint is set to its maximum value. Let's assume the maximum value of the inherent inertia constant that a synchronous generator can provide. Set the virtual inertia value of photovoltaic Set as the maximum allowable virtual inertia of the photovoltaic system And set the virtual inertia value for energy storage. Set as the maximum allowable virtual inertia of the energy storage system Under this extreme disturbance condition, the inertia participation factors of both the energy storage system and the photovoltaic inverter must be greater than zero, i.e., satisfy the following condition. and The coefficient boundary requirements are met to achieve coordinated compensation of active power in multi-source networks. To ensure the allocation mechanism of participation coefficients for independent devices under large disturbance ranges is fully disclosed and compileable for engineering applications, the collaborative matching relationship between the two participation coefficients and the specific proportional allocation calculation steps are defined here. Specifically: considering that the variable droop inertia control used in the energy storage converter has the advantage of millisecond-level fast active power throughput, while the VSG control used in the photovoltaic inverter has better continuous stability characteristics on a medium- to long-term second-level scale, the control unit introduces a time-priority strategy when allocating coefficients, thereby realizing a dynamic hierarchical allocation mechanism for inertia resources that adaptively adjusts according to the disturbance magnitude. In the specific allocation calculation, the photovoltaic inertia response participation coefficient is given priority. The maximum saturation value of 1 is locked, so that the active power additional regulation loop of the local distributed photovoltaic system is fully activated. Then, the remaining total rigid inertia deficit of the system is completely supplemented by the energy storage action loop with adaptive amplitude capability. The inertia participation factor of the energy storage system The calculation formula is as follows: (7) If during the calculation process, the obtained If the online calculation result is greater than 1, it will be truncated to 1. At this time, the virtual inertia reserves of the power source and storage system in the distribution network are all in full-load output state.

[0033] Through the aforementioned clear interval determination rules and corresponding closed-loop calculation formulas for equipment participation coefficients, the orderly integration of distributed energy resources and traditional generator impedance frequency modulation resources under different power impact depths is realized, providing a deterministic parameter basis for the accurate inertial response duration calculation and phased virtual control output in subsequent steps.

[0034] S4. Calculate the equivalent total inertia of the system based on the inertia setpoint and solve for the inertia response duration.

[0035] In this embodiment, the step of calculating the equivalent total inertia of the system based on the inertia setpoint and solving for the inertia response duration includes: calculating the equivalent total inertia of the system based on the inertia setpoint of each device and a predetermined virtual inertia response participation ratio; constructing a time-domain frequency response analytical expression based on the equivalent total inertia of the system, the turbine inertia time constant, the power-frequency static error ratio, the system damping degree, and the load regulation rate; and using the extremum condition that the first derivative of the time-domain frequency response analytical expression with respect to the time variable is zero, solving for the time required for the frequency to drop to the minimum value, and determining the time as the inertia response duration. The equivalent total inertia of the system... The calculation formula is shown in equation (1).

[0036] The specific implementation details of S4 are described below: Specifically, after determining the power disturbance level range and adaptively outputting the inertia setpoint and coefficient matrix of each power supply device through the aforementioned step S3, the control unit executes step S4. The control center dynamically maps the parameters of each grid-connected unit and calculates the equivalent total inertia of the system based on the inertia setpoint of each device and the predetermined virtual inertia response participation ratio. The equivalent total inertia of the system. It embodies the real-time sum of the physical basis rotor kinetic energy provided by the traditional rotating synchronous unit inside the system, as well as the various virtual active power support capabilities released by the distributed multi-source inverter control link. It serves as the core dynamic variable characterizing the transient frequency regulation impedance of the distribution network. After completing the current description After calculation, in order to eliminate the potential risks of frequency modulation power backflow and system oscillation caused by conventional differential control under frequency recovery conditions, the control unit needs to utilize the calculated... The frequency inflection point during the dynamic drop process can be calculated online, thereby solving for the duration of the inertial response.

[0037] Specifically, based on the system's equivalent total inertia, turbine inertial time constant, power-frequency static error ratio, system damping, and load regulation rate, a time-domain frequency response analytical expression is constructed. Furthermore, by establishing a system state-space equation incorporating photovoltaic penetration, energy storage configuration, and the combined frequency regulation performance of synchronous generators, a time-domain frequency response analytical expression characterizing the trajectory of the entire network's structural features is derived through an inverse Laplace transform. The specific calculation formulas for the complex frequency domain transient frequency response equation set are as follows: (8) In the formula, For the Laplace operator; This refers to the system frequency deviation in the complex frequency domain. This represents the increment of the turbine's mechanical active power output in the complex frequency domain; The step active power disturbance in the complex frequency domain is specifically expressed as follows: , is the inertial time constant of the steam turbine, in seconds (s); This is the power share coefficient of the intermediate-pressure cylinder, which is dimensionless. The static frequency difference ratio of the synchronous generator speed governor is dimensionless. The system damping is dimensionless. The load regulation rate is dimensionless. The system of equations is subjected to simultaneous algebraic elimination and rewritten as the characteristic polynomial of a standard second-order underdamped oscillation system, thus obtaining the Laplace domain closed-loop transfer function. Substituting this into the complex frequency domain step disturbance and performing an inverse Laplace transform, the analytical expression of the entire network's time-domain frequency response is constructed.

[0038] The time-domain frequency response analytical expression The specific calculation formula is as follows: (9) In the formula, This is the current time-domain frequency deviation analytical value that evolves continuously over time in a transient manner, in Hertz (Hz). The time domain variable after the disturbance occurs, in seconds (s); This represents the active power disturbance, expressed in per-unit (pu). is the base of the natural logarithm; It is a sine function; This is the system's inherent frequency parameter, expressed in radians per second (rad / s). The system damping ratio is dimensionless. To dampen the oscillation frequency, the unit is radians per second (rad / s). The initial phase angle depends on the initial boundary characteristic constants of the system, and is expressed in radians (rad).

[0039] Based on this, using the extremum condition that the first derivative of the time-domain frequency response analytical expression with respect to the time variable is zero, the time required for the frequency to drop to its minimum value is calculated, and this time is determined as the duration of the inertial response. Specifically: by order The physical extreme zero-slope boundary condition is used to demodulate the deterministic time span required for the frequency to drop from the disturbance moment to the minimum point. The duration of the inertial response The calculation formula is as follows: (10) In the formula, Take a value determined by time, which is the frequency from the time of the disturbance. The duration of the drop to the lowest value, i.e., the inertial response time, is measured in seconds (s). To ensure that the duration value can converge online in real time within the microprocessor control chip, the inherent dynamic characteristic variables of each intermediate system involved in the calculation formula are specifically derived from the equivalent total inertia of the system. And the existing physical structure parameters of the unit are explicitly analyzed and expanded. Specifically, the inherent frequency parameters of the system are... The calculation formula is as follows: (11) The system damping ratio The calculation formula is as follows: (12) The damped oscillation frequency The calculation formula is as follows: (13) By constructing the aforementioned multi-order dynamic explicit functional equation system, the solution unit, after capturing external active power disturbances, can directly call the system network structure constants preset in the registers and obtain the solution through real-time dynamic adaptive superposition. Perform multiplication and division operations to directly output deterministic time reference line values. This step utilizes the system's equivalent total inertia, obtained through real-time adaptive superposition of multi-source network structural parameters, to perform multi-order dynamic explicit function mapping. It constructs the analytical equation for the entire network's time-domain frequency response and directly solves the algebraic expression for the frequency drop extreme inflection point. This overcomes the technical obstacle of traditional control methods that rely solely on local frequency measurement filtering to capture the frequency inflection point, which leads to delayed virtual inertia differential control withdrawal or reverse false triggering due to measurement noise, ripple interference, and hardware physical filtering delays. This achieves accurate prediction of the frequency drop to its extreme value, providing a precise time reference for subsequent lockout control. It effectively avoids reverse power absorption during the frequency recovery phase of differential control, eliminating the risk of secondary frequency drops.

[0040] S5 controls each device to perform a phased response, and locks its differential control channel when the disturbance duration reaches the inertial response duration.

[0041] After completing the aforementioned steps to determine the system's equivalent total inertia Quantization superposition calculation and inertial response duration After accurate prediction, the control unit executes S5 to control each device to perform a phased response, and locks its differential control channel when the disturbance duration reaches the inertial response duration.

[0042] Specifically, the control of each device to execute a phased response is as follows: In the first stage of control, if the active power disturbance is determined to be in the large disturbance range in step S3, i.e., the participating equipment combination includes an energy storage system, then the energy storage system is controlled to respond using variable droop inertia control. Specifically, after detecting the frequency deviation, the local control chip of the energy storage converter automatically increases the virtual inertia coefficient within milliseconds. To quickly release active power and suppress the system frequency change rate, thus mitigating the initial downward trend of the system frequency. After the energy storage system responds, the second stage of control begins. If the participating equipment combination includes a photovoltaic inverter (i.e., currently in a medium or large disturbance range), the photovoltaic inverter is controlled to switch to virtual synchronous machine control mode. Specifically, the virtual synchronous machine dynamic adjustment loop inside the distributed photovoltaic converter is activated to increase the photovoltaic active power output to take over the inertia support task of the energy storage system, and the power output of the energy storage system is controlled to smoothly decline, thereby achieving a smooth and orderly handover of frequency regulation resources across the entire network on both fast and slow time scales. As the frequency fluctuation gradually subsides, the third stage of control begins. The synchronous generator is controlled to perform primary frequency regulation through the speed governor to maintain the long-term power balance of the system, relying on the mechanical rotating unit to provide basic rigid power regulation. At the same time, the photovoltaic inverter is controlled to maintain power compensation in virtual synchronous machine steady-state mode, outputting a small amount of continuous active power, thereby maintaining voltage and frequency support for the entire network's electromagnetic transients.

[0043] While the multi-source collaborative phased control response is being executed, the timer component inside the control chip starts recording the frequency disturbance from the initial time. Start high-frequency online timing and calculate the current time in real time. With the Time difference in the time domain The time difference is compared with the inertial response duration obtained analytically in step S4. Perform numerical comparisons. And when the disturbance duration reaches the inertial response duration, i.e., when the current relationship is satisfied... When the time-triggered boundary condition is met, it is determined that the system frequency drop waveform has just reached the theoretical minimum extreme point. At this moment, the control chip immediately issues a digital cutoff command to the local drive layer of the photovoltaic inverter and energy storage system, blocking their differential control channels; specifically, it shuts down the additional differential active power adjustment gain channel in the photovoltaic-energy storage inverter control loop that takes into account the rate of frequency change, forcibly truncating and clearing its differential control coefficient to zero. By instantaneously blocking the differential control term at the extreme point, the step response of the control loop to the reversal of the rate of frequency change direction can be cut off from the control physical mechanism.

[0044] Furthermore, after executing the locking of its differential control channel, a smooth reset process for the system control mode is also included.

[0045] Specifically, under the primary frequency regulation of the grid-side units, the system frequency gradually rises and approaches the rated value, and the numerical calculation unit calculates the current frequency deviation in real time. The absolute value and the rate of change of frequency The absolute value of the frequency deviation. When the system frequency deviation is less than a preset first threshold and the absolute value of the frequency change rate is less than a preset second threshold, specifically, it satisfies the judgment formula. And satisfy the judgment expression The steady-state termination condition is used to determine whether the system has entered the steady-state control phase; wherein, the frequency deviation threshold is... The frequency change rate regression threshold is typically set to 0.033 Hz. The setting is 0.01 Hz / s. At this time, the control chip issues a global system state reset command, controlling the energy storage system to exit inertia support and enter charging mode, causing it to exit the aforementioned variable droop inertia support active power output. Under the guidance of the energy dispatch strategy, it replenishes the battery's power reserve by recovering surplus energy from the grid side. Simultaneously, it controls the photovoltaic inverter to return to maximum power point tracking mode, shuts off the virtual synchronous machine frequency regulation operation loop, and returns to the optimal active power output condition of maximum power point tracking to improve the efficiency of new energy power generation. It also controls the synchronous generator to maintain stable output, driving the speed governor system to lock at the current steady-state frequency regulation power line. After completing the above reset actions, the control status of all source and storage assets in the entire network is reinitialized, and the system returns to the real-time cyclic monitoring state of the aforementioned step S1 to wait for the next sudden frequency disturbance event.

[0046] This step introduces a three-level dynamic time-series allocation system: "millisecond-level rapid response to energy storage droop, second-level smooth succession of photovoltaic virtual synchronous machine, and long-term maintenance of primary frequency regulation by synchronous generator." Combined with transient digital interlocking based on analytical response time guided by a time-domain model, this addresses the technical obstacles in traditional control schemes. These obstacles include the lack of fine-grained timing coordination between photovoltaic and energy storage devices, leading to low energy utilization efficiency. Furthermore, it addresses the issue of differential inertia control failing to promptly withdraw during the frequency recovery phase (when the rate of frequency change is greater than zero) due to response lag and measurement noise interference, resulting in reverse frequency regulation power backflow and causing secondary frequency drops or over-regulation oscillations in the system. This achieves adaptive and coordinated supplementation of multi-source active power resources across micro, meso, and macro time scales, effectively eliminating secondary frequency drops during the frequency recovery phase, reducing unnecessary energy consumption in energy storage, extending the lifespan of energy storage assets, and significantly improving the stability of distribution network frequency recovery.

[0047] Example 2, Simulation Experiment Verification: This embodiment is used to conduct simulation experiments to verify the inertia coordinated control method of the distribution network source-storage joint system based on frequency dynamic partitioning as detailed in Embodiment 1 above, so as to quantitatively demonstrate its technical effects in improving grid frequency stability, reducing RoCoF, and eliminating secondary drops during the frequency recovery phase.

[0048] To ensure the objectivity and scientific validity of the verification results, the simulation experiment is based on Figure 2 The frequency response model of the integrated power grid energy storage system is shown in the diagram. This integrated system frequency response model integrates the energy storage system, photovoltaic system, governor and turbine components of the synchronous generator set, power-frequency scaling factor (the reciprocal of photovoltaic penetration rate), system inertia and damping components, and a load regulation rate feedback channel considering the frequency conversion characteristics of the entire network load. In this simulation model, the active power output increment of the additional control component of the energy storage system is defined as the active power support power of the energy storage system. The active power output increment of the additional control link in a distributed photovoltaic system is defined as the photovoltaic active power support. Both are introduced into the frequency response loop as active power injection terms for high dynamic active frequency regulation. The base rated frequency of the distribution network system is set to 50 Hz. The photovoltaic penetration rate of the system... The setting is 35%. The baseline physical and control parameters for each frequency modulation asset and network in the joint system are preset as follows: turbine inertial time constant. intermediate pressure cylinder power share coefficient The inherent inertia constant of a synchronous generator Speed ​​controller power frequency static error ratio System damping Load regulation rate Set it to 1.5.

[0049] During simulation runtime At that time, the system puts in variable load 2, which suddenly generates an active power deficit disturbance, thus injecting active power disturbance into the distribution network. The introduction of the disturbance caused the system frequency to drop rapidly. The control chip then monitored the bus voltage frequency signal at the grid connection point at a high frequency with a millisecond-level sampling rate. And based on step S1, the precise power disturbance is calculated. .

[0050] To quantitatively compare and analyze the substantial technical advantages of the control method proposed in this invention, simulation experiments were conducted with three different control scenarios for closed-loop verification: Scenario 1: Only synchronous generator sets participate in inertia support. In this scenario, neither the distributed photovoltaic system nor the energy storage system within the distribution network activates any virtual inertia control channels (i.e., they operate in a conventional grid-connected mode, and their active power output does not dynamically adjust with changes in system frequency, thus satisfying the requirement). and The frequency deviation of the entire network relies entirely on the physical rotor rotational inertia of traditional synchronous generators and the primary frequency regulation of the speed governor for passive adjustment. The corresponding simulation response waveform is as follows: Figure 3 and Figure 4 As shown.

[0051] Scenario 2: Synchronous generator and photovoltaic system work together. In this scenario, the distributed photovoltaic power station is equipped with a grid-type virtual synchronous generator (VSG) control strategy to provide virtual inertia, while the energy storage system remains in a static, unsupported state (i.e., the energy storage inertia response participation factor is set). And the energy storage active power support capacity When the frequency drops, the photovoltaic system actively and rapidly outputs virtual inertial power using VSG control. They work together with synchronous generators to counteract frequency fluctuations. The corresponding simulated response waveform is as follows: Figure 5 and Figure 6 As shown.

[0052] Scenario 3: Synchronous generator, photovoltaic system, and energy storage system working in tandem (i.e., the solution proposed in this invention). In this scenario, the synchronous generator, photovoltaic system, and energy storage system are all operational. Under the adaptive participation coefficient calculated in step S3, the energy storage system uses variable droop inertia control to respond and output within milliseconds. The photovoltaic system then smoothly replaces the response using the VSG mode, and reaches the inertial response duration calculated in step S4. Immediately lock the optical storage differential control channel. The corresponding simulation response waveform is as follows: Figure 7 , Figure 8 as well as Figure 9 As shown.

[0053] The transient frequency response and active power output characteristics under the above three scenarios are compared and analyzed below: Regarding scenario one, from Figure 3 and Figure 4 It can be seen that the system experienced a significant frequency drop and prolonged low-frequency oscillations after the active power imbalance disturbance. The system frequency reached its lowest point at approximately 49.81 Hz, with the initial maximum RoCoF reaching approximately 0.25 Hz / s. Due to the limited physical inertia of the rotor of a single synchronous generator and the slow time-varying characteristics of the primary frequency regulation of the speed governor, the transient fluctuation time near the lowest frequency point was long, and the overall system frequency recovery time exceeded 3.0 s. The intermediate power curve shows that the output power of the photovoltaic power station and the energy storage system remained constant throughout the process, indicating that the new energy unit was in a "static operation" state and could not participate in inertia support in a short period of time.

[0054] Regarding scenario two, from Figure 5 and Figure 6 It can be seen that after introducing a grid-connected photovoltaic system to participate in inertia support, the active power output of the photovoltaic system rapidly increases to the support peak during the instant of frequency drop, thus supplementing the distribution network with equivalent virtual inertia. Experimental results show that the lowest frequency point of the system rises to approximately 49.4 Hz, with the drop amplitude reduced by about 20% compared to scenario one; the maximum RoCoF of the system decreases to approximately 0.45 Hz / s; due to the additional damping introduced by the photovoltaic VSG control, the attenuation rate of frequency fluctuations is accelerated, and the steady-state recovery time is shortened to approximately 2.5 s. This verifies the positive role of the virtual inertia support of the grid-connected photovoltaic system in suppressing frequency drop. However, in the mid-to-late stage of continuous disturbance, limited by the active power capacity of a single regulation source, the frequency still exhibits small transient oscillations, and there is a certain power response lag.

[0055] Regarding scenario three, from Figure 7 and Figure 9 It can be seen that after introducing variable droop inertia control of the energy storage system and implementing phased timing coordination with photovoltaic VSG control, the dynamic frequency characteristics of the system are significantly optimized. Experimental results show that the system's lowest frequency is increased to 49.7 Hz, and its frequency drop amplitude is reduced by more than 35% compared to Case 1; the initial RoCoF of the system is reduced by more than 40% (down to about 0.3 Hz / s); due to the... At a critical moment, high-precision dynamic interlocking control was executed, cutting off the photovoltaic-storage differential control channel, thereby eliminating the secondary drop phenomenon during the frequency recovery stage. This resulted in a smooth and stable monotonic recovery curve, shortening the overall steady-state recovery time to approximately 1.8 seconds (a reduction of over 35%). Simultaneously, the power response curves of the energy storage system and the photovoltaic power station formed an adaptive complementary collaboration on the time axis: the energy storage variable droop control outputs peak active power within milliseconds to suppress RoCoF, followed by a smooth drop in active power; while the photovoltaic VSG control gradually increases output to take over support, effectively reducing the energy consumption burden of the energy storage system and improving overall energy utilization efficiency.

[0056] To further reveal the dynamic coordination mechanism of multi-source coordinated allocation and interlocking control in the time domain in the scheme of this invention. Figure 8 The following six typical timing stages of the lifetime frequency response curve under scenario three are shown. to The corresponding timing coordination logic is shown in Table 1.

[0057] Table 1

[0058] The specific timing coordination process is as follows: Initial stage ( to Phase 1: During this phase, a sudden active power deficit causes the system frequency to drop rapidly. Because the frequency deviation is still within the primary frequency regulation dead zone of the synchronous generator's governor (typically...),... Within this range, traditional rotating units have not yet switched to frequency regulation output. At this time, the new energy photovoltaic-storage power generation system quickly activates the virtual inertia compensation channel. Among them, the variable droop control of the energy storage system completes the active step injection within milliseconds, undertaking the main inertia support in the initial stage, thereby limiting RoCoF to the lowest level.

[0059] Inertia transition phase ( to (Stage 1): The system frequency drops and exceeds the primary frequency regulation dead zone. Over time, the passive rotor energy release effect corresponding to the synchronous generator rotor motion equation gradually diminishes, while the collaborative virtual inertia response of the new energy unit and energy storage system begins to fully engage. The photovoltaic converter executes VSG control output, and the energy storage transformer droop control dynamically increases the virtual inertia coefficient based on the real-time frequency deviation. This multi-source complementarity enhances the equivalent total inertia of the entire network. This slowed the downward slope towards the lowest extreme point.

[0060] Quasi-steady-state primary frequency modulation stage ( to Phase 1): During this phase, the system frequency decline gradually converges and reaches near the theoretical minimum extreme point. The high dynamic inertia release of the energy storage system gradually weakens, while the photovoltaic system takes over as the main source of second-level inertia support, continuously injecting active power for compensation. The primary frequency regulation power of the synchronous generator also begins to be substantially output, the overall damping characteristics of the system are strengthened, the active power imbalance is smoothed out, and the frequency curve enters a stable transition zone.

[0061] Frequency pole blocking stage ( transient and to Stage): When the duration of the disturbance reaches the duration of the inertial response predicted in step S4. At that time, the control unit is on the time axis The inflection point immediately triggers a latching command, shutting down the differential inertia channel of the optical storage control loop. Due to the latching mechanism... The precise positioning of the physical zero point blocked the reverse active power feedback in the control loop, thus eliminating the secondary drop phenomenon during the frequency recovery phase. Subsequently, the active power support of the entire network gradually became dominated by the primary frequency regulation of the physical speed controller, and the frequency began to rise steadily and monotonically.

[0062] Steady-state recovery transition phase ( to Phase 1): The system frequency deviation gradually recovers to within the primary frequency regulation dead zone. The frequency regulation response amplitude of the synchronous generator and each source-storage converter begins to decrease in an orderly and gradual manner proportionally. The power redistribution circuit operates smoothly, and the system frequency deviation further approaches the rated point without any underdamped oscillations or over-adjustment.

[0063] Steady-state control reset phase ( (After the initial phase): The control chip determines that the system frequency deviation and rate of change are consistently less than the preset micro-amplitude steady-state threshold, confirming that the system has returned to a safe steady state. At this point, the state reset procedure is initiated, controlling the energy storage power station to exit inertial response and smoothly transition to energy recharge mode to restore its state of charge (SOC). Simultaneously, the distributed photovoltaic inverter is controlled to smoothly exit VSG operation mode and reset to the optimal power generation condition of maximum power point tracking (MPPT) without disturbance. The entire system then re-enters the real-time cyclic monitoring state.

[0064] This embodiment addresses the technical challenges of traditional distribution networks after a high proportion of new energy sources are integrated into the network. It involves injecting a step load power disturbance into the network simulation model and quantitatively comparing the transient frequency trajectories of three scenarios: "synchronous machine only," "synchronous machine + photovoltaic VSG," and "synchronous machine + photovoltaic + energy storage phased timing coordination and dynamic blocking control." This solves the problems of severe loss of equivalent physical inertia, drastic frequency drops, and active power absorption and secondary frequency drops during the frequency recovery phase due to the inability to accurately predict the inflection point in conventional differential inertia control. The embodiment achieves comprehensive enhancement of the system's anti-disturbance capability and transient and steady-state frequency stability, resulting in significant technical effects such as increasing the system's lowest frequency point by over 35%, reducing RoCoF by over 40%, shortening recovery time by over 35%, and completely eliminating secondary frequency drops during the frequency recovery phase.

[0065] Example 3, Figure 10 A frequency-dynamic zoning-based inertia coordinated control system for a distribution network source-storage integrated system is presented, including: The frequency disturbance detection module is used to monitor frequency disturbances in the distribution network and calculate the active power disturbance. The inertia requirement assessment module is used to obtain the comprehensive minimum inertia requirement based on the active power disturbance. The dynamic partitioning module is used to determine the inertia settings of participating equipment and each piece of equipment by combining the comprehensive minimum inertia requirement and the active power disturbance. The time calculation module is used to calculate the equivalent total inertia of the system and solve for the duration of the inertia response based on the inertia setpoint. The collaborative control module is used to control each device to perform a phased response and to lock its differential control channel when the duration of the disturbance reaches the duration of the inertial response.

[0066] The above formulas are all dimensionless calculations. 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 in the formulas are set by those skilled in the art according to the actual situation.

[0067] The above embodiments can be implemented, in whole or in part, by software, hardware, firmware, or any other combination thereof. When implemented using software, the above embodiments can be implemented, in whole or in part, in the form of a computer program product.

[0068] Those skilled in the art will recognize that the modules and algorithm steps of the various examples described in conjunction with the embodiments disclosed herein can be implemented in electronic hardware, or a combination of computer software and electronic hardware. Whether these functions are implemented in hardware or software depends on the specific application and design constraints of the technical solution. Those skilled in the art can use different methods to implement the described functions for each specific application, but such implementation should not be considered beyond the scope of this application.

[0069] In addition, the functional modules in the various embodiments of this application can be integrated into one processing module, or each module can exist physically separately, or two or more modules can be integrated into one module.

[0070] The above description is merely a specific embodiment of this application, but the scope of protection of this application is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the scope of the technology disclosed in this application should be included within the scope of protection of this application. Therefore, the scope of protection of this application should be determined by the scope of the claims.

[0071] In conclusion, the above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. 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.

Claims

1. A method for coordinated inertia control of a power distribution network source-storage integrated system based on frequency dynamic zoning, characterized in that, include: Monitor frequency disturbances in the distribution network and calculate active power disturbances; The comprehensive minimum inertia requirement is obtained based on the active power disturbance. Specifically, the process involves: establishing a set of equations relating frequency deviation and power disturbance; these equations include a pre-determined first mapping equation and a second mapping equation; the first and second mapping equations are pre-fitted from the time-domain frequency response analytical expression under the maximum allowable frequency deviation corresponding to the frequency deviation constraint; based on the frequency change rate constraint and the frequency deviation constraint, a first minimum inertia requirement is calculated according to the active power disturbance, and a second minimum inertia requirement is calculated using the set of equations relating frequency deviation and power disturbance, specifically: inputting the maximum allowable frequency deviation and the real-time acquired active power disturbance into the first mapping equation, and solving for the second minimum inertia requirement; taking the larger of the first and second minimum inertia requirements as the comprehensive minimum inertia requirement; At the same time, the inertia limit values ​​of each participating device combination are input into the second mapping equation to calculate multiple disturbance reference power critical values; The multiple disturbance reference power threshold values ​​serve as interval threshold values ​​for dividing the active power disturbance quantity into level intervals. By combining the comprehensive minimum inertia requirement with the active power disturbance, the inertia setpoints of the participating equipment and each piece of equipment are determined. Calculate the equivalent total inertia of the system and solve for the inertia response duration based on the inertia setpoint. Specifically, the equivalent total inertia of the system is calculated based on the inertia setpoints of each device and the predetermined virtual inertia response participation ratio; the time-domain frequency response analytical expression is constructed based on the equivalent total inertia of the system, the turbine inertia time constant, the power-frequency static error ratio, the system damping degree, and the load regulation rate; the time required for the frequency to drop to the minimum value is solved by using the extremum condition that the first derivative of the time-domain frequency response analytical expression with respect to the time variable is zero, and the time is determined as the duration of the inertia response. Each device is controlled to perform a phased response, and its differential control channel is locked when the duration of the disturbance reaches the duration of the inertial response.

2. The method according to claim 1, characterized in that, The analytical expression for the time-domain frequency response is as follows: In the formula, This represents the current analytical value of the time-domain frequency deviation as it continuously evolves over time. For time variables in the time domain after the disturbance occurs; This represents the active power disturbance. is the base of the natural logarithm; These are the inherent frequency parameters of the system; The system damping ratio; To dampen the oscillation frequency; The initial phase angle depends on the initial boundary characteristic constants of the system; The inertial time constant of the steam turbine; The static frequency difference ratio of the synchronous generator speed governor; The system damping degree; Load regulation rate; This represents the photovoltaic penetration rate.

3. The method according to claim 1, characterized in that, The determination of the inertia settings of the participating equipment combination and each equipment includes: If the active power disturbance is less than or equal to the first critical value, the current disturbance is determined to be a small disturbance range, the participating equipment combination is determined to include only the synchronous generator, the inertia setting value of the synchronous generator is set to the maximum value, and the inertia participation coefficients of the photovoltaic inverter and the energy storage system are both set to zero. If the active power disturbance is greater than the first critical value and less than or equal to the second critical value, the current disturbance is determined to be in the medium disturbance range. The participating equipment combination is determined to include synchronous generators and photovoltaic inverters. The inertia setting value of the synchronous generator and the virtual inertia setting value of the photovoltaic inverter are both set to the maximum value. The inertia participation coefficient of the energy storage system is set to zero, and the inertia participation coefficient of the photovoltaic inverter is set to be greater than zero. If the active power disturbance is greater than the second critical value, the current disturbance is determined to be a large disturbance range. The participating equipment combination is determined to include a synchronous generator, a photovoltaic inverter, and an energy storage system. The virtual inertia settings of the synchronous generator, the photovoltaic inverter, and the energy storage system are all set to the maximum value. The inertia participation coefficients of the energy storage system and the photovoltaic inverter are both set to be greater than zero.

4. The method according to claim 1, characterized in that, The method of locking its differential control channel when the disturbance duration reaches the inertial response duration includes: When the duration of the disturbance reaches the duration of the inertial response, the additional differential adjustment gain related to the rate of change of frequency in the control loop of the photovoltaic inverter and / or energy storage system is set to zero. While locking the differential control channel, the power frequency droop control channel of the photovoltaic inverter is kept enabled to control the photovoltaic inverter to maintain active power compensation.

5. The method according to claim 1, characterized in that, The control of each device to execute a phased response includes: First-stage control: If the participating equipment combination includes an energy storage system, the energy storage system is controlled to respond using variable droop inertia control, releasing active power to suppress the system frequency change rate; Second-stage control: After the energy storage system responds, if the participating equipment combination includes photovoltaic inverters, control the photovoltaic inverters to switch to virtual synchronous machine control mode, increase the photovoltaic active power output to take over the inertia support task of the energy storage system, and control the power output of the energy storage system to drop back. The third stage of control involves controlling the synchronous generator to perform primary frequency regulation via the speed governor to maintain the long-term power balance of the system, and controlling the photovoltaic inverter to maintain power compensation in a virtual synchronous machine steady-state mode.

6. The method according to claim 1, characterized in that, After locking its differential control channel, the method further includes: The system frequency recovery status is continuously monitored. When the system frequency deviation is less than the preset first threshold and the absolute value of the frequency change rate is less than the preset second threshold, the system is determined to have entered the steady-state control stage. Control the energy storage system to exit inertia support and switch to charging mode, control the photovoltaic inverter to return to maximum power point tracking mode, and control the synchronous generator to maintain stable output.

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