A method for coordinated control of a power grid and associated power plants and related devices

Abstract

The application provides a power grid and associated power plant cooperative control method and related equipment, in the method, real-time power grid load and each power plant and power grid between the grid-connected point voltage are needed to be acquired, so as to carry out power grid operation monitoring according to real-time power grid load and each power plant grid-connected point voltage. When at least one of real-time power grid load and each grid-connected point voltage triggers a preset abnormality judgment rule, abnormal fluctuation data is determined, and at least one of active power and reactive power of at least one power plant is adjusted according to abnormal fluctuation data, inverter power characteristics of each power plant and system inertia data of the power grid, so as to maintain the connection of the power grid, load end and each power plant. In this way, the active and reactive conversion relationship in each power plant can be fully considered, the chain reaction caused by single device adjustment lag can be avoided, and the operation stability of the power grid can be ensured.

Description

Technical Field

[0001] The present application relates to the field of power grid control technology, and in particular to a coordinated control method for a power grid and associated power plants and related equipment. Background Art

[0002] Current coordinated control schemes for power grids and their associated power plants typically rely on SVC (Static Var Compensator) and energy storage system regulation technologies to achieve power regulation for both the power plant and the grid itself. Currently, these control technologies have a slow response time of minutes. In particular, for power plants with multiple power fluctuations, such as photovoltaic power plants, conventional SVC and energy storage system regulation technologies are unable to effectively control the power generation efficiency of PV power plants, as their power is highly susceptible to weather factors and fluctuates rapidly. Furthermore, when the voltage at the grid-connection point between the power plant and the grid, or the grid's own frequency, fluctuates, these power generation control technologies are unable to take timely and accurate measures, potentially disconnecting the grid from its associated power plant or load, resulting in poor grid operational stability. Summary of the Invention

[0003] In view of the above problems, in order to improve the operational stability of the power grid, an embodiment of the present application provides a collaborative control method and related equipment for a power grid and associated power plants.

[0004] The embodiments of this application disclose the following technical solutions:

[0005] In a first aspect, an embodiment of the present application provides a method for coordinated control of a power grid and associated power plants, which is applied to a power grid, wherein the power grid is connected to multiple power plants, and each power plant has a separate type of inverter; the method includes:

[0006] Obtaining real-time grid load and the voltage at the connection point between each power plant and the grid;

[0007] Performing grid operation monitoring based on the real-time grid load and the plurality of grid connection point voltages, and determining abnormal fluctuation data that triggers a preset abnormality determination rule when at least one of the real-time grid load and the plurality of grid connection point voltages triggers the preset abnormality determination rule;

[0008] Based on the abnormal fluctuation data, the inverter power characteristics of each of the power plants, and the system inertia data of the power grid, at least one of the active power and reactive power of at least one of the power plants is adjusted to maintain the connection between the power grid and the load end and each of the power plants; the power characteristics are used to characterize the dynamic relationship between the active power and reactive power of the inverter.

[0009] In a possible implementation, the abnormal fluctuation data comprises grid-connected point voltage fluctuation data and frequency fluctuation data.

[0010] The adjusting at least one of the active power and the reactive power of at least one of the power plants according to the abnormal fluctuation data, the inverter power characteristics of each of the power plants, and the system inertia data of the power grid, to maintain the connection of the power grid and the load end and each of the power plants, comprises:

[0011] In a case where the abnormal fluctuation data only comprises the grid-connected point voltage fluctuation data, determining a voltage ride-through depth corresponding to the grid-connected voltage fluctuation data, and a first power plant generating the grid-connected point voltage fluctuation data;

[0012] According to the first power plant and the inverter power characteristics of each of the power plants, the system inertia data of the power grid, and the voltage ride-through depth, adjusting the reactive power of at least one of the power plants to maintain the connection of the first power plant and the power grid.

[0013] In a possible implementation, the inverter power characteristics comprise a PQ characteristic curve, and the first power plant is provided with a first inverter;

[0014] The adjusting the reactive power of at least one of the power plants according to the first power plant and the inverter power characteristics of each of the power plants, the system inertia data of the power grid, and the voltage ride-through depth, to maintain the connection of the first power plant and the power grid, comprises:

[0015] According to the PQ characteristic curve of the first inverter, determining a power critical state of the first inverter; the power critical state is used to represent whether the current reactive power of the inverter enters a nonlinear inflection point region in the PQ characteristic curve, and the nonlinear inflection point is a characteristic mutation point of the first inverter from a linear adjustment region of active power and reactive power to a saturation adjustment region;

[0016] According to the power critical state of the first inverter, the system inertia data of the power grid, and the voltage ride-through depth, adjusting the reactive power of the first power plant or at least one power plant other than the first power plant to maintain the connection of the first power plant and the power grid.

[0017] In a possible implementation, the power critical state comprises a pre-inflection point state and a post-inflection point state.

[0018] The pre-inflection point state is used to represent a case where the current reactive power is less than a reactive power value of the nonlinear inflection point, and a difference between them is greater than a preset first threshold value;

[0019] The post-inflexion state is used to represent a case where the current reactive power is not less than the reactive power value of the nonlinear inflection point, or the current reactive power is less than the reactive power value of the nonlinear inflection point, and the difference between them is not greater than the preset first threshold value.

[0020] In a possible implementation, the adjusting the reactive power of the first power plant or at least one power plant other than the first power plant according to the power critical state of the first inverter, the system inertia data of the power grid, and the voltage ride-through depth to maintain the connection of the first power plant with the power grid comprises:

[0021] According to the voltage ride-through depth, a first duration in which the first inverter can be maintained to operate at a minimum is determined, and a target reactive power of the first inverter and a target grid-connected point voltage of the first power plant are calculated based on the first duration;

[0022] In a case where the power critical state is the pre-inflexion state, and the difference between the reactive power at the inflection point and the current reactive power is not greater than the target reactive power, the reactive power output of the first inverter is adjusted to the target reactive power to maintain the connection of the first power plant with the power grid;

[0023] In a case where the power critical state is the post-inflexion state, or the difference between the reactive power at the inflection point and the current reactive power is less than the target reactive power, the reactive power of the first inverter or a second inverter is adjusted according to the voltage ride-through depth, the target reactive power, and the target grid-connected point voltage to maintain the connection of the first power plant with the power grid; the second inverter is an inverter other than the first inverter whose power critical state is the pre-inflexion state, and the power plant to which the second inverter belongs is different from the first power plant;

[0024] Wherein, when the reactive power output of the first inverter reaches the target reactive power, or the grid-connected point voltage between the first power plant and the power grid reaches the target grid-connected point voltage, the first power plant can maintain the connection with the power grid.

[0025] In a possible implementation, the adjusting the reactive power of the first inverter or the second inverter according to the voltage ride-through depth, the target reactive power, and the target grid-connected point voltage to maintain the connection of the first power plant with the power grid in a case where the power critical state is the post-inflexion state comprises:

[0026] A first active power change value generated by the first inverter when the first inverter is adjusted from the current reactive power to the target reactive power is calculated.

[0027] Calculating, based on the real-time grid load, a first frequency change rate of the grid generated by the first active power change value;

[0028] determining, based on the system inertia data of the power grid, whether the current system inertia of the power grid can suppress the first frequency change rate;

[0029] If the current system inertia of the power grid is capable of suppressing the first frequency change rate, adjusting the reactive power output of the first inverter to the target reactive power to maintain the connection between the first power plant and the power grid;

[0030] If the current system inertia of the grid cannot suppress the first frequency change rate, the reactive power output of the second inverter is adjusted based on the target grid connection point voltage to maintain the connection between the first power plant and the grid.

[0031] In one possible implementation, adjusting at least one of active power and reactive power of at least one of the power plants based on the abnormal fluctuation data, inverter power characteristics of each of the power plants, and system inertia data of the power grid to maintain connection between the power grid and at least one of the load end and each of the power plants includes:

[0032] In a case where the abnormal fluctuation data only includes the frequency fluctuation data, determining a second frequency change rate associated with the frequency fluctuation data;

[0033] The active power of at least one of the power plants is adjusted based on the inverter power characteristics of each of the power plants, the system inertia data of the power grid, and the second frequency change rate to maintain the connection between the power grid and the load end and each of the power plants.

[0034] In one possible implementation, adjusting the active power of at least one of the power plants based on inverter power characteristics of each of the power plants, system inertia data of the power grid, and the second frequency change rate to maintain connection between the power grid and the load end and each of the power plants includes:

[0035] determining, based on the system inertia data of the power grid, whether the system inertia of the power grid can suppress the second frequency change rate;

[0036] When the system inertia of the power grid is capable of suppressing the second frequency change rate, maintaining the connection between the power grid and the load end and each of the power plants only by the system inertia of the power grid;

[0037] When the system inertia of the power grid cannot suppress the second frequency change rate, the active power of at least one inverter in the power plant is adjusted according to the power critical state and the second frequency change rate of the inverter in each power plant to maintain the connection between the power grid and the load end and each power plant.

[0038] In a possible implementation, when the system inertia of the power grid cannot suppress the second frequency change rate, adjusting the active power of at least one inverter in the power plant according to the power criticality state and the second frequency change rate of the inverter in each power plant to maintain the connection between the power grid and the load end and each power plant includes:

[0039] determining a target active power for the power grid based on the second frequency change rate; a difference between the target active power and the current active power output of the power grid can suppress the second frequency change rate;

[0040] Determining at least one third inverter based on the target active power and the critical power state of each inverter in the power plant; the critical power state of the third inverter is the post-inflection point state, and the third inverter is capable of ensuring that a corresponding reactive power change value generated is no greater than a preset second threshold value while ensuring that the current active power output of the power grid is adjusted to the target active power;

[0041] The active power of the third inverter is adjusted so that the current active power output of the power grid reaches the target active power.

[0042] In one possible implementation, adjusting at least one of the active power and the reactive power of at least one of the power plants based on the abnormal fluctuation data, the inverter power characteristics of each of the power plants, and the system inertia data of the power grid to maintain the connection between the power grid and the load end and each of the power plants includes:

[0043] In a case where the abnormal fluctuation data includes the grid connection point voltage fluctuation data and the frequency fluctuation data, determining a third frequency change rate associated with the frequency fluctuation data, and a voltage ride-through occurrence ratio associated with the grid connection point voltage fluctuation data; the voltage ride-through occurrence ratio is used to represent a proportion of power plants in the plurality of power plants that experience voltage ride-through;

[0044] calculating a frequency fluctuation impact weight and a voltage ride-through impact weight respectively according to the third frequency change rate and the voltage ride-through occurrence ratio;

[0045] determine a power adjustment priority according to the frequency fluctuation influence weight and the voltage ride-through influence weight; the power adjustment priority is used to determine an adjustment order between active power adjustment and reactive power adjustment;

[0046] adjust at least one of active power and reactive power of at least one of the power plants according to the power adjustment priority, inverter power characteristics of each of the power plants, and system inertia data of the power grid, to maintain the connection of the power grid with the load end and each of the power plants.

[0047] In a possible implementation, before the adjustment of at least one of active power and reactive power of at least one of the power plants, the method further includes:

[0048] obtain environment change parameters individually associated with each of the power plants within a preset future time length;

[0049] perform power prediction based on the environment change parameters individually associated with each of the power plants, to determine a predicted power change curve of an inverter in each of the power plants within the preset future time length;

[0050] determine the predicted power change curve of the inverter in each of the power plants within the preset future time length as the inverter power characteristics of each of the power plants.

[0051] In a second aspect, an embodiment of the present application provides a coordinated control system of a power grid and associated power plants, applied to the power grid side, the power grid being connected with a plurality of power plants, and each of the power plants being provided with an inverter of a single type; the system includes:

[0052] an obtaining module, configured to obtain real-time power grid load and point-of-connection voltages between each of the power plants and the power grid;

[0053] a running monitoring module, configured to perform power grid running monitoring according to the real-time power grid load and the plurality of point-of-connection voltages, and determine abnormal fluctuation data of the power grid in a case where at least one of the real-time power grid load and the plurality of point-of-connection voltages triggers a preset abnormality determination rule; the abnormal fluctuation data is used to represent a fluctuation condition corresponding to at least one of the real-time power grid load and the plurality of point-of-connection voltages;

[0054] an adjusting module, configured to adjust at least one of active power and reactive power of at least one of the power plants according to the abnormal fluctuation data, inverter power characteristics of each of the power plants, and system inertia data of the power grid, to maintain the connection of the power grid with the load end and each of the power plants; the power characteristics are used to represent a dynamic relationship between active power and reactive power of the inverter.

[0055] In a third aspect, an embodiment of the present application provides a power grid, which is used to implement any possible coordinated control method of the power grid and associated power plants in the first aspect.

[0056] In a fourth aspect, an embodiment of the present application provides an artificial intelligence device, which is used to implement any possible collaborative control method of a power grid and associated power plants as described in the first aspect.

[0057] In a fifth aspect, an embodiment of the present application provides a computer-readable storage medium having a computer program stored thereon, which, when executed by a processor, implements any possible method for coordinated control of a power grid and associated power plants in the first aspect.

[0058] Compared with the prior art, the present application has the following beneficial effects: The embodiment of the present application provides a coordinated control method and related equipment for a power grid and associated power plants, and the method is applied to the power grid side, where the power grid is connected to multiple power plants, and each power plant has a separate type of inverter. In this method, it is necessary to first obtain the real-time power grid load and the grid connection point voltage between each power plant and the power grid, so as to monitor the power grid operation based on the real-time power grid load and the grid connection point voltage of each power plant. When at least one of the real-time power grid load and the grid connection point voltage of each power plant triggers a preset abnormality judgment rule, the abnormal fluctuation data that triggers the preset abnormality judgment rule is determined, thereby quickly locking the fluctuation of key parameters that affect the stability of the power grid, providing a clear target for subsequent control strategies. Subsequently, based on the specific abnormal fluctuation data, the inverter power characteristics of each power plant, and the system inertia data of the power grid, at least one of the active power and reactive power of at least one power plant is adjusted to maintain the connection between the power grid and the load end and each power plant. Among them, power control is performed through the dynamic relationship between the active power and reactive power of the inverters of each power plant, which can fully consider the active and reactive conversion relationship in each power plant and the flexible adjustment capability of the inverter equipment, avoid the chain reaction caused by the lag in the adjustment of a single device, and thus ensure the operational stability of the power grid. At the same time, based on the consideration of the inertia of the power grid system, it can effectively avoid the defects of the traditional static compensation technology of slow response and dependence on hardware upgrades, and prevent the risk of active power drop and frequency collapse caused by excessive reactive power regulation. The collaborative control mechanism for the power grid and the corresponding associated power plants provided in the embodiment of the present application can achieve dynamic support for the grid voltage and frequency on the basis of considering the equipment characteristics of the inverter and the inertia of the power grid system, thereby achieving the effect of improving the operational stability of the power grid. BRIEF DESCRIPTION OF THE DRAWINGS

[0059] In order to more clearly illustrate the embodiments of the present application or the technical solutions in the prior art, the following briefly introduces the drawings required for use in the embodiments or the description of the prior art. Obviously, the drawings described below are only some embodiments of the present application. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying any creative labor.

[0060] Figure 1 A schematic flow chart of a coordinated control method for a power grid and associated power plants provided in an embodiment of the present application;

[0061] Figure 2 A schematic diagram of a PQ characteristic curve provided in an embodiment of the present application;

[0062] Figure 3 A flow chart of a reactive power adjustment method provided in an embodiment of the present application;

[0063] Figure 4 A flow chart of another reactive power adjustment method provided in an embodiment of the present application;

[0064] Figure 5 A flow chart of another reactive power adjustment method provided in an embodiment of the present application;

[0065] Figure 6 A schematic diagram of the relationship between low voltage ride-through and minimum operating time provided in an embodiment of the present application;

[0066] Figure 7 A flow chart of another reactive power adjustment method provided in an embodiment of the present application;

[0067] Figure 8 A flow chart of an active power adjustment method during frequency fluctuations provided in an embodiment of the present application;

[0068] Figure 9 A flowchart of another active power adjustment method provided in an embodiment of the present application;

[0069] Figure 10 A flowchart of another active power adjustment method provided in an embodiment of the present application;

[0070] Figure 11 A flow chart of an active power and reactive power adjustment method provided in an embodiment of the present application;

[0071] Figure 12 A schematic diagram of a flow chart of a power change curve prediction method provided in an embodiment of the present application;

[0072] Figure 13A schematic structural diagram of a coordinated control system for a power grid and associated power plants provided in an embodiment of the present application. DETAILED DESCRIPTION

[0073] To make the objectives, technical solutions, and advantages of this application more clearly understood, the application is further described in detail below in conjunction with specific embodiments and with reference to the accompanying drawings. It should be noted that the embodiments described in the embodiments of this application are only part of the embodiments of this application, not all of the embodiments. Based on the embodiments in this application, all other embodiments obtained by ordinary technicians in this field without making any creative efforts are within the scope of protection of this application.

[0074] It should be noted that, unless otherwise defined, the technical or scientific terms used in the embodiments of this application should have the ordinary meaning understood by people with ordinary skills in the field to which this application belongs. The words "first", "second" and similar terms used in the embodiments of this application do not indicate any order, quantity or importance, but are only used to distinguish different components. Words such as "include" or "comprise" mean that the elements or objects preceding the word include the elements or objects listed after the word and their equivalents, but do not exclude other elements or objects. Words such as "connect" or "connected" are not limited to physical or mechanical connections, but can include electrical connections, whether direct or indirect. "Up", "down", "left", "right" and the like are only used to indicate relative positional relationships. When the absolute position of the described object changes, the relative positional relationship may also change accordingly.

[0075] As previously described, current power regulation technologies for the power grid and its associated power plants have a response time of minutes, resulting in a relatively slow response. This is particularly true for power plants with a wide range of power fluctuations, such as photovoltaic power plants. Because the power of photovoltaic power plants is highly susceptible to weather factors and fluctuates rapidly, conventional SVC and energy storage system regulation technologies are unable to effectively control the power generation efficiency of photovoltaic power plants. Furthermore, when the voltage at the grid-connected point between the power grid and the power plant, or the grid's own frequency, fluctuates, these power generation control technologies are unable to take immediate and accurate measures, potentially disconnecting the grid from its associated power plant or load, resulting in poor grid operational stability.

[0076] In order to solve the above problems, an embodiment of the present application provides a collaborative control method and related equipment for a power grid and associated power plants, the method being applied to the power grid side, the power grid being connected to multiple power plants, and each power plant having a separate type of inverter. In this method, it is necessary to first obtain the real-time power grid load and the grid connection point voltage between each power plant and the power grid, so as to monitor the power grid operation based on the real-time power grid load and the grid connection point voltage of each power plant. When at least one of the real-time power grid load and the grid connection point voltage triggers a preset abnormality determination rule, the abnormal fluctuation data that triggers the preset abnormality determination rule is determined, thereby quickly locking the fluctuation of key parameters that affect the stability of the power grid, and providing a clear target for subsequent control strategies. Subsequently, based on the specific abnormal fluctuation data, the inverter power characteristics of each power plant, and the system inertia data of the power grid, at least one of the active power and reactive power of at least one power plant is adjusted to maintain the connection between the power grid and the load end and each power plant. Among them, power control is performed through the dynamic relationship between the active power and reactive power of the inverters of each power plant, which can fully consider the active and reactive conversion relationship in each power plant, and can give full play to the flexible adjustment ability of the inverter equipment, avoid the chain reaction caused by the adjustment lag of a single device, and thus ensure the operation stability of the power grid. At the same time, based on the consideration of the inertia of the power grid system, it can effectively avoid the defects of the traditional static compensation technology that is slow to respond and relies on hardware upgrades, and prevent the risk of active power drop and frequency collapse caused by excessive reactive power regulation. The collaborative control mechanism for the power grid and the corresponding associated power plants provided in the embodiment of the present application can achieve dynamic support for the grid voltage and frequency on the basis of considering the equipment characteristics of the inverter and the inertia of the power grid system, thereby achieving the effect of improving the operation stability of the power grid.

[0077] It should be noted in advance that the coordinated control method for a power grid and associated power plants provided in the embodiments of the present application is applied to the power grid side. In the power grid to which the method of this embodiment is applied, the power grid is connected to multiple power plants. Each power plant has different power generation types, such as photovoltaic power plants, thermal power plants, hydropower plants, nuclear power plants, etc., and the types of inverters installed in different power plants are also different. Therefore, when actually controlling the power of the inverters of each power plant, it is necessary to adjust them according to the actual power characteristics of each type of inverter to ensure the stability of the overall adjustment.

[0078] In order to help those skilled in the art better understand the present invention, the following will clearly and completely describe the technical solutions in the embodiments of the present invention in conjunction with the accompanying drawings. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative work are within the scope of protection of this application.

[0079] See also Figure 1, which is a flow chart of a coordinated control method for a power grid and associated power plants provided in an embodiment of the present application, specifically comprising the following steps:

[0080] S101: Acquire real-time grid load and the voltage at the connection point between each power plant and the grid.

[0081] In actual power grid operations, the factors that contribute to grid instability can be categorized as frequency and grid connection point voltage. Taking frequency fluctuation as an example, grid frequency is essentially a reflection of the rotor speed of synchronous generators. When the grid's active power output is out of balance with the load it carries, the grid frequency will deviate from the nominal value (e.g., 50 Hz). If the frequency drops suddenly, the protection devices of power plants connected to the grid will detect that the system has entered an unstable state. For traditional thermal or hydropower units, low-frequency operation can cause resonance damage to turbine blades. Therefore, when the frequency falls below a set threshold (often set at 49 Hz in practical scenarios), the units will automatically disconnect from the grid for self-protection. This can potentially cause widespread power plant disconnections and large-scale power outages. Furthermore, large industrial users on the load side (such as aluminum smelters and data centers) are often equipped with low-frequency load shedding devices that automatically shed some load when the frequency drops below a critical value. If this protective action is compounded by power plant disconnections, it can exacerbate power shortages, creating a vicious cycle.

[0082] Power plant disconnections caused by voltage fluctuations are more often related to reactive power imbalances. The stability of voltage at the connection point between a power plant and the grid depends on the plant's ability to regulate reactive power in real time. When voltage drops suddenly (for example, to below 0.9 times its nominal value), the power plant's inverters prioritize increasing reactive power to support the voltage. However, if the grid's system inertia is insufficient at this time, the forced voltage increase may further limit the inverter's active power output, potentially causing grid frequency fluctuations and large-scale power outages. More seriously, voltage fluctuations can trigger misjudgments in inverter protection relays, misinterpreting transient fluctuations as permanent faults and triggering tripping. These chain reactions are particularly dangerous in power grids with a high proportion of renewable energy power plants. Inverter-dominated grids lack the mechanical inertia of traditional synchronous generators, significantly compressing the voltage and frequency regulation windows. This makes coordination of protective actions significantly more difficult, ultimately leading to systemic disconnections or load short-circuit failures, resulting in poor grid operational stability.

[0083] Therefore, in the system control method for the power grid and associated power plants provided in this embodiment, it is first necessary to obtain the real-time power grid load and the grid connection point voltage between each power plant and the power grid, so as to calculate the real-time frequency of the power grid based on the real-time power grid load and the active power output of the power plant, so as to facilitate the subsequent real-time monitoring of the real-time frequency of the power grid and the grid connection point voltage between each power plant, and trigger the adjustment and control process for the power grid or power plant when at least one of the two items shows abnormal data fluctuations, thereby ensuring the operational stability of the power grid.

[0084] In one possible implementation, real-time grid load can be obtained through a Supervisory Control and Data Acquisition (SCADA) system or an Energy Management System (EMS). These systems collect key parameters such as current, voltage, and power from each grid node in real time and, combined with high-precision synchronized data from PMUs (Phase Measurement Units), provide dynamic monitoring of grid load. Furthermore, smart meters and distribution automation systems can provide detailed load information at the load end, helping the grid understand real-time power usage. This data is transmitted to the grid control center via communication networks (such as optical fiber, 5G, or power carriers). After analysis and processing, it forms the basis for load forecasting and scheduling decisions.

[0085] Accordingly, the voltage at the connection point between the power plant and the grid can be measured in real time using various monitoring devices installed at the grid connection interface (such as relay protection devices, power quality analyzers, and remote terminal units). Relay protection devices and power quality analyzers can directly collect parameters such as voltage amplitude, frequency, and phase angle at the connection point to monitor whether the voltage fluctuates within the rated range in real time. They also record power quality indicators such as voltage swells, sags, and harmonics. The remote terminal unit, acting as a data transfer station, transmits this real-time measurement data via a communication network (such as optical fiber, wireless communication, or power carrier) to the power plant's local monitoring system and the grid dispatch center, providing operators with a real-time status reference.

[0086] S102: Monitor grid operation according to the real-time grid load and the voltages of the plurality of grid connection points, and determine abnormal fluctuation data that triggers a preset abnormality determination rule when at least one of the real-time grid load and the voltages of the plurality of grid connection points triggers a preset abnormality determination rule.

[0087] On the basis of obtaining the real-time grid load, the real-time frequency of the grid is calculated according to the current active power output of the grid and the real-time grid load, and the grid operation is monitored based on the real-time frequency of the grid and the grid connection point voltage between each power plant and the grid, so as to carry out the operation monitoring of the grid at the same time through the two aspects of the grid frequency and the grid connection point voltage.

[0088] In this embodiment, independent preset abnormality determination rules are set for the real-time grid frequency and the grid connection point voltage, respectively, to achieve parallel monitoring of the grid frequency and the grid connection point voltage. With respect to grid frequency, the setting of abnormality determination rules must take into account key factors such as static thresholds, dynamic rate of change, and fluctuation duration. For example, static threshold rules can set an allowable deviation range for the rated frequency value. For example, the normal fluctuation range of the frequency near the threshold is set to ±0.2Hz, while the fluctuation range under abnormal conditions is extended to ±0.5Hz. When the real-time frequency reaches the set static threshold and exceeds the set fluctuation range under abnormal conditions, an alert is triggered, indicating abnormal grid frequency fluctuation. In one possible implementation, the abnormality determination rule for grid frequency can also incorporate the frequency change rate as a factor. For example, if the frequency changes by more than 0.1Hz per second, abnormal grid frequency fluctuation can be determined even if the static threshold is not reached. This can capture rapid grid frequency fluctuations caused by initial imbalances in the grid's active power output.

[0089] Regarding the grid connection point voltage, the abnormality determination rules for this point require comprehensive consideration of multiple dimensions, including amplitude, phase, dynamic characteristics, and spatial correlation. For amplitude determination, a static threshold based on the rated voltage is first set. For example, during normal operation, the voltage is allowed to fluctuate within ±10% of the rated value. However, because the grid connection point voltage between the power plant and the grid can vary due to distance, the strictness of the fluctuation range can be differentiated for different voltage levels, such as high-voltage, medium-voltage, and low-voltage grid connection nodes. For example, high-voltage nodes (power plants closer to the grid) often have a greater impact on grid stability, so the fluctuation range can be set within ±5%. Furthermore, the determination logic can be dynamically adjusted based on the reactive power balance status. If the grid connection point voltage remains below the lower limit despite the power plant's reactive output reaching over 80% of its rated capacity, it can be determined that the reactive compensation equipment is undercapacitated or the excitation regulation system is malfunctioning.

[0090] Phase anomaly determination relies on the acquisition of high-precision synchronized phasor data. When the voltage phase at a power plant's grid connection point changes by more than 10° within a short period of time (e.g., 10ms), or when the phase difference between adjacent grid-connected nodes exceeds the system stability limit (e.g., the phase difference on both sides of a 220kV line exceeds 30°), it can be determined that abnormal fluctuations in the voltage at the grid connection point between the power plant and the grid exist, thereby capturing synchronization anomalies before system oscillations or short-circuit faults.

[0091] Thus, this embodiment performs real-time grid operation monitoring based on preset abnormality determination rules corresponding to both the grid frequency and the grid connection point. When at least one of these triggers the corresponding preset abnormality determination rule, abnormal fluctuation data triggering that rule is acquired. For example, when the grid frequency triggers a preset abnormality determination rule, the specific frequency fluctuation data at the time the rule is triggered is acquired. Similarly, when the grid connection point voltage triggers a preset abnormality determination rule, the corresponding voltage fluctuation data is acquired.

[0092] S103: Based on the abnormal fluctuation data, the inverter power characteristics of each of the power plants, and the system inertia data of the power grid, adjust at least one of the active power and reactive power of at least one of the power plants to maintain the connection between the power grid and the load end and each of the power plants; the power characteristics are used to characterize the dynamic relationship between the active power and reactive power of the inverter.

[0093] Finally, after obtaining the abnormal fluctuation data generated during the actual operation of the power grid, combined with the power characteristics of the inverters in each power plant and the inertia of the power grid system, at least one of the active power and reactive power in the power plant is adjusted to cope with the abnormal frequency and voltage fluctuations that may occur in the power grid.

[0094] The power characteristics of the inverter are specifically the PQ characteristic curve of the inverter. The PQ characteristic curve of the inverter is a key indicator for measuring the power regulation capability of the inverter when it is connected to the grid. It describes the dynamic relationship between the active power and reactive power of the inverter. Figure 2 A schematic diagram of a PQ characteristic curve is disclosed, wherein the horizontal axis represents the reactive power of the inverter and the vertical axis represents the active power of the inverter. As can be seen from the figure, the reactive power and active power of the inverter are in a nonlinear relationship. For the first quadrant area in the figure, the increase in reactive power and the decrease in active power are in a nonlinear relationship. When the reactive power of the inverter is small, the increase in reactive power will not lead to a sharp decrease in active power. In this case, the adjustment of the reactive power of the inverter will not have too much impact on its active power. On the contrary, when the reactive power of the inverter itself is large, the increase in reactive power is often accompanied by a sharp decrease in active power. When the reactive power of the inverter is close to its rated value, the corresponding active power will also experience a sharp decrease.

[0095] Therefore, when selectively adjusting the active power and reactive power of each power plant inverter, the embodiment of the present application introduces consideration of the PQ characteristic curve of each inverter itself to prevent the introduction of other sudden changes in the process of power adjustment of the inverter, thereby ensuring the stability of the control process.

[0096] Furthermore, the embodiments of the present application also incorporate considerations of the system inertia within the power grid during this process. System inertia primarily originates from the rotational inertia of rotating equipment such as synchronous generator rotors and motors. Its core function is to buffer rapid changes in the power grid frequency and maintain frequency stability by storing and releasing kinetic energy. Therefore, when there is an imbalance in the supply and demand of active power in the power grid (such as a sudden load surge or generator tripping), if the current system inertia within the power grid is large, the frequency change rate caused by the imbalance in the active power of the power grid will also be relatively maintained within a smaller range by the system inertia, thereby gaining more response time for the frequency modulation equipment and avoiding system instability caused by severe frequency fluctuations. Therefore, based on considerations of the power characteristics of the inverters of each power plant, this embodiment further incorporates considerations of the system inertia of the power grid. If adjustments to the reactive power of the inverters cause a sudden imbalance in active power, the fluctuations in the power grid frequency can be further stabilized by the system inertia within the power grid, thereby improving the overall control process.

[0097] Specifically, the adjustment selection of the active power and reactive power of the power plant needs to be based on the abnormal fluctuation of the power grid. In this embodiment, the abnormal fluctuation data includes frequency fluctuation data and grid connection point voltage fluctuation data, which correspond to the abnormal frequency fluctuation of the power grid and the abnormal voltage fluctuation of the grid connection point, respectively. Since the frequency of the power grid is related to the real-time load and active power output of the power grid, when the frequency fluctuation of the power grid is abnormal, it is necessary to adjust the active power output of the inverter in each power plant to cope with the abnormal frequency fluctuation in the power grid. Similarly, when the grid connection point voltage between the power grid and a power plant fluctuates abnormally, it is necessary to adjust the reactive power output of the power plant or other power plants to cope with the voltage fluctuation. In a special scenario, frequency fluctuation and voltage fluctuation will occur simultaneously on the power grid side. In such cases, it is necessary to determine the execution order of the two according to the severity of the frequency fluctuation and voltage fluctuation.

[0098] Next, the power adjustment methods for each power plant when abnormal voltage fluctuation, abnormal frequency fluctuation, or both abnormalities occur in the power grid will be introduced with reference to the accompanying drawings of specific embodiments.

[0099] First, we introduce the abnormal voltage fluctuation situation. Figure 3 , which is a flow chart of a reactive power adjustment method provided in an embodiment of the present application, specifically comprising the following steps:

[0100] S201: When the abnormal fluctuation data only includes the grid-connected point voltage fluctuation data, determine a voltage ride-through depth corresponding to the grid-connected point voltage fluctuation data and a first power plant that generates the grid-connected point voltage fluctuation data.

[0101] As described above, the acquired abnormal fluctuation data refers to monitoring items (i.e., grid frequency and grid connection point voltage) that trigger corresponding preset abnormality determination rules. Therefore, when the abnormal fluctuation data only includes grid connection point voltage fluctuation data, it indicates that only grid connection point voltage fluctuations are occurring in the power grid, and the reactive power of the power plant with voltage fluctuations needs to be adjusted to stabilize the voltage fluctuations at that power plant. In this embodiment, the power plant that generates the grid connection point voltage fluctuation data is named the first power plant.

[0102] Voltage ride-through (VRT) can be categorized into two modes: low voltage ride-through (LVRT) and high voltage ride-through (HVRRT). For LVRRT, when the grid connection point voltage suddenly drops, the inverter must remain connected to the grid within a certain voltage drop range (e.g., 20%-90% of the rated voltage). Dynamic reactive power adjustment is used to support voltage recovery and prevent system voltage collapse. For HVRRT, when the grid voltage suddenly rises, the inverter must continue operating within a certain voltage range above the rated value (e.g., 110%-130% of the rated voltage). It absorbs or generates reactive power to suppress excessive voltage increases and maintain grid stability.

[0103] Based on this, the voltage ride-through depth (VRTD) is a key indicator of the severity of voltage fluctuations at the grid connection point and a key metric for measuring the impact of voltage anomalies on power plant inverters. The VRTD provides a direct indicator of the threat level posed by voltage fluctuations to the inverters in the primary power plant. A greater VRTD typically shortens the inverter's operational life, necessitating a more intuitive and rapid reactive power adjustment.

[0104] S202: Adjust the reactive power of at least one of the power plants based on the inverter power characteristics of the first power plant and each of the power plants, the system inertia data of the power grid, and the voltage ride-through depth to maintain the connection between the first power plant and the power grid.

[0105] Based on this, the reactive power support currently required by the inverter can be determined based on the actual voltage ride-through depth. As mentioned earlier in the introduction to inverter power characteristics, the inverter's reactive power and active power have a nonlinear relationship. Regarding adjustments when reactive power is positive, when the inverter's reactive power is within a specific range of values, adjustments to the reactive power within the unit often cause more dramatic changes in active power. Therefore, to prevent inverter reactive power adjustments from significantly impacting the grid's actual active power output, it is necessary to consider the inverter power characteristics of the primary power plant and each power plant, as well as the grid's system inertia, to determine the reactive power adjustment method for the power plant.

[0106] Next, the specific execution process of step S202 will be introduced in conjunction with the specific embodiment drawings. Figure 4Fig. 4 is a flowchart of another method for adjusting reactive power according to an embodiment of the present application, and specifically includes the following steps:

[0107] S2021: determining a power critical state of the first inverter according to the PQ characteristic curve of the first inverter; the power critical state is used to represent whether the current reactive power of the inverter enters a nonlinear inflection point region in the PQ characteristic curve, and the nonlinear inflection point is a characteristic mutation point of the first inverter from a linear adjustment region of active power and reactive power to a saturation adjustment region.

[0108] In the coordinated control system of the power grid in the embodiment, determining the power critical state of the first inverter according to the PQ characteristic curve is a key link for accurately identifying the power regulation characteristics of the inverter. The PQ characteristic curve is a core index for measuring the power regulation capability of the inverter when it is connected to the power grid, and directly presents the dynamic nonlinear relationship between the active power and the reactive power. In the linear adjustment region of the curve, a small adjustment of the reactive power will only cause a gentle change of the active power, and at this time, the power regulation of the inverter has high flexibility. When the reactive power enters the nonlinear inflection point region after the inflection point, an increase of the reactive power will cause a sharp drop of the active power, forming a characteristic mutation from linear adjustment to saturation adjustment. This nonlinear inflection point, as a critical dividing point of the power regulation capability of the inverter, marks the transition of the regulation characteristics from "large controllable margin" to "active power vulnerable to impact". By analyzing whether the current reactive power enters the inflection point region, it can be determined whether the power regulation of the inverter is in a risk critical state, thereby providing a key basis for subsequent control strategies.

[0109] In the embodiment, whether the inflection point region is linear or not can be divided according to the slope formed by the reactive power and the active power. If the slope formed by the current reactive power and the active power is smaller, it means that the change of the active power caused by the change of the reactive power within a unit is smaller. Therefore, in a possible implementation manner, whether the current reactive power of the inverter enters the nonlinear inflection point region can be determined by setting a slope threshold.

[0110] For details, refer to Figure 2 The PQ characteristic curve shown in FIG. 5 is a PQ characteristic curve when the voltage is 0.9U. In this PQ characteristic curve, the set point B is an inflection point. As can be seen from the curve shown in the figure, for the characteristic curve on the right side of the B point, an increase of the reactive power within a unit will cause an exponential drop of the active power, and therefore, the curve region on the right side of the B point is a nonlinear inflection point region of the inverter. Conversely, for the characteristic curve on the left side of the B point, the change of the reactive power within a unit has a smaller impact on the active power, and therefore, the adjustment of the reactive power in this region will not cause too much impact on the active power output of the power grid.

[0111] The critical power state is divided into a pre-inflection point state and a post-inflection point state. The pre-inflection point state indicates that the inverter is before the nonlinear inflection point, that is, within the safety margin of the linear regulation zone. Specifically, the inverter's current reactive power is less than the reactive power value at the nonlinear inflection point, and the difference between the two is greater than a preset first threshold (e.g., 0.1 times the rated reactive power). In this state, the inverter's active power and reactive power have a nearly linear relationship. Moderate adjustments to reactive power will only result in a gradual change in active power and will not trigger a sharp drop in active power. For example, if the first power plant corresponding to the first inverter experiences a low voltage ride-through, the inverter in the pre-inflection point state can increase its reactive power output to increase the voltage at the grid connection point between the first power plant and the grid. In this case, the active power only decreases slightly in a linear manner, and the system can still compensate for the active power shortfall with other power sources or energy storage devices to maintain frequency stability. This state provides ample adjustment space for grid dispatch. The dispatch system can instruct the inverter to gradually increase its reactive power output, thereby increasing the voltage while avoiding excessive fluctuations in active power, fully utilizing its reactive power support capacity without threatening the active power balance. The setting of the preset first threshold is essentially to reserve a "safety buffer zone" for the system, ensuring that the inverter has sufficient response time to implement the control strategy before entering the high-risk regulation area.

[0112] The post-inflection state indicates that the inverter has approached or entered the nonlinear saturation regulation region. This refers to the situation where the current reactive power is not less than the reactive power value at the nonlinear inflection point, or the current reactive power is less than the reactive power value at the nonlinear inflection point, and the difference between the two is not greater than a preset first threshold. At this point, the slope of the PQ characteristic curve changes abruptly, and even a small increase in reactive power will cause a cliff-like drop in active power. During a large-scale power outage, when a large number of inverters enter the post-inflection state due to low voltage ride-through, the rapid cumulative drop in their active power will directly cause an imbalance in active power across the entire network, exacerbating frequency fluctuations and potentially triggering malfunction of protective devices. In this state, the inverter's reactive power regulation capability is nearing saturation. Further increasing reactive power will not only fail to effectively support voltage, but will also disrupt the system power balance due to a sudden drop in active power, creating the risk of a cascading voltage-frequency collapse.

[0113] Therefore, determining the post-inflection point state requires triggering an emergency control strategy. First, the grid-side system rapidly adjusts the inverter's reactive output limit to prevent it from entering the saturation zone. Second, it leverages other power sources with inertial support (such as rotating motors and energy storage devices) to compensate for the active power shortfall and prevent frequency collapse. The preset first threshold serves as a "risk warning line," ensuring that if the system detects that the inverter is about to exceed its linear regulation limit, it immediately initiates multi-source coordinated control, preventing risks before they occur.

[0114] S2022: Based on the power critical state of the first inverter, the system inertia data of the power grid, and the voltage crossing depth, adjust the reactive power of the first power plant or at least one power plant other than the first power plant to maintain the connection between the first power plant and the power grid.

[0115] The core of this step is to use the critical power state of the first inverter as a risk indicator for power regulation. At the same time, the inertia buffering capacity represented by the system inertia data and the actual low voltage ride-through situation represented by the voltage ride-through depth are combined to determine the adjustment method for the reactive power of the first power plant or other power plants.

[0116] It is understandable that when determining whether to adjust the reactive power of the first power plant, the power criticality of the first power plant itself is not the only indicator to be measured. When the system inertia currently maintained by the power grid is large, even if the reactive power adjustment of the first power plant causes fluctuations in active power, the frequency stability of the power grid can still be maintained based on the system inertia of the power grid, thereby raising the grid connection point voltage between the first power plant and the power grid. Therefore, the decision of whether to adjust the reactive power of the first power plant or to raise the grid connection point voltage between the first power plant and the power grid through the reactive power output of other power plants needs to be judged in combination with the power criticality of the first power plant and the system inertia of the power grid to ensure the accuracy of the inverter power control.

[0117] Next, the process of step S2022 will be introduced in conjunction with the accompanying drawings of specific embodiments. Figure 5 , which is a flow chart of another reactive power adjustment method provided in an embodiment of the present application, specifically comprising the following steps:

[0118] S2023: Determine a first minimum duration for which the first inverter can maintain operation based on the voltage ride-through depth, and calculate a target reactive power of the first inverter and a target grid connection point voltage of the first power plant based on the first duration.

[0119] For inverters in actual power plants, different types of inverters have specific minimum operating time standards. For details, please refer to Figure 6 A schematic diagram of the relationship between low voltage ride-through and minimum operating time is disclosed. In the figure, the vertical axis represents the voltage multiple at which low voltage ride-through occurs, and the horizontal axis represents the specified minimum operating time of the inverter. This shows that when the grid connection point voltage experiences different degrees of low voltage ride-through, the minimum operating time of the inverter will also change. The greater the depth of the voltage ride-through and the lower the voltage, the shorter the minimum operating time of the inverter. Correspondingly, the grid connection point voltage of the inverter needs to be raised more quickly (greater reactive power support) to avoid the inverter shutting down and causing the corresponding power plant to go offline.

[0120] It should be noted that Figure 6 The example shown is only an example of the minimum operating time relationship when low voltage ride-through occurs in the power plant. In actual application scenarios, there is also a corresponding minimum operating time when high voltage ride-through occurs. This embodiment is not limited to low voltage ride-through.

[0121] Therefore, in the initial stage of reactive power adjustment, it is necessary to determine the first minimum duration for which the first inverter can maintain operation based on the voltage crossing depth of the first power plant, so as to calculate the target reactive power that the first inverter needs to achieve within the first duration, as well as the target grid connection point voltage for the first power plant. Among them, when the reactive power output of the first inverter reaches the target reactive power, or the grid connection point voltage between the first power plant and the power grid reaches the target grid connection point voltage, the first power plant can maintain its connection with the power grid. Based on this, the embodiment of the present application divides the method of maintaining the connection between the first power plant and the power grid into two aspects: reactive power adjustment and grid connection point voltage adjustment. Reactive power adjustment mainly focuses on the reactive power adjustment of the first inverter, while the grid connection point voltage mainly focuses on responding to the voltage crossing of the first power plant by adjusting the reactive power of other power plants.

[0122] S2024: Determine whether the power critical state is a state before the inflection point, and whether the difference between the reactive power at the inflection point and the current reactive power is not greater than the target reactive power;

[0123] S2025: When the power critical state is the pre-inflection point state and the difference between the reactive power at the inflection point and the current reactive power is not greater than the target reactive power, the reactive power output of the first inverter is adjusted to the target reactive power to maintain the connection between the first power plant and the power grid.

[0124] First, a double judgment is required to determine whether the reactive power of the first inverter can be adjusted. The first is to determine that the critical power state is the "pre-inflection point state", that is, the current reactive power of the first inverter has not yet reached the nonlinear inflection point. The second is to verify whether the difference between the target reactive power and the current reactive power of the inverter is not greater than the target reactive power, that is, the impact of the reactive power adjustment of the first inverter on the active power is within a predictable range.

[0125] If both conditions are met, the adjustment of reactive power will only result in a smooth change in active power, and there will be no risk of a sudden drop in active power. For example, when the grid voltage drops slightly, if it is calculated that 0.15 times the rated reactive power needs to be increased, and the current reactive power still has a margin of 0.2 times the rated power from the inflection point, the adjustment can be performed safely, completing reactive power compensation within a time scale of 10ms, while simultaneously maintaining active power stability and providing rapid support for grid voltage recovery. This closed loop of "status confirmation-margin verification-direct adjustment" is essentially a precise utilization of the inverter's linear regulation advantage range, which can not only improve local reactive power regulation efficiency, but also maintain the active power stability boundary through constraint conditions.

[0126] S2026: When the power critical state is a post-inflection point state, or the difference between the reactive power at the inflection point and the current reactive power is less than the target reactive power, the reactive power of the first inverter or the second inverter is adjusted according to the voltage crossing depth, the target reactive power and the target grid connection point voltage to maintain the connection between the first power plant and the grid.

[0127] Conversely, if either condition is not met, forcibly adjusting the reactive power output of the first inverter to the target reactive power may cause the first inverter's reactive power to enter the nonlinear region, leading to a deterioration in regulation characteristics (e.g., reactive power saturation causing a sharp drop in active power). Therefore, to prevent this undesirable situation, it is necessary to determine, based on system inertia data, whether the system inertia can stabilize the grid frequency in the event of corresponding active power fluctuations, thereby preventing large-scale power plant disconnections. If the system inertia can support the active power fluctuations caused by the first inverter, conventional adjustments to the reactive power output of the first inverter are sufficient. Conversely, if the system inertia cannot support the active power fluctuations, the reactive power of inverters other than the first inverter (i.e., the second inverter) must be adjusted to address the voltage fluctuations experienced by the first power plant.

[0128] In this embodiment, the second inverter is an inverter other than the first inverter whose critical power state is the pre-inflection point state. The second inverter can be an inverter for multiple power plants or an inverter within a single power plant. The principle of selecting the second inverter is to select inverters whose reactive power adjustment will not significantly affect the active power, thereby ensuring stability throughout the power and voltage adjustment process.

[0129] Next, the process of adjusting the reactive power of the first inverter or the second inverter according to the voltage ride-through depth, the target reactive power and the target grid connection point voltage in step S2026 will be introduced with reference to the drawings of specific embodiments.

[0130] See also Figure 7Fig. 7 is a flow diagram of another method for adjusting reactive power according to an embodiment of the present application, which includes the following steps:

[0131] S2027: Calculate a first active power change value of the first inverter when the first inverter is adjusted from the current reactive power to the target reactive power.

[0132] First, calculate the active power change value caused by adjusting the first inverter from the current reactive power to the target reactive power. This process needs to deeply couple the device mechanism and real-time operating state of the inverter. According to the PQ characteristic curve of the first inverter, the reactive power adjustment is not a simple linear mapping, but there is a nonlinear demarcation based on the inflection point B. When the current reactive power of the first inverter or the region after adjusting into the nonlinear inflection point, the reactive adjustment will trigger an exponential drop in active power. Therefore, first locate the specific position of the current reactive power on the PQ curve, retrieve the real-time voltage depth (such as 0.95 times the rated voltage or lower), device temperature and other operating parameters of the inverter, and combine the polynomial model fitted by the factory test (or the dynamic model learned by AI in real time) to accurately calculate the active power change trajectory of the first inverter from the current reactive power to the target reactive power. For example, if the target reactive adjustment needs to cross the nonlinear inflection point, the active power change value needs to be calculated in segments: the linear region before the inflection point uses differential approximation, and the nonlinear region after the inflection point introduces an exponential decay factor, and finally the first active power change value is obtained.

[0133] S2028: Calculate a first frequency change rate of the power grid caused by the first active power change value according to the real-time power grid load.

[0134] Furthermore, based on the first active power change, the first frequency change rate caused by the active power change is calculated. This requires mapping the power fluctuations caused by a single power plant into the frequency dynamics model of the entire power grid. First, real-time grid load data is obtained, including key parameters such as total active load, regional tie-line power, and total inertia of rotating electrical machines. The first frequency change rate caused by the first active power change is calculated based on the rotor motion equation. Special attention must be paid to the real-time inertia of the power grid. When the proportion of rotating electrical machines in the system is high, the total inertia is large, and the frequency change rate caused by the same active power change is relatively small. However, when the penetration rate of renewable energy power plants in the power grid is high, the total inertia decreases, and the impact of active power changes on frequency is amplified. For example, if the first inverter's active power suddenly drops by 100 MW due to reactive power adjustment, and the current total grid inertia is 5000 MW·s, the specific value of the corresponding frequency change rate can be calculated. In addition, this step also needs to consider the islanding operation status of the power grid. If the current power grid is in islanding mode, the inertia in the area is smaller, and the frequency fluctuations caused by the same active power changes will be significantly aggravated. Therefore, it is necessary to retrieve the power grid topology data in real time to determine whether there is any tie line support in order to correct the calculation model of the frequency change rate.

[0135] S2029: Based on the system inertia data of the power grid, determine whether the current system inertia of the power grid can suppress the first frequency change rate.

[0136] The grid system's inertia suppression capability is then assessed. The technical definition of "suppression" is defined as the ability of system inertia to release or absorb kinetic energy, thereby controlling the frequency change rate within a safe range (such as the specified 2 Hz / s threshold) that prevents protective relays from operating. The specific judgment logic consists of two steps: The first step is to calculate the theoretically tolerable maximum rate of change threshold based on the grid's current system inertia data (including synchronous generator inertia, synchronous condenser inertia, and the combined inertia provided by grid-connected inverters). This threshold is inversely proportional to the inertia size and directly proportional to the damping characteristics.

[0137] The second step is to compare the calculated first frequency change rate with the theoretical threshold. If the actual value is less than or equal to the threshold, it means that the inertia is sufficient to buffer the active power fluctuations, leaving a safety margin for subsequent adjustments. If the actual value exceeds the threshold, it indicates the risk of frequency collapse. It is worth noting that the system inertia data here needs to be dynamically updated, because the synthetic inertia contribution of the new energy inverter will change with the control mode (such as whether it is operating in the grid-forming GFM mode), and the inertia of the traditional unit may be reduced in real time due to the tripping of some generators (such as units that are disconnected from the grid one after another during a large-scale power outage). In addition, this judgment must also be combined with the voltage oscillation state of the power grid. If the voltage is in a deep drop stage below 0.9 times the rated voltage at this time, even if the first frequency change rate does not exceed the standard, the boundary conditions of the low voltage ride-through capability must be considered to avoid decision-making deviations caused by relying solely on inertia judgment.

[0138] S2030: If the current system inertia of the power grid can suppress the first frequency change rate, adjust the reactive power output of the first inverter to the target reactive power to maintain the connection between the first power plant and the power grid.

[0139] Accordingly, when the system inertia assessment results indicate that the grid's current system inertia can suppress the first frequency change rate, it means that the grid's rotational inertia reserve is sufficient to buffer the active power fluctuations caused by the reactive power adjustment of the first inverter. In this case, the inverter's reactive power is directly adjusted to the target value. The key to this decision lies in leveraging the inverter's linear regulation capability in the region before the inflection point of the PQ characteristic curve. When the target reactive power is to the left of the inflection point, the corresponding decrease in active power is approximately linear, the power gradient is controllable, and the system inertia can slow the frequency drop by releasing kinetic energy, buying time for subsequent voltage recovery. For example, if the current grid voltage is in the first stage of fluctuation at 0.95 times the rated voltage, the decrease in active power during the process of adjusting the first inverter from the current reactive power to the target value is within the buffer range of the system inertia. In this case, direct adjustment can quickly increase the grid connection point voltage, preventing equipment disconnection caused by a continuous voltage drop.

[0140] S2031: If the current system inertia of the power grid cannot suppress the first frequency change rate, the reactive power output of the second inverter is adjusted based on the target grid connection point voltage to maintain the connection between the first power plant and the power grid.

[0141] Conversely, when insufficient system inertia prevents the frequency change rate, continued adjustment of the first inverter could trigger a vicious cycle of "reactive power increase, active power drop, and frequency collapse." In this case, the control strategy switches to "cross-plant coordinated regulation." Specifically, the system prioritizes a second inverter (such as a gas-fired power plant or a photovoltaic inverter with linear regulation margin) that is in a state before the inflection point of the PQ curve and belongs to a different power plant. Its reactive power is adjusted based on the target grid connection point voltage. The key condition for selecting the second inverter is that its current operating state has not entered the nonlinear region, and that active power fluctuations during reactive power adjustment are controllable, avoiding additional frequency impacts. For example, if the first inverter is already to the right of the inflection point due to a deep voltage sag (high active power sag risk), while the second inverter is located in a different region and its voltage remains above 0.95 times the rated voltage (pre-inflection point region), adjusting the second inverter's reactive power can indirectly support the voltage stability of the first power plant by increasing its grid connection point voltage. Furthermore, since its active power fluctuations are within the acceptable inertia range, the frequency drop will not be exacerbated. The essence of this strategy is to shift voltage support demand from high-risk nonlinear regulation areas to low-risk linear regulation areas through a "risk transfer-regional coordination-linear regulation" mechanism. This strategy leverages the spatial distribution advantages of multiple inverters to achieve peak-shifting regulation of reactive power compensation, avoiding the systemic risks associated with single-device adjustments. Its core purpose is to overcome the limitations of insufficient local inertia. By leveraging cross-plant resource coordination, voltage stability is maintained without triggering frequency protection. This effectively mitigated the cascading outages caused by inertia shortages during the Spanish blackout, achieving the dual-dimensional "voltage-frequency" stability control objectives.

[0142] The above is an introduction to the situation when only abnormal voltage fluctuation occurs in item S103 in the embodiment of the present application. Next, the situation when only abnormal frequency fluctuation occurs will be introduced.

[0143] See also Figure 8 , which is a flow chart of an active power adjustment method during frequency fluctuation provided by an embodiment of the present application, specifically comprising the following steps:

[0144] S301: When the abnormal fluctuation data only includes the frequency fluctuation data, determine a second frequency change rate associated with the frequency fluctuation data.

[0145] Similar to the processing mode when the grid fluctuation occurs, when only frequency fluctuation data is included in the abnormal fluctuation data, i.e., only frequency fluctuation occurs, the "second frequency change rate" directly associated with the fluctuation needs to be locked first. This process needs to synchronously collect the frequency data of each node by the phasor measurement unit in real time, and combine signal processing technologies such as wavelet transform to accurately locate the source area of the fluctuation (such as a new energy concentrated access area or a load sudden increase area). Unlike the first frequency change rate involved in the foregoing, the calculation of the second frequency change rate focuses more on the independent cause of the frequency fluctuation. For example, if the fluctuation is caused by the random fluctuation of active power of a wind farm due to turbulence, the frequency change slope at the outlet of the power plant needs to be extracted; if it is caused by the starting impact of the motor group at the load end, the equivalent active disturbance needs to be calculated in combination with the load model. Specifically, by substituting the real-time frequency deviation data into the power system frequency dynamic equation, the frequency change rate in a unit time can be calculated, which can directly reflect the severity of the frequency fluctuation and is the core criterion for triggering subsequent adjustment. For example, when it is detected that the frequency of a certain area decreases by 0.3 Hz within 50 ms, it can be determined that the RoCoF2 is 3.6 Hz / s, which is far beyond the conventional safety threshold (such as 2 Hz / s), and active power adjustment needs to be started immediately.

[0146] S302: Adjusting the active power of at least one of the power plants according to the inverter power characteristics of each of the power plants, the system inertia data of the grid, and the second frequency change rate, to maintain the connection of the grid, the load end, and each of the power plants.

[0147] After the second frequency change rate is determined, the active power of at least one of the power plants is adjusted according to the inverter power characteristics of each of the power plants and the system inertia of the grid. Similarly, this process needs to consider the system inertia of the grid, and if the system inertia of the grid can support the fluctuation of the frequency, the active power of other power plants does not need to be adjusted. Next, this process will be introduced in combination with specific embodiments and drawings.

[0148] Referring to Figure 9 The figure is a flowchart of another active power adjustment method provided by the embodiments of the present application, which specifically includes the following steps:

[0149] S3021: Judging whether the system inertia of the grid can suppress the second frequency change rate based on the system inertia data of the grid.

[0150] First, the current inertia reserve capacity of the power grid needs to be evaluated to determine whether it is sufficient to buffer the current frequency fluctuations, providing the core decision basis for subsequent control strategies. Specifically, first, the system inertia data of the power grid need to be collected in real time, which includes not only the mechanical inertia of traditional synchronous generators, synchronous compensators and other rotating equipment, but also the synthetic inertia simulated by control algorithms of grid-forming inverters (a kind of virtual inertia support capacity). These inertia data reflect the "buffering capacity" of the power grid when facing active power fluctuations, by releasing or absorbing kinetic energy to suppress frequency changes. The second frequency change rate represents the severity of the current frequency fluctuations, such as the rate of rapid frequency rise or fall in a short period of time, which directly reflects the immediate pressure on power grid stability.

[0151] S3022: In the case where the system inertia of the power grid can suppress the second frequency change rate, only the system inertia of the power grid is used to maintain the connection between the power grid, the load end and each power plant.

[0152] When it is confirmed that the system inertia can suppress the second frequency change rate, the rotor kinetic energy of the traditional synchronous generator will be naturally released (such as the release of kinetic energy when the load suddenly increases and the speed decreases, or the absorption of excess energy when the load suddenly decreases and the speed increases), and the synthetic inertia control of the grid-forming inverter will also assist the inertial response, without the need for active adjustment of the active power of the power plant inverter. This "inertia first" mechanism has the greatest advantage in reducing the frequency of device action and avoiding the impact of frequent adjustment on the service life of the inverter, while taking advantage of the "natural buffering" characteristics of inertia to quickly suppress frequency fluctuations within milliseconds, providing an adjustment window for subsequent secondary frequency modulation, especially suitable for power grid scenarios with a high proportion of traditional units and sufficient inertia reserves.

[0153] S3023: In the case where the system inertia of the power grid cannot suppress the second frequency change rate, the active power of at least one inverter in each power plant is adjusted according to the power critical state of the inverter and the second frequency change rate, to maintain the connection between the power grid, the load end and each power plant.

[0154] When system inertia is insufficient to suppress the second frequency change rate, it is necessary to selectively select at least one power plant's inverter for active power regulation, taking into account the critical power states of each power plant's inverters and the severity of the current frequency fluctuations. For example, inverters in the linear regulation region (where voltage fluctuations are controllable when regulating active power) are preferred. The core of this strategy is to precisely identify the safe regulation boundaries of each power plant's inverters in the face of insufficient inertia, leveraging the inverters' active power regulation capabilities to compensate for the inertia gap and prevent cascading grid disconnections caused by persistently exceeding the frequency change rate. For example, in a grid with a high proportion of renewable energy, when a sudden increase in load causes a rapid drop in frequency, and traditional generators are no longer able to support the situation alone, adjusting the active power output of safe photovoltaic or wind turbine inverters can quickly suppress frequency deterioration and buy time for system recovery.

[0155] Next, the execution process of step S3023 will be introduced in conjunction with the accompanying drawings of specific embodiments. Figure 10 , which is a flow chart of another active power adjustment method provided in an embodiment of the present application, specifically comprising the following steps:

[0156] S3024: Determine a target active power for the power grid based on the second frequency change rate; a difference between the target active power and the current active power output of the power grid can suppress the second frequency change rate.

[0157] The essence of this step is to quantify the severity of frequency fluctuations and accurately calculate the active power target value that needs to be adjusted, providing a benchmark for subsequent active power adjustments.

[0158] As mentioned previously, the second frequency change rate directly reflects the rate of change of the grid frequency per unit time (for example, the frequency drops by a certain number of hertz per second). A larger value indicates more severe frequency fluctuations and a greater threat to grid stability. In this case, the required active power adjustment must be deduced based on this fluctuation pressure. Specifically, active power must be adjusted to bring the frequency change rate back within a safe threshold to prevent equipment disconnection or system failure due to frequency out-of-control.

[0159] The core logic for determining the target active power is to establish a dynamic correspondence between the "frequency change speed" and the "active power gap". When the frequency rapidly decreases (such as a sudden increase in load or a sudden decrease in active power at the power generation end), it indicates that there is an active power shortage in the power grid, and the active output needs to be increased. When the frequency rapidly rises (such as a sudden decrease in load or a sudden increase in active power at the power generation end), the active output needs to be reduced. This process needs to consider the current operating state of the power grid, such as the active power output limit of each power plant, the adjustment margin of the inverter, the real-time support capacity of the system inertia, etc. For example, in a power grid with a high proportion of new energy, if the second frequency change rate is detected to be excessive, the determination of the target active power will give priority to the virtual inertia adjustment capacity of the grid-forming inverter and the speed regulation potential of the traditional generating units, to ensure that the adjustment amount meets the demand for suppressing frequency changes and does not exceed the safety operating boundary of the equipment.

[0160] S3025: Based on the target active power and the power critical state of each inverter in the power plant, at least one third inverter is determined; the power critical state of the third inverter is the post-inflexion state, and the third inverter can correspond to a generated reactive power change value not greater than a preset second threshold value under the condition that the current active power output of the power grid is adjusted to the target active power.

[0161] The key of this step is to lock the third inverter suitable for adjustment based on the double constraints of target active power and inverter power critical state. The power critical state here is the same as before, which refers to the operating position of the inverter on the active-reactive regulation characteristic curve. However, there are differences between the selection logic for the third inverter and the selection logic for the second inverter. Unlike the selection logic for the second inverter, the power critical state of the third inverter is the post-inflexion state, and it can ensure that the generated reactive power change value is not greater than the preset second threshold value under the condition that the current active power output of the power grid is adjusted to the target active power.

[0162] The "post-inflexion state" means that the third inverter has entered the nonlinear regulation region, at this time the unit internal change of reactive power will cause the active power to change dramatically. From another point of view, for such inverters, only a small part of reactive power needs to be sacrificed to achieve a large adjustment of active power. Further, the system limits this impact through a preset "second threshold value" (such as a reactive power change of no more than 15% of the rated capacity), to ensure that the disturbance to the grid voltage is within a safe range. The selection logic needs to meet two core conditions: one is that the inverter is in the post-inflexion state (i.e. it has a certain active regulation margin, but the regulation behavior will affect the reactive output), and the other is that the reactive power change value generated after active adjustment is not greater than the threshold value. This process essentially seeks a balance between "regulation necessity" and "regulation safety", aiming to find an inverter that can maximize the efficiency of active power adjustment.

[0163] S3026: Adjust the active power of the third inverter so that the current active power output of the power grid reaches the target active power.

[0164] After selecting the third inverter, its active power is adjusted specifically to ensure that the grid's overall active power output precisely matches the target value. This adjustment process adheres to the principle of minimizing reactive power disturbances: Prioritize inverters with reactive power variations close to the lower threshold (e.g., reactive power variations of only 10% of rated capacity) to avoid excessive reactive power caused by centralized adjustments to multiple inverters.

[0165] In one possible implementation, different types of inverters, such as wind and photovoltaic, can be differentiated based on their regulation characteristics. For example, wind turbine inverters can smoothly adjust their active power ramp rate using virtual inertia control, while photovoltaic inverters can fine-tune their reactive power output within the MPPT (Maximum Power Point Tracking) range with a power margin reserve. This ensures that changes in reactive power output are strictly controlled during the adjustment process. The key advantage of this strategy is that even when insufficient system inertia requires active intervention, precise screening and targeted regulation can be used to avoid new stability issues caused by the active-reactive power coupling effect of the inverters. For example, when a sudden increase in grid load in a region causes a rapid drop in frequency, the target active power needs to be increased by 5%. However, if some photovoltaic inverters in a post-inflection point state were to be directly adjusted at full power, their reactive power compensation capability would drop by 18% (exceeding the 15% threshold). In this case, the system automatically excludes these devices and instead selects wind turbine inverters, whose reactive power changes by only 12%, for adjustment. This ensures that the active power gap is met while maintaining voltage stability at the grid connection point.

[0166] The above describes active power adjustment methods when only frequency fluctuations occur on the grid side. In actual application scenarios, frequency fluctuations and grid connection point voltage fluctuations may sometimes occur simultaneously. When frequency and voltage fluctuations occur simultaneously, the severity of the fluctuations needs to be compared to determine the adjustment priority. Next, with reference to the accompanying drawings of specific embodiments, we will describe active and reactive power adjustment methods when frequency and voltage fluctuations occur simultaneously.

[0167] See also Figure 11 , which is a flow chart of an active power and reactive power adjustment method provided in an embodiment of the present application, specifically comprising the following steps:

[0168] S401: When the abnormal fluctuation data includes the grid-connected point voltage fluctuation data and the frequency fluctuation data, determine a third frequency change rate associated with the frequency fluctuation data, and a voltage ride-through occurrence ratio associated with the grid-connected point voltage fluctuation data; the voltage ride-through occurrence ratio is used to characterize the proportion of power plants in which voltage ride-through occurs among the multiple power plants.

[0169] During power grid operation, when abnormal fluctuation data includes both grid-connection point voltage and frequency fluctuation data, it is crucial to accurately extract two key indicators: the third frequency change rate and the voltage ride-through occurrence ratio. This provides a quantitative basis for subsequent coordinated control strategies. The third frequency change rate is a key characteristic of frequency fluctuation data. By collecting frequency signals from each grid node in real time and calculating the rate of change of frequency per unit time (RoCoF) based on the power system dynamic equation, it directly reflects the severity of active power imbalance. For example, when the system frequency drops rapidly within a short period of time due to the disconnection of renewable energy or a sudden increase in load, the third frequency change rate will increase significantly, indicating a sharp imbalance between active power supply and demand in the grid and requiring urgent adjustments to power plant active power output to restore frequency stability. Furthermore, the voltage ride-through occurrence ratio quantifies the impact of voltage fluctuations by measuring the percentage of power plants experiencing voltage ride-through (such as low voltage ride-through or high voltage ride-through). If a large number of power plants trigger the voltage ride-through mechanism due to sudden voltage sags or swells at the grid connection point, it indicates that the grid voltage imbalance has evolved from a local issue to a regional risk, and reactive power adjustment is a priority to improve voltage stability. These two indicators define the nature and scale of abnormal fluctuations from the dimensions of active power balance and reactive power balance, respectively, laying the foundation for the subsequent formulation of differentiated control strategies.

[0170] S402: Calculate a frequency fluctuation impact weight and a voltage ride-through impact weight according to the third frequency change rate and the voltage ride-through occurrence ratio.

[0171] Because the third frequency change rate and voltage ride-through occurrence ratio are not measured in the same unit, their original data are difficult to compare. It is necessary to calculate the frequency fluctuation impact weight and the voltage ride-through impact weight separately.

[0172] Calculating impact weights based on the third frequency change rate and the voltage ride-through ratio essentially quantifies the degree of coupling between active and reactive power imbalances, providing a basis for priority decisions in the coordinated control strategy. Calculating the frequency fluctuation impact weights requires first establishing a mapping between the frequency change rate and the system's inertia support capacity. An increase in the third frequency change rate indicates a worsening system active power imbalance and increased reliance on the inertia of rotating units or grid-connected power sources. For example, if the change rate exceeds 0.5 Hz / s, a higher weight should be assigned using an exponential or piecewise function to reflect the nonlinear growth of frequency collapse risk. During the calculation, the real-time frequency change rate can be normalized with the maximum change rate allowed by the system design. The weight coefficient can then be dynamically adjusted based on the penetration rate of renewable energy. In scenarios with a high PV penetration rate, due to weak inertial support, the weight corresponding to the same frequency change rate should be higher than that of traditional systems to strengthen the priority of responding to frequency anomalies.

[0173] The calculation of voltage ride-through impact weights focuses on the correlation between the spread of voltage issues and the behavior of inverter clusters. The voltage ride-through occurrence ratio (i.e., the proportion of power plants triggering low / high voltage ride-through) directly reflects the impact of voltage fluctuations on equipment. When the ratio exceeds 30%, it indicates that local voltage anomalies have evolved into regional risks, requiring rapid intervention by the reactive power compensation network. Weight calculations must consider the grid voltage level and equipment tolerance characteristics. For example, at transmission nodes 110 kV and above, the weight increases in an arithmetic or geometric progression for every 10% increase in the voltage ride-through occurrence ratio, highlighting the cascading impact of voltage instability on the system's hierarchical structure. Furthermore, a PQ curve inflection point correction factor is introduced. When the grid connection point voltage approaches the inflection point of the PV inverter's PQ curve, even if the occurrence ratio does not reach the threshold, the weight should be increased to avoid entering the dangerous zone of "reactive power increase leading to active power collapse." The two weights are standardized with a unified dimension (e.g., a range of 0-1), ultimately forming directly comparable quantitative indicators that provide a data foundation for subsequent coordination of active power redistribution and reactive power compensation strategies.

[0174] S403: Determine a power adjustment priority based on the frequency fluctuation impact weight and the voltage ride-through impact weight; the power adjustment priority is used to determine an adjustment order between active power adjustment and reactive power adjustment;

[0175] S404: Adjust the active power and reactive power of at least one of the power plants according to the power adjustment priority, the inverter power characteristics of each of the power plants, and the system inertia data of the power grid to maintain the connection between the power grid and the load end and each of the power plants.

[0176] When the frequency fluctuation impact weight exceeds the voltage ride-through impact weight (e.g., the weight difference exceeds 0.2), it indicates that the system active power balance is nearing a critical state, and active power adjustment mechanisms must be prioritized. For example, if the third frequency change rate suddenly rises to 1.2 Hz / s (corresponding to a weight of 0.85) due to large-scale renewable energy disconnection, while the voltage ride-through occurrence rate is 25% (weight of 0.5), the frequency collapse risk outweighs the voltage issue. Energy storage systems, fast-response coal-fired power units, or grid-forming inverters (GFMs) should be immediately deployed to inject active power. This will enhance system inertia to suppress further frequency drops and create a window for subsequent reactive power adjustments. Conversely, when the weight relationship reverses (e.g., the voltage ride-through weight reaches 0.75 and the frequency weight reaches 0.6), it indicates that the voltage anomaly has become a regional threat (e.g., over 40% of power plants triggering low voltage ride-through). Inverter group control strategies should be prioritized to increase reactive power output, switch reactors, or activate synchronous compensators to quickly raise the grid connection point voltage to a safe range. This prevents further equipment disconnection due to continued voltage drops, which would further exacerbate the active power imbalance. This priority decision-making mechanism is not absolute, but achieves flexible switching through preset weight thresholds (such as a 0.1 level difference). For example, when the weights are close (difference < 0.1), the "active-reactive coordinated adjustment" mode is triggered, and adjustment resources are allocated synchronously to avoid the coupling risk caused by one-dimensional adjustment.

[0177] The above describes methods for adjusting active and reactive power when frequency and voltage fluctuations occur simultaneously. In particular, in one possible implementation, before adjusting at least one of active and reactive power, the power variation curve of each power plant can be predicted based on environmental variation parameters of each power plant. This power variation curve can then be used as a control basis to improve the accuracy of grid regulation and power control.

[0178] See also Figure 12 , which is a flow chart of a power change curve prediction method provided in an embodiment of the present application, specifically comprising the following steps:

[0179] S501: Obtain environmental change parameters individually associated with each power plant within a preset future time period.

[0180] The collection of environmental change parameters must cover key physical quantities that are strongly correlated with the type of power plant. For photovoltaic power plants, this includes minute-by-minute solar irradiance, module temperature, and atmospheric humidity; for wind power plants, this involves wind speed, wind direction, and hub-height air temperature. These parameters are collected in real time through a sensor network deployed across the plant and, combined with numerical weather forecasts, extrapolated for the next 15 minutes to an hour, forming a refined time series of environmental parameters (such as an irradiance prediction curve at 1-second intervals). Its core value lies in capturing the "predictable fluctuations" in renewable energy output, such as sudden drops in irradiance in cloudy weather and sudden changes in wind power caused by gusts. If these fluctuations are not quantified in advance, they may accumulate on the grid side as abnormal oscillations in voltage and frequency.

[0181] S502: Perform power prediction based on the environmental change parameters individually associated with each of the power plants to determine a predicted power change curve of the inverter in each of the power plants within the preset future time period.

[0182] S503: Determine the predicted power change curve of the inverter in each of the power plants within the preset future time period as the inverter power characteristic of each of the power plants.

[0183] Power prediction based on environmental parameters requires a deep coupling of the inverter's physical model and data-driven algorithms. For photovoltaic inverters, irradiance and temperature inputs are converted into DC power using a modified photovoltaic cell equivalent circuit model. This is then combined with the MPPT algorithm and the inverter efficiency curve to generate a predicted AC active power value. Simultaneously, the adjustable range of reactive power is output synchronously, taking into account reactive power regulation constraints (such as the power factor range). For wind turbine inverters, aerodynamic power is calculated using an aerodynamic model and converted into grid-side power using the drive train and converter models, taking into account the dynamic response delays of pitch angle adjustment and speed control. The prediction process needs to incorporate an outlier detection mechanism. For example, when the irradiance forecast fluctuation rate exceeds 20% / minute, a short-term power fluctuation warning is triggered. The resulting predicted power variation curve (including the time-power relationship between active and reactive power) is essentially a quantitative description of the inverter's dispatchability under future operating conditions. For example, during the 2:00 PM to 2:10 PM period, due to cloud cover, the active power of a photovoltaic power plant will linearly drop from 90% of the rated value to 60%, while the reactive power regulation margin will dynamically shrink with the voltage fluctuation range.

[0184] The embodiment of the present application provides a kind of power grid and the cooperative control method of associated power plant, its method is applied to power grid side, power grid is connected with multiple power plants, and each power plant is equipped with single type inverter.In the present method, real-time power grid load and the grid-connected point voltage between each power plant and power grid need to be obtained, to carry out power grid operation monitoring according to real-time power grid load and the grid-connected point voltage of each power plant.When at least one of real-time power grid load and each grid-connected point voltage triggers preset abnormality determination rule, determine the abnormal fluctuation data of preset abnormality determination rule triggered, to quickly lock the key parameter fluctuation situation of influence power grid stability, provide clear targeting for subsequent control strategy.Subsequently, according to specific abnormal fluctuation data, the inverter power characteristic of each power plant and the system inertia data of power grid, at least one of the active power and the reactive power of at least one power plant is adjusted, to maintain the connection of power grid and load end and each power plant.The power control between the active power and the reactive power of each power plant inverter can fully consider the active and reactive conversion relationship in each power plant, can give full play to the flexible adjustment capacity of inverter equipment, avoid the chain reaction caused by single device adjustment lag, and then ensure the operation stability of power grid.Meanwhile, based on the consideration of power grid system inertia, the defects of slow response and dependence on hardware upgrade of traditional static compensation technology can be effectively avoided, to prevent the risk of active power sudden drop and frequency collapse caused by excessive reactive power regulation.The cooperative control mechanism for power grid and corresponding associated power plant provided in the embodiment of the present application can realize dynamic support for power grid voltage and frequency based on considering the device characteristics of inverter and power grid system inertia, to achieve the effect of improving power grid operation stability.

[0185] The embodiment of the present application provides a kind of power grid and the cooperative control system of associated power plant, which will be described below, the cooperative control system of power grid and associated power plant described below can be mutually corresponding with the cooperative control method of power grid and associated power plant described above.

[0186] Referring to Figure 13 The figure is the structure schematic diagram of the cooperative control system of power grid and associated power plant provided in the embodiment of the present application, specifically comprising the following modules:

[0187] The acquisition module 100 is used to acquire real-time power grid load and the grid-connected point voltage between each power plant and the power grid;

[0188] The operation monitoring module 200 is used for carrying out power grid operation monitoring according to the real-time power grid load and multiple grid-connected point voltages, and determining the abnormal fluctuation data of the power grid in the case where at least one of the real-time power grid load and multiple grid-connected point voltages triggers preset abnormality determination rule;The abnormal fluctuation data is used to represent the fluctuation situation corresponding to at least one of the real-time power grid load and multiple grid-connected point voltages.

[0189] The regulation module 300 is used to adjust at least one of the active power and reactive power of at least one of the power plants based on the abnormal fluctuation data, the inverter power characteristics of each of the power plants, and the system inertia data of the power grid to maintain the connection between the power grid and the load end and each of the power plants; the power characteristics are used to characterize the dynamic relationship between the active power and reactive power of the inverter.

[0190] An embodiment of the present application further provides a power grid, which is used to implement the coordinated control method of the power grid and associated power plants of any of the above embodiments.

[0191] An embodiment of the present application also provides an artificial intelligence device, which is used to implement the coordinated control method of the power grid and the associated power plant in any of the above embodiments.

[0192] Based on the same inventive concept, corresponding to any of the above-mentioned embodiment methods, an embodiment of the present application also provides a computer-readable storage medium, wherein the computer-readable storage medium stores computer instructions, and the computer instructions are used to enable the computer to perform the coordinated control of the power grid and the associated power plants as described in any of the above embodiments.

[0193] The computer-readable media of the embodiments of the present application include permanent and non-permanent, removable and non-removable media that can be used to store information by any method or technology. The information can be computer-readable instructions, data structures, program modules or other data. Examples of computer storage media include, but are not limited to, phase change memory (PRAM), static random access memory (SRAM), dynamic random access memory (DRAM), other types of random access memory (RAM), read-only memory (ROM), electrically erasable programmable read-only memory (EEPROM), flash memory or other memory technology, read-only compact disc read-only memory (CD-ROM), digital versatile disc (DVD) or other optical storage, magnetic cassettes, magnetic disk storage or other magnetic storage devices or any other non-transmission media that can be used to store information that can be accessed by a computing device.

[0194] The computer instructions stored in the storage medium of the above embodiment are used to enable the computer to execute the gain flatness compensation method for millimeter wave signals as described in any of the above embodiments, and have the beneficial effects of the corresponding method embodiments, which will not be described in detail here.

[0195] It should be noted that the various embodiments in this specification are described in a progressive manner, and the same or similar parts between the various embodiments can be referred to each other, and each embodiment focuses on the differences from other embodiments. In particular, for the methods and related equipment, since they are basically similar to the method embodiments, the description is relatively simple, and the relevant parts can be referred to the partial description of the method embodiments. The methods and related equipment described above are merely schematic, wherein the units described as separate components may or may not be physically separated, and the components indicated as units may or may not be physical units, that is, they may be located in one place, or they may be distributed on multiple network units. Some or all of the modules can be selected according to actual needs to achieve the purpose of the solution of this embodiment. A person of ordinary skill in the art can understand and implement it without expending creative work.

[0196] The above is merely one specific embodiment of the present application, but the scope of protection of the present application is not limited thereto. Any changes or substitutions that can be easily conceived by a person skilled in the art within the technical scope disclosed in this application should be included in the scope of protection of the present application. Therefore, the scope of protection of the present application should be based on the scope of protection of the claims.

Claims

1. A coordinated control method for a power grid and associated power plants, characterized in that: Applied to a power grid, the power grid is connected to multiple power plants, and each power plant has a separate type of inverter; the method includes: Obtaining real-time grid load and the voltage at the connection point between each power plant and the grid; Performing grid operation monitoring based on the real-time grid load and the plurality of grid connection point voltages, and determining abnormal fluctuation data that triggers a preset abnormality determination rule when at least one of the real-time grid load and the plurality of grid connection point voltages triggers the preset abnormality determination rule; Based on the abnormal fluctuation data, the inverter power characteristics of each of the power plants, and the system inertia data of the power grid, at least one of the active power and reactive power of at least one of the power plants is adjusted to maintain the connection between the power grid and the load end and each of the power plants; the power characteristics are used to characterize the dynamic relationship between the active power and reactive power of the inverter.

2. The method according to claim 1, characterized in that The abnormal fluctuation data includes: grid connection point voltage fluctuation data and frequency fluctuation data; The adjusting, based on the abnormal fluctuation data, the inverter power characteristics of each of the power plants, and the system inertia data of the power grid, at least one of the active power and the reactive power of at least one of the power plants to maintain the connection between the power grid and the load end and each of the power plants, includes: In a case where the abnormal fluctuation data only includes the grid connection point voltage fluctuation data, determining a voltage ride-through depth corresponding to the grid connection point voltage fluctuation data and a first power plant that generates the grid connection point voltage fluctuation data; According to the inverter power characteristics of the first power plant and each of the power plants, the system inertia data of the power grid, and the voltage ride-through depth, the reactive power of at least one of the power plants is adjusted to maintain the connection between the first power plant and the power grid.

3. The method according to claim 2, characterized in that The inverter power characteristics include: a PQ characteristic curve, the inverter provided in the first power plant is a first inverter; The adjusting the reactive power of at least one of the power plants based on the inverter power characteristics of the first power plant and each of the power plants, the system inertia data of the power grid, and the voltage ride-through depth to maintain the connection between the first power plant and the power grid includes: determining a power critical state of the first inverter based on a PQ characteristic curve of the first inverter; the power critical state is used to indicate whether the current reactive power of the inverter has entered a nonlinear inflection point region in the PQ characteristic curve, the nonlinear inflection point being a characteristic mutation point at which the first inverter transitions from a linear regulation region of active power and reactive power to a saturation regulation region; Based on the power critical state of the first inverter, the system inertia data of the power grid, and the voltage ride-through depth, the reactive power of the first power plant or at least one power plant other than the first power plant is adjusted to maintain the connection between the first power plant and the power grid.

4. The method according to claim 3, characterized in that The power critical state includes: a state before the inflection point and a state after the inflection point; The pre-inflection point state is used to represent a situation where the current reactive power is less than the reactive power value of the nonlinear inflection point, and the difference between the two is greater than a preset first threshold; The post-inflection point state is used to characterize the situation where the current reactive power is not less than the reactive power value of the nonlinear inflection point, or the current reactive power is less than the reactive power value of the nonlinear inflection point, and the difference between the two is not greater than the preset first threshold.

5. The method according to claim 4, characterized in that The adjusting, based on the power criticality of the first inverter, the system inertia data of the power grid, and the voltage ride-through depth, the reactive power of the first power plant or at least one power plant other than the first power plant to maintain the connection between the first power plant and the power grid includes: Determining, based on the voltage ride-through depth, a first minimum duration for which the first inverter can maintain operation, and calculating, based on the first duration, a target reactive power of the first inverter and a target grid connection point voltage of the first power plant; When the critical power state is the pre-inflection point state and the difference between the reactive power at the inflection point and the current reactive power is not greater than the target reactive power, adjusting the reactive power output of the first inverter to the target reactive power to maintain the connection between the first power plant and the power grid; When the critical power state is the post-inflection point state, or the difference between the reactive power at the inflection point and the current reactive power is less than the target reactive power, adjusting the reactive power of the first inverter or the second inverter based on the voltage ride-through depth, the target reactive power, and the target grid connection point voltage to maintain the connection between the first power plant and the power grid; the second inverter is an inverter other than the first inverter whose critical power state is the pre-inflection point state, and the power plant to which the second inverter belongs is different from the first power plant; When the reactive power output of the first inverter reaches the target reactive power, or the grid connection point voltage between the first power plant and the grid reaches the target grid connection point voltage, the first power plant can maintain connection with the grid.

6. The method according to claim 5, characterized in that When the power critical state is the post-inflection point state, adjusting the reactive power of the first inverter or the second inverter according to the voltage ride-through depth, the target reactive power, and the target grid connection point voltage to maintain the connection between the first power plant and the grid includes: calculating a first active power change value generated by the first inverter when the first inverter is adjusted from the current reactive power to the target reactive power; Calculating, based on the real-time grid load, a first frequency change rate of the grid generated by the first active power change value; determining, based on the system inertia data of the power grid, whether the current system inertia of the power grid can suppress the first frequency change rate; If the current system inertia of the power grid is capable of suppressing the first frequency change rate, adjusting the reactive power output of the first inverter to the target reactive power to maintain the connection between the first power plant and the power grid; If the current system inertia of the grid cannot suppress the first frequency change rate, the reactive power output of the second inverter is adjusted based on the target grid connection point voltage to maintain the connection between the first power plant and the grid.

7. The method according to claim 4, characterized in that The adjusting, based on the abnormal fluctuation data, the inverter power characteristics of each of the power plants, and the system inertia data of the power grid, at least one of the active power and the reactive power of at least one of the power plants to maintain the connection between the power grid and the load end and at least one of the power plants, includes: In a case where the abnormal fluctuation data only includes the frequency fluctuation data, determining a second frequency change rate associated with the frequency fluctuation data; The active power of at least one of the power plants is adjusted based on the inverter power characteristics of each of the power plants, the system inertia data of the power grid, and the second frequency change rate to maintain the connection between the power grid and the load end and each of the power plants.

8. The method according to claim 7, characterized in that The adjusting the active power of at least one of the power plants based on the inverter power characteristics of each of the power plants, the system inertia data of the power grid, and the second frequency change rate to maintain the connection between the power grid and the load end and each of the power plants includes: determining, based on the system inertia data of the power grid, whether the system inertia of the power grid can suppress the second frequency change rate; When the system inertia of the power grid is capable of suppressing the second frequency change rate, maintaining the connection between the power grid and the load end and each of the power plants only by the system inertia of the power grid; When the system inertia of the power grid cannot suppress the second frequency change rate, the active power of at least one inverter in the power plant is adjusted according to the power critical state of the inverter in each power plant and the second frequency change rate to maintain the connection between the power grid and the load end and each power plant.

9. The method according to claim 8, characterized in that When the system inertia of the power grid cannot suppress the second frequency change rate, adjusting the active power of at least one inverter in the power plant according to the power critical state and the second frequency change rate of the inverter in each power plant to maintain the connection between the power grid and the load end and each power plant includes: determining a target active power for the power grid based on the second frequency change rate; a difference between the target active power and the current active power output of the power grid can suppress the second frequency change rate; Determining at least one third inverter based on the target active power and the critical power state of each inverter in the power plant; the critical power state of the third inverter is the post-inflection point state, and the third inverter is capable of ensuring that a corresponding reactive power change value generated is no greater than a preset second threshold value while ensuring that the current active power output of the power grid is adjusted to the target active power; The active power of the third inverter is adjusted so that the current active power output of the power grid reaches the target active power.

10. The method according to claim 2, characterized in that The adjusting, based on the abnormal fluctuation data, the inverter power characteristics of each of the power plants, and the system inertia data of the power grid, at least one of the active power and the reactive power of at least one of the power plants to maintain the connection between the power grid and the load end and each of the power plants, includes: In a case where the abnormal fluctuation data includes the grid connection point voltage fluctuation data and the frequency fluctuation data, determining a third frequency change rate associated with the frequency fluctuation data, and a voltage ride-through occurrence ratio associated with the grid connection point voltage fluctuation data; the voltage ride-through occurrence ratio is used to represent a proportion of power plants in the plurality of power plants that experience voltage ride-through; calculating a frequency fluctuation impact weight and a voltage ride-through impact weight respectively according to the third frequency change rate and the voltage ride-through occurrence ratio; determining a power adjustment priority according to the frequency fluctuation impact weight and the voltage ride-through impact weight; the power adjustment priority is used to determine an adjustment order between active power adjustment and reactive power adjustment; According to the power adjustment priority, the inverter power characteristics of each power plant and the system inertia data of the power grid, the active power and reactive power of at least one of the power plants are adjusted to maintain the connection between the power grid and the load end and each power plant.

11. The method according to claim 1, wherein Before adjusting at least one of the active power and the reactive power of at least one of the power plants, the method further comprises: Obtaining environmental change parameters individually associated with each of the power plants within a preset future time period; Performing power prediction based on the environmental change parameters individually associated with each of the power plants to determine a predicted power change curve for the inverters in each power plant within the preset future time period; The predicted power variation curve of the inverter in each of the power plants within the preset future time period is determined as the inverter power characteristic of each of the power plants.

12. A coordinated control system for a power grid and associated power plants, characterized in that: Applied to a power grid, the power grid is connected to multiple power plants, and each power plant has a separate type of inverter; the system includes: An acquisition module, configured to acquire real-time grid load and the voltage at the connection point between each power plant and the grid; an operation monitoring module, configured to monitor the operation of the power grid based on the real-time power grid load and the plurality of grid connection point voltages, and determine abnormal fluctuation data of the power grid when at least one of the real-time power grid load and the plurality of grid connection point voltages triggers a preset abnormality determination rule; the abnormal fluctuation data is used to characterize the fluctuation corresponding to the real-time power grid load and at least one of the plurality of grid connection point voltages; a regulation module configured to adjust at least one of the active power and reactive power of at least one of the power plants based on the abnormal fluctuation data, the inverter power characteristics of each of the power plants, and the system inertia data of the power grid, so as to maintain the connection between the power grid and the load end and each of the power plants; the power characteristics being configured to characterize the dynamic relationship between the active power and reactive power of the inverter.

13. A power grid, characterized in that: The power grid is used to implement the coordinated control method of the power grid and the associated power plants as described in any one of claims 1-11.

14. An artificial intelligence device, characterized in that: The artificial intelligence device is used to implement the coordinated control method of the power grid and the associated power plant as described in any one of claims 1-11.

15. A computer-readable storage medium having a computer program stored thereon, characterized in that: When the program is executed by a processor, the coordinated control method of the power grid and the associated power plant described in any one of claims 1 to 11 is implemented.

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