Active power and primary frequency cooperative control method for wind farm based on direct control architecture

Abstract

The application discloses a kind of active and primary frequency modulation collaborative control method of wind farm based on direct access direct control architecture, comprising: by the joint constraint analysis to grid-connected point frequency, grid-connected point frequency rate of change, machine active power, rotor speed, pitch angle, converter current and collector line load rate, generate single machine adjustable interval, can obtain the real adjustment boundary of each wind turbine under current working condition, avoid the over-limit adjustment caused by single index distribution;Through line constraint correction and field level dynamic adjustable domain generation, the total adjustment demand of wind farm is divided into active collaborative control quantity and primary frequency modulation collaborative control quantity, which can consider planned output and frequency support;Through stage determination and speed recovery peak-shaving distribution, reduce the secondary power fluctuation caused by concentrated backfilling;Through consistency check, state compensation and degradation control, improve the control continuity and station operation stability under abnormal working condition.

Description

Technical Field

[0001] This invention relates to the technical field of wind farm grid connection control and power system frequency regulation control, and particularly to a wind farm active power and primary frequency regulation coordinated control method based on a direct acquisition and direct control architecture. Background Technology

[0002] With the continuous increase in the proportion of large-scale wind power grid connection, wind farms have gradually transformed from early power generation units mainly based on maximum power tracking to active control units that need to participate in grid active power regulation, primary frequency regulation, and safety and stability support. Existing wind farm control technologies usually revolve around grid connection point active power tracking, primary frequency regulation response, unit power distribution, and station-level coordinated control. The controlled objects are mostly composed of grid connection point frequency, station active power, and unit operating status.

[0003] For example, CN108306312B discloses a primary frequency regulation control method for wind farms. This method calculates the maximum active power generated by each turbine and the maximum active power generated by the entire wind farm based on the grid connection frequency, the actual active power at the wind farm outlet, and the wind speed of each turbine. When the frequency fluctuation exceeds the dead zone, it establishes the relationship between frequency and active power through droop control, and then distributes the active power of the wind farm in combination with the AGC input. This method can form a primary frequency regulation control path for wind farms, but its focus is on reserve capacity estimation and reference power distribution. It still does not adequately consider the joint constraints between turbine rotor speed, pitch angle, converter current, and the transmission capacity of the collector line.

[0004] For example, CN102496966A discloses a power optimization control substation for grid-connected operation of a wind farm. This scheme consists of a workstation, a coordination controller, and a power optimization controller. In active power control, it meets the requirements of direct acquisition and control and data homogeneity. Based on dispatching instructions, it supplements the active power change of primary frequency regulation to form the final active power instruction. This scheme can improve the unified dispatching capability of wind farms in grid-connected operation. However, its active power control and primary frequency regulation control are mainly reflected in the superposition and allocation of the target level of the wind farm. It does not further establish a detailed field-level dynamic control boundary around the single unit regulation boundary, the load constraint of the collector line, and the coupling constraint of multiple physical quantities of the unit.

[0005] For example, CN116505556A discloses a wind farm power control system and method based on primary frequency regulation for wind farm power control in primary frequency regulation scenarios. It uses model predictive control to predict and control the output power of wind turbines and combines power output classification for control adjustment. This scheme can improve the accuracy of power prediction and regulation to a certain extent, but its focus is still on power prediction modeling and output classification. It does not provide sufficient constraints on the stage connection between kinetic energy release, support attenuation, and energy recovery after primary frequency regulation, as well as the peak-shifting treatment during the speed recovery process of multiple units. At the same time, it lacks a degradation control path that is linked with the dynamic boundary of the farm for abnormal operating conditions of the field control chain, such as inconsistent measurement time scales, power direction conflicts, and abnormal command feedback.

[0006] It is evident that existing active power and primary frequency regulation control technologies for wind farms generally suffer from the following problems: First, the control boundary of a single unit is often determined by a single reserve or a single target power, lacking a joint convergence boundary based on rotor speed, pitch angle, converter current, and line load rate; second, the control objectives of the wind farm are often developed separately based on active power plans or frequency support, lacking a unified decomposition mechanism for the dynamic adjustable domain at the farm level; third, the recovery process after primary frequency regulation often remains at the level of routine callbacks, lacking a phased allocation based on the staggered peak order of speed recovery; and fourth, the handling of measurement anomalies and feedback anomalies often remains at the level of alarms or simple retransmissions, lacking a closed-loop control mechanism for state compensation, adjustable domain contraction, and reconstruction of degraded control commands.

[0007] In summary, given the problems of existing wind farm grid-connected power control, primary frequency regulation control, and related coordinated control technologies, such as coarse single-unit adjustment boundaries, unclear farm-level coordination boundaries, easy introduction of new power disturbances during the recovery phase, and insufficient stability of the control chain under abnormal operating conditions, this invention proposes a wind farm active power and primary frequency regulation coordinated control method based on a direct acquisition and control architecture. By constructing a single-unit adjustable range, a farm-level dynamic adjustable domain, a phased coordinated allocation mechanism, and a degradation control mechanism under abnormal conditions, this invention solves the coordinated control problem of wind farms in the scenario of active power plan tracking and primary frequency regulation in parallel. Summary of the Invention

[0008] The purpose of this section is to outline some aspects of the embodiments of the present invention and to briefly introduce some preferred embodiments. Some simplifications or omissions may be made in this section, as well as in the abstract and title of the present application, to avoid obscuring the purpose of this section, the abstract and title of the invention. Such simplifications or omissions shall not be used to limit the scope of the present invention.

[0009] In view of the aforementioned existing problems, the present invention is proposed.

[0010] To solve the above-mentioned technical problems, the present invention provides the following technical solution: As described in this invention, the wind farm active power and primary frequency regulation coordinated control method based on direct acquisition and direct control architecture includes: determining the speed regulation margin, pitch regulation margin, converter current regulation margin, and active power regulation margin of each wind turbine based on the measured values ​​of grid connection point frequency, grid connection point frequency change rate, active power at the turbine terminal, rotor speed, pitch angle, converter current, and collector line load rate; and generating a single-unit adjustable range by taking the limiting boundary of each regulation margin. Line constraint corrections are performed based on the adjustable range of each unit and the measured load rate of the collection line. The field-level dynamic adjustable domain is generated by combining the current active power planned value of the wind farm. The total regulation demand of the wind farm is divided into active power coordinated control quantity and primary frequency regulation coordinated control quantity. Based on the measured values ​​of the grid connection point frequency, the measured value of the grid connection point frequency change rate, the measured value of the rotor speed, and the primary frequency regulation coordinated control quantity, it is determined whether each wind turbine is in the kinetic energy release stage, the support attenuation stage, or the energy recovery stage. The active power coordinated control quantity and the primary frequency regulation coordinated control quantity are allocated according to the stage sequence and the speed recovery staggered order to generate a set of unit control commands. The measurement timescale, power direction, and adjustment boundary corresponding to the set of unit control commands are checked for consistency. When the check passes, the set of unit control commands is issued. When the check fails or the unit control feedback is abnormal, the abnormal measurement value is compensated for and the field-level dynamic adjustable domain is shrunk to generate a set of degraded control commands.

[0011] The beneficial effects of this invention are as follows: By conducting joint constraint analysis on grid connection point frequency, grid connection point frequency change rate, active power at the turbine terminal, rotor speed, pitch angle, converter current, and collector line load rate, this invention generates an adjustable range for each wind turbine, enabling the determination of the true adjustment boundary of each wind turbine under the current operating conditions and avoiding over-limit adjustments caused by the allocation of a single indicator. Through line constraint correction and the generation of a dynamic adjustable domain at the farm level, the total adjustment demand of the wind farm is broken down into active power coordinated control quantity and primary frequency regulation coordinated control quantity, which can take into account both planned output and frequency support. Through stage judgment and speed recovery staggered allocation, the secondary power fluctuations caused by centralized compensation are reduced. Through consistency verification, state compensation, and degradation control, the control continuity and farm operation stability under abnormal operating conditions are improved. Attached Figure Description

[0012] To more clearly illustrate the technical solutions of the embodiments of the present invention, the drawings used in the description of the embodiments will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort. Wherein: Figure 1This is a flowchart illustrating the wind farm active power and primary frequency regulation coordinated control method based on a direct acquisition and control architecture, as shown in this invention. Detailed Implementation

[0013] To make the above-mentioned objects, features and advantages of the present invention more apparent and understandable, the specific embodiments of the present invention will be described in detail below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments.

[0014] Based on the embodiments of this invention, all other embodiments obtained by those skilled in the art without inventive effort should fall within the scope of protection of this invention.

[0015] Many specific details are set forth in the following description in order to provide a full understanding of the invention. However, the invention may also be practiced in other ways different from those described herein, and those skilled in the art can make similar extensions without departing from the spirit of the invention. Therefore, the invention is not limited to the specific embodiments disclosed below.

[0016] According to an embodiment of the present invention, in combination Figure 1 The flowchart shown illustrates a method for coordinated control of active power and primary frequency regulation in wind farms based on a direct acquisition and control architecture, specifically including the following steps: S1. Based on the measured values ​​of grid connection point frequency, grid connection point frequency change rate, active power at the turbine terminals, rotor speed, pitch angle, converter current, and collector line load rate, determine the speed regulation margin, pitch regulation margin, converter current regulation margin, and active power regulation margin for each wind turbine unit, and generate the adjustable range for each unit by taking the limiting boundaries of each regulation margin. Note that the following should be noted in this step: In this embodiment, the measured values ​​of grid connection point frequency, grid connection point frequency change rate, turbine active power, rotor speed, pitch angle, converter current, and collector line load rate are all directly collected by the wind farm's direct acquisition and control master station. Specifically, the grid connection point frequency measurement is provided by the frequency measurement device located at the grid connection point of the booster station; the grid connection point frequency change rate measurement is generated within the master station based on the direction and magnitude of change of the frequency measurement values ​​between two consecutive measurement cycles, after the frequency measurement device continuously provides the frequency change results for adjacent measurement periods; the turbine active power measurement is provided by the active power measurement unit on the turbine side or grid side of each wind turbine; the rotor speed measurement is provided by the generator speed measurement unit; the pitch angle measurement is provided by the angle detection unit of the pitch servo system; the converter current measurement is provided by the AC side current sampling unit of the converter; and the collector line load rate measurement is calculated by combining the current, voltage, and rated transmission capacity at the corresponding collector line's starting end.

[0017] S1.1. Determine the power increase margin based on the difference between the measured rotor speed and the upper limit of the speed; determine the power decrease margin based on the difference between the measured rotor speed and the lower limit of the speed; determine the power increase margin based on the difference between the measured pitch angle and the upper limit of the pitch; determine the power decrease margin based on the difference between the measured pitch angle and the lower limit of the pitch; determine the power increase margin based on the difference between the measured converter current and the upper limit of the current; determine the power decrease margin based on the difference between the measured converter current and the lower limit of the current. The basic power increase margin is determined based on the difference between the rated active power of the unit and the measured active power at the generator terminal; the basic power reduction margin is determined based on the difference between the measured active power at the generator terminal and the minimum stable active power of the unit; the remaining transmission margin of the line is determined based on the difference between the maximum allowable transmission power of the corresponding collector line and the current transmission power of the line, combined with the measured load rate of the collector line; the smaller value between the basic power increase margin and the remaining transmission margin of the line is determined as the active power increase margin; the basic power reduction margin is determined as the active power reduction margin. Among them, the speed increase margin and the speed decrease margin constitute the speed regulation margin, the pitch increase margin and the pitch decrease margin constitute the pitch regulation margin, the current increase margin and the current decrease margin constitute the converter current regulation margin, and the active power increase margin and the active power decrease margin constitute the active power regulation margin.

[0018] In a preferred embodiment, the upper and lower limits of the rotational speed, pitch, current, rated active power, minimum stable active power, and maximum allowable transmission power are all derived from the combined calibration results of wind turbine type parameters, grid connection test records, and power station electrical design parameters. Specifically, the upper and lower limits of the rotational speed are determined based on the normal operating speed range given by the turbine manufacturer and verified in conjunction with the stable operating range in the long-term operating records of the turbine. The upper and lower limits of the pitch are determined based on the mechanical travel range of the pitch actuator and the pitch adjustment range under normal power generation conditions. The upper and lower limits of the current are determined based on the smaller stable boundary between the converter's continuous operating current capability and short-term allowable current capability. The rated active power of the turbine is determined based on the nameplate capacity of the turbine. The minimum stable active power of the turbine is determined based on the minimum stable output that does not cause continuous oscillations or exit the grid connection state during grid-connected operation. The maximum allowable transmission power is determined based on the conductor cross-section of the collector line, allowable temperature rise, long-term current carrying capacity of the cable or overhead line, and the power station electrical verification results.

[0019] For example, for a doubly-fed or full-power wind turbine with a single unit rated capacity of 5MW, the upper limit of the speed can be taken as 1.25pu, and the lower limit of the speed can be taken as 0.72pu; the upper limit of the pitch can be taken as 25∘, and the lower limit of the pitch can be taken as 0∘; the upper limit of the current can be taken as 1.10pu of the rated current, and the lower limit of the current can be taken as 0.10pu; the rated active power of the unit can be taken as 5MW; the minimum stable active power of the unit can be taken as 0.50MW; for a branch connected to a 35 kV collector system, the maximum allowable transmission power can be taken as 28 MW.

[0020] S1.2. Based on the current operating point corresponding to the rotor speed measurement, the ratio of the active power difference between adjacent speed points on both sides of the current operating point to the speed difference is taken to determine the change in power per unit speed. The product of the speed increase margin and the change in power per unit speed is determined as the speed increase boundary, and the product of the speed decrease margin and the change in power per unit speed is determined as the speed decrease boundary. Based on the current operating point corresponding to the pitch angle measurement, the ratio of the active power difference between adjacent pitch points on both sides of the current operating point to the pitch difference is taken to determine the change in power per unit pitch. The product of the pitch increase margin and the change in power per unit pitch is taken as the change in power per unit pitch. The product of the changes is determined as the pitch power increase boundary, and the product of the pitch power decrease margin and the unit pitch power change is determined as the pitch power decrease boundary. Based on the current operating point corresponding to the converter current measurement, the ratio of the active power difference to the current difference between adjacent current points on both sides of the current operating point is taken to determine the unit current power change. The product of the current power increase margin and the unit current power change is determined as the current power increase boundary, and the product of the current power decrease margin and the unit current power change is determined as the current power decrease boundary. The active power increase margin is determined as the active power increase boundary, and the active power decrease margin is determined as the active power decrease boundary. Among them, the minimum value among the power increase boundary of speed, power increase boundary of pitch, power increase boundary of current and power increase boundary is taken as the power increase limit boundary, and the minimum value among the power decrease boundary of speed, power decrease boundary of pitch, power decrease boundary of current and power decrease boundary is taken as the power decrease limit boundary.

[0021] In this embodiment, the current operating point corresponding to the rotor speed measurement value refers to the point where the rotor speed measurement value falls on the unit's power-speed characteristic curve at the current moment; the current operating point corresponding to the pitch angle measurement value refers to the point where the pitch angle measurement value falls on the unit's power-pitch characteristic curve at the current moment; the current operating point corresponding to the converter current measurement value refers to the point where the converter current measurement value falls on the unit's power-current characteristic curve at the current moment; all of the above current operating points are obtained by the direct acquisition and control master station after receiving the measurement values ​​and calling the stored unit static calibration curve table for interval positioning.

[0022] Specifically, the main station first selects the corresponding speed-power comparison table, pitch-power comparison table, and current-power comparison table according to the unit model. Then, it substitutes the rotor speed measurement value, pitch angle measurement value, and converter current measurement value into the corresponding comparison table, finds the lower point that is less than or equal to the current measurement value and the upper point that is greater than the current measurement value, and regards the interval between the current measurement value and these two points as the interval where the current operating point is located.

[0023] S1.3. Based on the power increase limit boundary, power decrease limit boundary and active power measurement value at the turbine terminal, determine the adjustable range of the corresponding wind turbine unit. The upper boundary of the adjustable range of a single unit is the sum of the active power measurement value at the unit end and the power increase limit boundary, and the lower boundary of the adjustable range of a single unit is the difference between the active power measurement value at the unit end and the power decrease limit boundary.

[0024] Preferably, by taking the above steps, various adjustment margins are first formed, then various power boundaries are formed, and the boundary with the strictest restriction is taken as the final constraint of a single unit. This allows the adjustable range of a single unit to correspond one-to-one with the current unit status and line status, thereby improving the executability of subsequent field-level adjustment commands, reducing the probability of command overruns and line congestion, and providing a unified boundary basis for the joint allocation of active power control and primary frequency regulation control.

[0025] S2. Based on the adjustable range of each individual unit and the measured load rate of the collector lines, line constraints are corrected, and a field-level dynamic adjustable domain is generated in conjunction with the current active power planned value of the wind farm. The total regulation demand of the wind farm is then broken down into active power coordinated control quantities and primary frequency regulation coordinated control quantities. It should be noted that in this step: S2.1. Based on the measured load rate of the corresponding collector lines for each wind turbine, determine the remaining transmission margin of the corresponding collector lines. Compare the upper boundary of the adjustable range of each wind turbine connected to the same collector line with the remaining transmission margin of the line. If the upper boundary of the adjustable range of the single turbine is greater than the remaining transmission margin of the line, determine the remaining transmission margin of the line as the corrected upper boundary of the corresponding wind turbine. If the upper boundary of the adjustable range of the single turbine is less than or equal to the remaining transmission margin of the line, determine the upper boundary of the adjustable range of the single turbine as the corrected upper boundary of the corresponding wind turbine. Determine the lower boundary of the adjustable range of each wind turbine as the corrected lower boundary of the corresponding wind turbine, and generate the corrected adjustable range of each wind turbine.

[0026] In a preferred embodiment, the method for determining the remaining transmission margin of the corresponding collector line is as follows: when the measured load rate of the collector line is less than 70%, the difference between the maximum allowable transmission power and the current transmission power of the line is directly determined as the remaining transmission margin of the line; when the measured load rate of the collector line is between 70% and 90%, the difference is multiplied by a tightening coefficient to determine the remaining transmission margin of the line, and the tightening coefficient is 0.90; when the measured load rate of the collector line is greater than 90%, the difference is further reduced according to the high load tightening rule to determine the remaining transmission margin of the line, and the tightening coefficient is 0.70.

[0027] S2.2. Accumulate the upper boundary of the correction for each adjustable range of a single unit to generate the field-level power increase boundary; accumulate the lower boundary of the correction for each adjustable range of a single unit to generate the field-level power decrease boundary; generate the field-level dynamic adjustable domain based on the field-level power increase boundary, the field-level power decrease boundary and the current active power planned value of the wind farm. Among them, the upper boundary of the field-level dynamic adjustable domain is the sum of the current active power planned value of the wind farm and the field-level power increase boundary, and the lower boundary of the field-level dynamic adjustable domain is the difference between the current active power planned value of the wind farm and the field-level power decrease boundary.

[0028] In this embodiment, the current active power planned value of the wind farm is given by the current period planned output instruction issued by the wind farm energy management system. The direct acquisition and control master station obtains the planned output value corresponding to the current control cycle from the wind farm dispatch interface and determines this value as the current active power planned value of the wind farm. This value can come from the day-ahead planned curve, intraday rolling correction curve or the currently effective value in the current period active power planned instruction issued by the regional dispatch.

[0029] S2.3. Determine the wind farm frequency support requirement based on the difference between the rated frequency and the grid connection point frequency measurement, and in conjunction with the difference between zero and the grid connection point frequency change rate measurement; determine the wind farm planned regulation requirement based on the difference between the target power output value of the wind farm and the current active power planned value of the wind farm; add the wind farm frequency support requirement and the wind farm planned regulation requirement together to generate the total wind farm regulation requirement.

[0030] In a preferred embodiment, the rated frequency is determined by the grid connection operation standard, such as 50 Hz; the target output value of the wind farm is jointly determined by the superior dispatch instruction, the wind farm's current operating plan, and the primary frequency regulation participation status; specifically, within the control cycle of the wind farm participating in primary frequency regulation, the target output value of the wind farm can be composed of the wind farm's current active power plan value and the current time-based dispatch additional correction instruction; when the superior dispatch does not issue an additional correction instruction, the target output value of the wind farm can be directly taken as the wind farm's current active power plan value; when the dispatch system issues a temporary increase or decrease instruction, the corrected target output value of the wind farm is determined as the target output value of the wind farm.

[0031] For example, if the current active power planned value of the wind farm is 72MW, and the dispatch system requires the station to generate an additional 3MW at the current moment, then the target output value of the station can be taken as 75MW.

[0032] In a preferred embodiment, the frequency support requirement of the wind farm is determined as follows: when the measured frequency at the grid connection point is lower than the rated frequency, and the measured rate of change of the grid connection point still shows a continuous decrease in frequency, the frequency support requirement of the wind farm is determined as an increase in power demand, and the greater the frequency deviation and the faster the frequency decreases, the greater the frequency support requirement of the wind farm; when the measured frequency at the grid connection point is higher than the rated frequency, and the measured rate of change of the grid connection point shows that the frequency is still rising, the frequency support requirement of the wind farm is determined as a decrease in power demand, and the greater the frequency deviation and the faster the frequency rises, the greater the frequency support requirement of the wind farm; when the measured frequency at the grid connection point is close to the rated frequency and the measured rate of change of the grid connection point is close to zero, the frequency support requirement of the wind farm is determined to be zero.

[0033] In a preferred embodiment, the wind farm's planned adjustment demand is determined as follows: the target power output of the wind farm is compared with the current planned active power output of the wind farm. If the target power output of the wind farm is higher than the current planned active power output of the wind farm, the difference between the two is determined as the wind farm's planned adjustment demand in the direction of increasing power output. If the target power output of the wind farm is lower than the current planned active power output of the wind farm, the difference between the two is determined as the wind farm's planned adjustment demand in the direction of decreasing power output. If the two are the same, the wind farm's planned adjustment demand is determined to be zero.

[0034] S2.4. Compare the total regulation demand of the wind farm with the upper and lower boundaries of the farm-level dynamic adjustable domain: When the total regulation demand of the wind farm is less than or equal to the upper boundary of the field-level dynamic adjustable domain and greater than or equal to the lower boundary of the field-level dynamic adjustable domain, the frequency support demand of the wind farm is determined as the primary frequency regulation coordinated control quantity, and the difference between the total regulation demand of the wind farm and the primary frequency regulation coordinated control quantity is determined as the active power coordinated control quantity. When the total regulation demand of the wind farm is greater than the upper boundary of the dynamic adjustable domain at the farm level, the upper boundary of the dynamic adjustable domain at the farm level is determined as the total regulation boundary. The frequency support demand of the wind farm is compared with the total regulation boundary. When the frequency support demand of the wind farm is greater than or equal to the total regulation boundary, the total regulation boundary is determined as the primary frequency regulation coordinated control quantity, and zero is determined as the active power coordinated control quantity. When the frequency support demand of the wind farm is less than the total regulation boundary, the frequency support demand of the wind farm is determined as the primary frequency regulation coordinated control quantity, and the difference between the total regulation boundary and the primary frequency regulation coordinated control quantity is determined as the active power coordinated control quantity. When the total regulation demand of the wind farm is less than the lower boundary of the dynamic adjustable domain at the farm level, the lower boundary of the dynamic adjustable domain at the farm level is determined as the total regulation boundary. The frequency support demand of the wind farm is compared with the total regulation boundary. When the frequency support demand of the wind farm is less than or equal to the total regulation boundary, the total regulation boundary is determined as the primary frequency regulation coordinated control quantity, and zero is determined as the active power coordinated control quantity. When the frequency support demand of the wind farm is greater than the total regulation boundary, the frequency support demand of the wind farm is determined as the primary frequency regulation coordinated control quantity, and the difference between the total regulation boundary and the primary frequency regulation coordinated control quantity is determined as the active power coordinated control quantity.

[0035] S3. Based on the measured values ​​of the grid connection point frequency, the grid connection point frequency change rate, the rotor speed, and the primary frequency regulation coordinated control quantity, determine whether each wind turbine is in the kinetic energy release stage, the support attenuation stage, or the energy recovery stage. Then, allocate the active power coordinated control quantity and the primary frequency regulation coordinated control quantity according to the stage sequence and the speed recovery peak-shifting order, generating a set of turbine control commands. Note that the following should be noted in this step: S3.1 Calculate the first difference between the rated frequency and the measured value of the grid connection point frequency, the second difference between zero and the measured value of the rate of change of the grid connection point frequency, and the third difference between the lower limit of the speed and the measured value of the rotor speed, and compare the first difference, the second difference, and the third difference with zero respectively: When the first difference is greater than zero, the second difference is greater than zero, and the third difference is less than zero, the corresponding wind turbine is determined to be in the kinetic energy release stage. When the first difference is greater than zero, the second difference is less than or equal to zero, and the third difference is less than zero, the corresponding wind turbine is determined to be in the support attenuation stage. When the first difference is less than or equal to zero or the third difference is greater than or equal to zero, the corresponding wind turbine is determined to be in the energy recovery phase.

[0036] It should be noted that the kinetic energy release stage refers to the stage where the grid connection point frequency is lower than the rated frequency and continues to decrease, while the rotor speed measurement value is still higher than the lower limit of the speed. During this stage, the wind turbine still has the condition to release power from the rotor rotation kinetic energy to support the grid frequency, so the primary frequency regulation coordinated control quantity can be allocated to the power increase direction first.

[0037] Furthermore, the support decay stage refers to the period when the grid connection point frequency is still lower than the rated frequency, but the measured value of the grid connection point frequency change rate no longer shows a continuous decline, indicating that the frequency drop trend has begun to weaken. At this time, the wind turbine has completed the kinetic energy release of the previous period, and the rotor speed is approaching the lower limit of the speed. Continuing to maintain the original primary frequency regulation output will further compress the speed safety margin. Therefore, it is necessary to make a decreasing correction to the primary frequency regulation component.

[0038] In this embodiment, the energy recovery stage refers to the period when the grid connection frequency has recovered to near or above the rated frequency, or the rotor speed measurement value has approached the lower limit of the speed. At this time, the control focus of the unit shifts to speed recovery and internal energy balance of the unit, and the additional output or additional load reduction of the previous stage needs to be gradually withdrawn in the order of peak shifting.

[0039] S3.2 When the primary frequency regulation coordinated control quantity is greater than zero, the primary frequency regulation allocation direction is determined as the power increase direction, and the primary frequency regulation coordinated control quantity is allocated based on the ratio of the difference between the upper boundary of the adjustable range of each wind turbine unit and the active power measurement value at the turbine end to the sum of the corresponding differences of all wind turbine units. When the primary frequency regulation coordinated control quantity is less than zero, the primary frequency regulation allocation direction is determined as the power decrease direction, and the primary frequency regulation coordinated control quantity is allocated based on the ratio of the difference between the active power measurement value at the turbine end and the lower boundary of the adjustable range of each wind turbine unit to the sum of the corresponding differences of all wind turbine units. When the active power coordinated control quantity is greater than zero, the active power allocation direction is determined as the power increase direction, and the active power coordinated control quantity is allocated based on the ratio of the corresponding differences at the upper boundary. When the active power coordinated control quantity is less than zero, the active power allocation direction is determined as the power decrease direction, and the active power coordinated control quantity is allocated based on the ratio of the corresponding differences at the lower boundary.

[0040] In a preferred embodiment, the specific method for allocating the primary frequency regulation coordinated control quantity is as follows: first, the allocation direction is determined according to the positive and negative directions of the primary frequency regulation coordinated control quantity, and then the allocation is carried out proportionally according to the current adjustable space ratio of each wind turbine unit; when the primary frequency regulation coordinated control quantity is greater than zero, the difference between the upper boundary of the adjustable range of each wind turbine unit and the active power measurement value at the turbine end is taken as the current available space for power increase of the unit, and then the available space for power increase of each unit is summarized to obtain the total available space for power increase of all units in the station, and then the primary frequency regulation coordinated control quantity is allocated according to the ratio of the available space for power increase of each unit to the total amount; when the primary frequency regulation coordinated control quantity is less than zero, the difference between the active power measurement value at the turbine end and the lower boundary of the adjustable range of each wind turbine unit is taken as the current available space for power reduction of the unit, and then the primary frequency regulation coordinated control quantity is allocated according to the ratio of the available space for power reduction of each unit to the total available space for power reduction of the whole.

[0041] Preferably, the allocation method of the active power coordinated control quantity in this embodiment is consistent with that of the primary frequency regulation coordinated control quantity, except that the allocation object is changed to the active power coordinated control quantity. That is, when the active power coordinated control quantity is greater than zero, it is allocated according to the proportion of available space for each wind turbine to increase power; when the active power coordinated control quantity is less than zero, it is allocated according to the proportion of available space for each wind turbine to decrease power.

[0042] S3.3 During the kinetic energy release phase, the allocated primary frequency regulation coordinated control quantity is added to the allocated active power coordinated control quantity to generate the corresponding stage control quantity for the wind turbine unit. During the support attenuation phase, the allocated primary frequency regulation coordinated control quantity is progressively corrected according to the ratio of the difference between the rotor speed measurement value and the lower speed limit to the sum of the corresponding differences for all wind turbine units in the support attenuation phase. The corrected primary frequency regulation coordinated control quantity is then added to the allocated active power coordinated control quantity to generate the corresponding stage control quantity for the wind turbine unit. During the energy recovery phase, the speed recovery staggered order for each wind turbine unit is determined according to the order of the difference between the rotor speed measurement value and the lower speed limit from small to large. The stage control quantity is then progressively reduced to zero according to the speed recovery staggered order to generate the unit control command set for each wind turbine unit.

[0043] In a preferred embodiment, the reduction correction method is as follows: during the support decay phase, the original primary frequency control component of the kinetic energy release phase is no longer maintained. Instead, the allocated primary frequency control collaborative control quantity is differentially withdrawn based on the difference between the current rotor speed measurement value and the lower speed limit of each wind turbine in the support decay phase. Specifically, the sum of the corresponding differences for all wind turbines in the support decay phase is first calculated, and then the ratio of the difference between the rotor speed measurement value and the lower speed limit of each turbine to the sum is used as the basis for the primary frequency control retention coefficient of that turbine. The larger the difference, the farther the turbine is from the lower speed limit, and the more its primary frequency control component is retained; the smaller the difference, the closer the turbine is to the lower speed limit, and the more its primary frequency control component is withdrawn.

[0044] Preferably, the control quantity can be gradually reduced in fixed steps within adjacent control cycles. For example, the control quantity of the previous cycle can be reduced by 20% to 0% in each control cycle until the control quantity of the corresponding unit is reduced to zero.

[0045] In a preferred embodiment, the set of unit control commands includes at least the unit identifier, control power value, control direction identifier, control phase identifier, command generation time stamp, command issuance time stamp, and command identifier for each wind turbine. The unit identifier uniquely corresponds to a specific wind turbine within the site. The control power value represents the target active power that the unit should achieve within the current control cycle. The control direction identifier indicates whether the current command is an increase or decrease command. The control phase identifier indicates whether the unit is currently in the kinetic energy release phase, support attenuation phase, or energy recovery phase. The command generation and issuance time stamps are used for subsequent consistency verification and receipt checking. The command identifier establishes a one-to-one correspondence between the master station and the unit controller within the current control cycle.

[0046] S4. Perform consistency verification on the measurement timescale, power direction, and adjustment boundary corresponding to the unit control command set. If the verification passes, issue the unit control command set. If the verification fails or the unit control feedback is abnormal, perform state compensation on the abnormal measurement values ​​and shrink the field-level dynamic adjustable domain to generate a degraded control command set. Note that the following points should be noted in this step: S4.1 Compare the measurement timescales corresponding to each wind turbine in the unit control command set with the measurement timescales corresponding to the grid connection point frequency measurement, grid connection point frequency change rate measurement, turbine terminal active power measurement, rotor speed measurement, pitch angle measurement, converter current measurement, and collector line load rate measurement. If all measurement timescales are the same, the measurement timescale consistency check is determined to be passed. If at least one measurement timescale is different, the measurement timescale consistency check is determined to be failed. S4.2. Subtract the control power value corresponding to the unit control command set from the active power measurement value at the corresponding wind turbine terminal to generate the control power change value; add the primary frequency regulation coordinated control quantity to the active power coordinated control quantity to generate the total control quantity; when the total control quantity is greater than zero and the control power change value is greater than zero, or when the total control quantity is less than zero and the control power change value is less than zero, the power direction consistency check is determined to be passed; when the total control quantity is greater than zero and the control power change value is less than or equal to zero, or when the total control quantity is less than zero and the control power change value is greater than or equal to zero, the power direction consistency check is determined to be failed; subtract the control power value corresponding to the unit control command set from the active power measurement value at the corresponding wind turbine terminal to generate the control power change value; add the primary frequency regulation coordinated control quantity to the active power coordinated control quantity to generate the total control quantity; when the total control quantity is greater than zero and the control power change value is greater than or equal to zero, the power direction consistency check is determined to be failed; subtract the control power value corresponding to the unit control command set from the active power measurement value at the corresponding wind turbine terminal to generate the control power change value ... The adjustment boundary consistency check is determined to be passed when comparing the adjustable range of a single wind turbine unit with the dynamic adjustable range of the wind farm. If the control power value is less than or equal to the upper boundary of the adjustable range of a single wind turbine unit and greater than or equal to the lower boundary of the adjustable range of a single wind turbine unit, and the sum of the control power values ​​of all wind turbine units is less than or equal to the upper boundary of the dynamic adjustable range of the wind farm and greater than or equal to the lower boundary of the dynamic adjustable range of the wind farm. If the control power value is greater than the upper boundary of the adjustable range of a single wind turbine unit or less than the lower boundary of the adjustable range of a single wind turbine unit, or the sum of the control power values ​​of all wind turbine units is greater than the upper boundary of the dynamic adjustable range of the wind farm or less than the lower boundary of the dynamic adjustable range of the wind farm, the adjustment boundary consistency check is determined to be failed.

[0047] In a preferred embodiment, the control power value is obtained as follows: for units in the power increase direction, the control power value is the current active power measurement value at the generator terminal plus the corresponding stage control amount; for units in the power decrease direction, the control power value is the current active power measurement value at the generator terminal minus the corresponding stage control amount.

[0048] S4.3 When the consistency checks of measurement timescale, power direction, and adjustment boundary are all passed, a set of unit control commands is issued, and a set of unit control receipts returned by the corresponding wind turbine is received. The command identifiers in the set of unit control receipts are compared with the command identifiers in the set of unit control commands, the executed power value in the set of unit control receipts is compared with the control power value in the set of unit control commands, and the return timescale in the set of unit control receipts is compared with the issuance timescale in the set of unit control commands. If the command identifiers are different, the executed power value is not equal to the control power value, or the return timescale is earlier than the issuance timescale, the unit control receipt is determined to be abnormal.

[0049] In a preferred embodiment, the unit control feedback set includes the unit identifier, instruction identifier, executed power value, return time stamp, and execution status identifier returned by each wind turbine; wherein, the instruction identifier specifically includes a unique number of the instruction received by the unit within the current control cycle, which corresponds one-to-one with the corresponding instruction identifier in the unit control instruction set; the executed power value is fed back to the site master station by the wind turbine controller after receiving the control power value and completing the internal power instruction conversion, and the executed power value can be taken as the current target value of the active power closed-loop controller at the turbine end.

[0050] S4.4 When at least one consistency check fails or the unit control feedback is abnormal, take the average of the valid measurement value corresponding to the abnormal measurement value at the previous moment and the current measurement value of the same type of adjacent wind turbine, generate a compensation measurement value, and replace the abnormal measurement value with the compensation measurement value to generate a state compensation result.

[0051] In a preferred embodiment, the compensation measurement value is generated as follows: for wind turbines that fail the consistency check or have abnormal control feedback, firstly extract the valid measurement value corresponding to the abnormal measurement value at the previous moment, then extract the similar measurement values ​​of adjacent wind turbines connected to the same collection line and with similar current operating conditions, calculate their average value, and then synthesize the valid measurement value at the previous moment and the average value of the similar measurement values ​​of adjacent wind turbines in an equal weighted manner to obtain the compensation measurement value.

[0052] As an example, if there are at least two adjacent wind turbine units, the average value of the two or three adjacent wind turbine units will be taken first; if there is only one adjacent wind turbine unit available, the same type of measurement value of that unit will be combined with the valid measurement value of the previous moment.

[0053] S4.5. Based on the state compensation results, redetermine the adjusted single-unit adjustable range of each wind turbine, and redetermine the upper and lower boundaries of the contracted field-level dynamic adjustable domain according to each adjusted single-unit adjustable range; add the primary frequency regulation coordinated control quantity and the active power coordinated control quantity to generate the total control quantity before correction; when the total control quantity before correction is greater than the upper boundary of the contracted field-level dynamic adjustable domain, determine the upper boundary of the contracted field-level dynamic adjustable domain as the degraded control power value; when the total control quantity before correction is less than the lower boundary of the contracted field-level dynamic adjustable domain, determine the lower boundary of the contracted field-level dynamic adjustable domain as the degraded control power value; when the total control quantity before correction is less than or equal to the upper boundary of the contracted field-level dynamic adjustable domain and greater than or equal to the lower boundary of the contracted field-level dynamic adjustable domain, determine the total control quantity before correction as the degraded control power value.

[0054] In a preferred embodiment, the method for re-determining the corrected single-unit adjustable range of each wind turbine based on the state compensation result is as follows: For wind turbines that have experienced anomalies, the abnormal measurement values ​​originally calculated in steps S1 and S2 are replaced with the state compensation results. Then, the speed adjustment margin, pitch adjustment margin, converter current adjustment margin, and active power adjustment margin are re-determined according to the same processing order from steps S1.1 to S1.3. After that, the power increase limit boundary and power decrease limit boundary are regenerated, and the single-unit adjustable range of the wind turbine is re-formed with the replaced active power measurement value at the turbine end. Subsequently, the method is followed according to steps... Following the same processing sequence as S2.1, the newly formed adjustable range of a single unit is compared with the remaining transmission margin of the corresponding collection line to obtain the corrected adjustable range of the single unit for that wind turbine. For wind turbines that have not experienced any abnormalities, the previously determined corrected adjustable range of a single unit is retained. Then, the corrected adjustable ranges of all wind turbines are re-aggregated, the upper boundary of the correction is accumulated to obtain the contracted field-level power increase boundary, the lower boundary of the correction is accumulated to obtain the contracted field-level power reduction boundary, and the upper and lower boundaries of the contracted field-level dynamic adjustable domain are regenerated based on the current active power planned value of the wind farm.

[0055] S4.6 When the degraded control power value is greater than zero, the degraded control power value is allocated according to the ratio of the difference between the upper boundary of the corrected single-unit adjustable range of each wind turbine and the active power measurement value at the turbine end to the sum of the corresponding differences of all wind turbines, generating a degraded control power component for each wind turbine; when the degraded control power value is less than zero, the degraded control power value is allocated according to the ratio of the difference between the active power measurement value at the turbine end and the lower boundary of the corrected single-unit adjustable range of each wind turbine to the sum of the corresponding differences of all wind turbines, generating a degraded control power component for each wind turbine; the degraded control power component of each wind turbine is added to the active power measurement value at the turbine end of the corresponding wind turbine to generate a set of degraded control commands for each wind turbine.

[0056] In a preferred embodiment, the specific method for allocating the degraded control power value is as follows: When the degraded control power value is greater than zero, firstly, the sum of the differences between the upper boundary of the corrected single-unit adjustable range of all wind turbine units and the active power measurement value at the turbine terminal is calculated. Then, the ratio of the corresponding difference of each wind turbine unit to the total sum is used as the power increase allocation weight of that unit in degraded mode. After that, the degraded control power value is allocated to each wind turbine unit according to this weight, generating the degraded control power component of each wind turbine unit. When the degraded control power value is less than zero, firstly, the sum of the differences between the active power measurement value at the turbine terminal of all wind turbine units and the lower boundary of the corrected single-unit adjustable range is calculated. Then, the degraded control power value is allocated to each wind turbine unit according to the ratio of the corresponding difference of each wind turbine unit to the total sum, generating the degraded control power component of each wind turbine unit.

[0057] Preferably, through the above steps, the consistency of the instructions is first checked item by item, then the abnormal measurement values ​​are compensated for, and the dynamic adjustable domain of the wind farm is re-shrunken according to the compensated single-unit boundary. Then, a set of degraded control instructions is generated, which can enable the wind farm to maintain continuous control even under abnormal measurement or local unit operating conditions, reduce the operational risks caused by the direct issuance of erroneous instructions, and improve the robustness and sustainable operation capability of the wind farm's active power and primary frequency regulation coordinated control.

[0058] It should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention and are not intended to limit it. Although the present invention has been described in detail with reference to preferred embodiments, those skilled in the art should understand that modifications or equivalent substitutions can be made to the technical solutions of the present invention without departing from the spirit and scope of the technical solutions of the present invention, and all such modifications or substitutions should be covered within the scope of the claims of the present invention.

Claims

1. A method for coordinated control of active power and primary frequency regulation of a wind farm based on a direct access and direct control architecture, characterized in that, include: Based on the measured values ​​of grid connection point frequency, grid connection point frequency change rate, active power at the turbine terminal, rotor speed, pitch angle, converter current, and collector line load rate, the speed regulation margin, pitch regulation margin, converter current regulation margin, and active power regulation margin of each wind turbine are determined, and the limiting boundary of each regulation margin is taken to generate the adjustable range of a single unit. Line constraint corrections are performed based on the adjustable range of each unit and the measured load rate of the collection line. The field-level dynamic adjustable domain is generated by combining the current active power planned value of the wind farm. The total regulation demand of the wind farm is divided into active power coordinated control quantity and primary frequency regulation coordinated control quantity. Based on the measured values ​​of the grid connection point frequency, the measured value of the grid connection point frequency change rate, the measured value of the rotor speed, and the primary frequency regulation coordinated control quantity, it is determined whether each wind turbine is in the kinetic energy release stage, the support attenuation stage, or the energy recovery stage. The active power coordinated control quantity and the primary frequency regulation coordinated control quantity are allocated according to the stage sequence and the speed recovery staggered order to generate a set of unit control commands. The measurement timescale, power direction, and adjustment boundary corresponding to the set of unit control commands are checked for consistency. When the check passes, the set of unit control commands is issued. When the check fails or the unit control feedback is abnormal, the abnormal measurement value is compensated for and the field-level dynamic adjustable domain is shrunk to generate a set of degraded control commands.

2. The wind farm active power and primary frequency cooperative control method based on the direct access and direct control architecture according to claim 1, characterized in that, The determination of the speed regulation margin, pitch regulation margin, converter current regulation margin, and active power regulation margin of each wind turbine unit includes: Based on the difference between the measured rotor speed and the upper speed limit, determine the speed power increase margin; based on the difference between the measured rotor speed and the lower speed limit, determine the speed power decrease margin; based on the difference between the measured pitch angle and the upper pitch limit, determine the pitch power increase margin; based on the difference between the measured pitch angle and the lower pitch limit, determine the pitch power decrease margin; based on the difference between the measured converter current and the upper current limit, determine the current power increase margin; based on the difference between the measured converter current and the lower current limit, determine the current power decrease margin; based on... The basic power increase margin is determined based on the difference between the rated active power of the generator unit and the measured active power at the generator terminal; the basic power reduction margin is determined based on the difference between the measured active power at the generator terminal and the minimum stable active power of the generator unit; the remaining transmission margin of the line is determined based on the difference between the maximum allowable transmission power of the corresponding collector line and the current transmission power of the line, combined with the measured load rate of the collector line; the smaller value between the basic power increase margin and the remaining transmission margin of the line is determined as the active power increase margin; the basic power reduction margin is determined as the active power reduction margin. The speed increase margin and the speed decrease margin constitute the speed regulation margin, the pitch increase margin and the pitch decrease margin constitute the pitch regulation margin, the current increase margin and the current decrease margin constitute the converter current regulation margin, and the active power increase margin and the active power decrease margin constitute the active power regulation margin.

3. The wind farm active power and primary frequency collaborative control method based on the direct access and direct control architecture according to claim 2, characterized in that, The limiting boundary includes: Based on the current operating point corresponding to the rotor speed measurement, the ratio of the active power difference between adjacent speed points on both sides of the current operating point to the speed difference is taken to determine the power change per unit speed. The product of the speed power increase margin and the power change per unit speed is determined as the speed power increase boundary, and the product of the speed power decrease margin and the power change per unit speed is determined as the speed power decrease boundary. Based on the current operating point corresponding to the pitch angle measurement, the ratio of the active power difference between adjacent pitch points on both sides of the current operating point to the pitch difference is taken to determine the power change per unit pitch. The power increase margin and the power change per unit pitch are then calculated. The product is determined as the pitch power increase boundary, and the product of the pitch power reduction margin and the unit pitch power change is determined as the pitch power reduction boundary; based on the current operating point corresponding to the converter current measurement, the ratio of the active power difference to the current difference between adjacent current points on both sides of the current operating point is taken to determine the unit current power change, and the product of the current power increase margin and the unit current power change is determined as the current power increase boundary, and the product of the current power reduction margin and the unit current power change is determined as the current power reduction boundary; the active power increase margin is determined as the active power increase boundary, and the active power reduction margin is determined as the active power reduction boundary; Specifically, the minimum value among the power increase boundary of speed, the power increase boundary of pitch, the power increase boundary of current, and the power increase boundary of active power is taken as the power increase limit boundary, and the minimum value among the power decrease boundary of speed, the power decrease boundary of pitch, the power decrease boundary of current, and the power decrease boundary of active power is taken as the power decrease limit boundary.

4. The wind farm active power and primary frequency cooperative control method based on the direct access and direct control architecture according to claim 3, characterized in that, Generate a single-machine adjustable range based on the aforementioned limiting boundaries, including: Based on the power increase limit boundary, the power decrease limit boundary, and the active power measurement value at the turbine end, determine the single-unit adjustable range of the corresponding wind turbine. The upper boundary of the adjustable range of a single unit is the sum of the active power measurement value at the machine end and the power increase limit boundary, and the lower boundary of the adjustable range of a single unit is the difference between the active power measurement value at the machine end and the power decrease limit boundary.

5. The wind farm active power and primary frequency regulation coordinated control method based on a direct acquisition and control architecture according to claim 1 or 4, characterized in that, The generation of the field-level dynamically adjustable domain includes: Based on the measured load rate of the corresponding collector lines for each wind turbine, the remaining transmission margin of the corresponding collector lines is determined. The upper boundary of the adjustable range of each wind turbine connected to the same collector line is compared with the remaining transmission margin of the line. If the upper boundary of the adjustable range of the single turbine is greater than the remaining transmission margin of the line, the remaining transmission margin of the line is determined as the corrected upper boundary of the corresponding wind turbine. If the upper boundary of the adjustable range of the single turbine is less than or equal to the remaining transmission margin of the line, the upper boundary of the adjustable range of the single turbine is determined as the corrected upper boundary of the corresponding wind turbine. The lower boundary of the adjustable range of each wind turbine is determined as the corrected lower boundary of the corresponding wind turbine, thus generating the corrected adjustable range of each wind turbine. The upper boundary of each adjustable range of a single wind turbine is accumulated to generate a field-level power increase boundary; the lower boundary of each adjustable range of a single wind turbine is accumulated to generate a field-level power decrease boundary; and a field-level dynamic adjustable domain is generated based on the field-level power increase boundary, the field-level power decrease boundary, and the current active power planned value of the wind farm. Wherein, the upper boundary of the field-level dynamic adjustable domain is the sum of the current active power planned value of the wind farm and the field-level power increase boundary, and the lower boundary of the field-level dynamic adjustable domain is the difference between the current active power planned value of the wind farm and the field-level power decrease boundary.

6. The wind farm active power and primary frequency cooperative control method based on the direct access and direct control architecture according to claim 5, characterized in that, Also includes: The frequency support requirements of the wind farm are determined based on the difference between the rated frequency and the measured value of the grid connection point frequency, and in combination with the difference between zero and the measured value of the rate of change of the grid connection point frequency. The wind farm's planned adjustment needs are determined based on the difference between the target power output of the wind farm and the current planned active power output of the wind farm. The wind farm frequency support requirement is added to the wind farm planned regulation requirement to generate the total wind farm regulation requirement; The total regulation requirement of the wind farm is compared with the upper and lower boundaries of the farm-level dynamic adjustable domain: When the total regulation demand of the wind farm is less than or equal to the upper boundary of the field-level dynamic adjustable domain and greater than or equal to the lower boundary of the field-level dynamic adjustable domain, the wind farm frequency support demand is determined as the primary frequency regulation collaborative control quantity, and the difference between the total regulation demand of the wind farm and the primary frequency regulation collaborative control quantity is determined as the active power collaborative control quantity. When the total regulation demand of the wind farm is greater than the upper boundary of the field-level dynamic adjustable domain, the upper boundary of the field-level dynamic adjustable domain is determined as the total regulation boundary. The wind farm frequency support demand is compared with the total regulation boundary. When the wind farm frequency support demand is greater than or equal to the total regulation boundary, the total regulation boundary is determined as the primary frequency regulation collaborative control quantity, and zero is determined as the active power collaborative control quantity. When the wind farm frequency support demand is less than the total regulation boundary, the wind farm frequency support demand is determined as the primary frequency regulation collaborative control quantity, and the difference between the total regulation boundary and the primary frequency regulation collaborative control quantity is determined as the active power collaborative control quantity. When the total regulation demand of the wind farm is less than the lower boundary of the field-level dynamic adjustable domain, the lower boundary of the field-level dynamic adjustable domain is determined as the total regulation boundary. The wind farm frequency support demand is compared with the total regulation boundary. When the wind farm frequency support demand is less than or equal to the total regulation boundary, the total regulation boundary is determined as the primary frequency regulation coordinated control quantity, and zero is determined as the active power coordinated control quantity. When the wind farm frequency support demand is greater than the total regulation boundary, the wind farm frequency support demand is determined as the primary frequency regulation coordinated control quantity, and the difference between the total regulation boundary and the primary frequency regulation coordinated control quantity is determined as the active power coordinated control quantity.

7. The wind farm active power and primary frequency regulation coordinated control method based on direct acquisition and direct control architecture according to claim 1, characterized in that, Determine whether each wind turbine is in the kinetic energy release phase, the support decay phase, or the energy recovery phase, including: Calculate the first difference between the rated frequency and the measured value of the grid connection point frequency, the second difference between zero and the measured value of the rate of change of the grid connection point frequency, and the third difference between the lower limit of the speed and the measured value of the rotor speed, and compare the first difference, the second difference, and the third difference with zero respectively: When the first difference is greater than zero, the second difference is greater than zero, and the third difference is less than zero, the corresponding wind turbine is determined to be in the kinetic energy release stage. When the first difference is greater than zero, the second difference is less than or equal to zero, and the third difference is less than zero, the corresponding wind turbine is determined to be in the support attenuation stage. When the first difference is less than or equal to zero or the third difference is greater than or equal to zero, the corresponding wind turbine is determined to be in the energy recovery phase.

8. The wind farm active power and primary frequency collaborative control method based on the direct access and direct control architecture according to claim 7, characterized in that, The generation of the unit control command set includes: When the primary frequency regulation coordinated control quantity is greater than zero, the primary frequency regulation allocation direction is determined to be the power increase direction, and the primary frequency regulation coordinated control quantity is allocated based on the ratio of the difference between the upper boundary of the adjustable range of each wind turbine unit and the measured active power value at the turbine end to the sum of the corresponding differences of all wind turbine units. When the primary frequency regulation coordinated control quantity is less than zero, the primary frequency regulation allocation direction is determined to be the power decrease direction, and the primary frequency regulation coordinated control quantity is allocated based on the ratio of the difference between the measured active power value at the turbine end and the lower boundary of the adjustable range of each wind turbine unit to the sum of the corresponding differences of all wind turbine units. When the active power coordinated control quantity is greater than zero, the active power allocation direction is determined to be the power increase direction, and the active power coordinated control quantity is allocated based on the ratio of the corresponding differences at the upper boundary. When the active power coordinated control quantity is less than zero, the active power allocation direction is determined to be the power decrease direction, and the active power coordinated control quantity is allocated based on the ratio of the corresponding differences at the lower boundary. During the kinetic energy release phase, the allocated primary frequency regulation coordinated control quantity is added to the allocated active power coordinated control quantity to generate the corresponding stage control quantity for the wind turbine unit. During the support attenuation phase, the allocated primary frequency regulation coordinated control quantity is progressively corrected according to the ratio of the difference between the rotor speed measurement value and the lower speed limit to the sum of the corresponding differences for all wind turbine units in the support attenuation phase. The corrected primary frequency regulation coordinated control quantity is then added to the allocated active power coordinated control quantity to generate the corresponding stage control quantity for the wind turbine unit. During the energy recovery phase, the speed recovery staggered order for each wind turbine unit is determined according to the order of the difference between the rotor speed measurement value and the lower speed limit from small to large. The stage control quantity is then progressively reduced to zero according to the speed recovery staggered order to generate a set of unit control commands for each wind turbine unit.

9. The wind farm active power and primary frequency collaborative control method based on the direct access and direct control architecture according to claim 1, characterized in that, The consistency of the measurement timescale, power direction, and regulation boundary corresponding to the set of unit control commands is checked, including: The measurement timescales corresponding to each wind turbine in the set of unit control commands are compared with the measurement timescales corresponding to the grid connection point frequency measurement, the grid connection point frequency change rate measurement, the active power measurement at the turbine terminal, the rotor speed measurement, the pitch angle measurement, the converter current measurement, and the collector line load rate measurement. If all measurement timescales are the same, the measurement timescale consistency check is determined to be passed. If at least one of the measurement timescales is different, the measurement timescale consistency check is determined to be failed. Subtract the control power value corresponding to the set of unit control commands from the active power measurement value at the turbine terminal of the corresponding wind turbine to generate a control power change value; add the primary frequency regulation coordinated control quantity to the active power coordinated control quantity to generate a total control quantity; when the total control quantity is greater than zero and the control power change value is greater than zero, or when the total control quantity is less than zero and the control power change value is less than zero, the power direction consistency check is determined to be passed; when the total control quantity is greater than zero and the control power change value is less than or equal to zero, or when the total control quantity is less than zero and the control power change value is greater than or equal to zero, the power direction consistency check is determined to be failed; subtract the control power value corresponding to the set of unit control commands from the active power measurement value at the turbine terminal of the corresponding wind turbine to generate a control power change value; add the primary frequency regulation coordinated control quantity to the active power coordinated control quantity to generate a total control quantity; when the total control quantity is greater than zero and the control power change value is less than or equal to zero, or when the total control quantity is less than zero and the control power change value is greater than or equal to zero, the power direction consistency check is determined to be failed; subtract the control power value corresponding to the set of unit control commands from the active power measurement value at the turbine terminal of the corresponding wind turbine to generate a control power change value; subtract the control power value corresponding to the set of unit control commands from the active power measurement value at the turbine terminal of the corresponding wind turbine to generate a control power change value; subtract the control power value corresponding to the primary frequency regulation coordinated control quantity from the active power coordinated control quantity to generate a total control quantity; when the total control quantity is greater than zero and the control power change value is less than or equal to zero, the power direction consistency check is determined to be failed; subtract the control power value corresponding to the set of unit control commands from the primary frequency regulation coordinated control quantity to generate a total control quantity; subtract the control power value corresponding to the primary frequency regulation coordinated control quantity from the active power coordinated control quantity to generate a total control quantity; subtract the control power value corresponding to the primary frequency regulation coordinated control quantity from the active power coordinated control quantity to generate a total control quantity; sub The adjustment boundary consistency check is determined to be passed when the control power value is less than or equal to the upper boundary of the single-unit adjustable range and greater than or equal to the lower boundary of the single-unit adjustable range, and the sum of the control power values ​​of all wind turbines is less than or equal to the upper boundary of the field-level dynamic adjustable range and greater than or equal to the lower boundary of the field-level dynamic adjustable range; otherwise, the adjustment boundary consistency check is determined to be failed when the control power value is greater than the upper boundary of the single-unit adjustable range or less than the lower boundary of the single-unit adjustable range, or the sum of the control power values ​​of all wind turbines is greater than the upper boundary of the field-level dynamic adjustable range or less than the lower boundary of the field-level dynamic adjustable range.

10. The wind farm active power and primary frequency cooperative control method based on the direct access and direct control architecture according to claim 9, characterized in that, The generation of the degradation control instruction set includes: When the consistency checks of the measurement timescale, power direction, and adjustment boundary are all passed, the set of unit control commands is issued, and the set of unit control receipts returned by the corresponding wind turbine is received. The command identifiers in the set of unit control receipts are compared with the command identifiers in the set of unit control commands, the executed power value in the set of unit control receipts is compared with the control power value in the set of unit control commands, and the return timescale in the set of unit control receipts is compared with the issuance timescale in the set of unit control commands. If the command identifiers are different, the executed power value is not equal to the control power value, or the return timescale is earlier than the issuance timescale, the unit control receipt is determined to be abnormal. If at least one consistency check fails or the unit control feedback is abnormal, the average value of the valid measurement value corresponding to the abnormal measurement value at the previous moment and the current measurement value of the same type of adjacent wind turbines is taken to generate a compensation measurement value, and the abnormal measurement value is replaced with the compensation measurement value to generate a state compensation result. Based on the state compensation results, the corrected single-unit adjustable range of each wind turbine is redefined, and the upper and lower boundaries of the contracted field-level dynamic adjustable domain are redefined according to each corrected single-unit adjustable range. The primary frequency regulation coordinated control quantity and the active power coordinated control quantity are added to generate the total control quantity before correction. When the total control quantity before correction is greater than the upper boundary of the contracted field-level dynamic adjustable domain, the upper boundary of the contracted field-level dynamic adjustable domain is determined as the degraded control power value. When the total control quantity before correction is less than the lower boundary of the contracted field-level dynamic adjustable domain, the lower boundary of the contracted field-level dynamic adjustable domain is determined as the degraded control power value. When the total control quantity before correction is less than or equal to the upper boundary of the contracted field-level dynamic adjustable domain and greater than or equal to the lower boundary of the contracted field-level dynamic adjustable domain, the total control quantity before correction is determined as the degraded control power value. When the degraded control power value is greater than zero, the degraded control power value is allocated according to the ratio of the difference between the upper boundary of the corrected adjustable range of each wind turbine and the active power measurement value at the turbine end to the sum of the corresponding differences of all wind turbines, generating a degraded control power component for each wind turbine. When the degraded control power value is less than zero, the degraded control power value is allocated according to the ratio of the difference between the active power measurement value at the turbine end and the lower boundary of the corrected adjustable range of each wind turbine to the sum of the corresponding differences of all wind turbines, generating a degraded control power component for each wind turbine. The degraded control power component of each wind turbine is added to the active power measurement value at the turbine end of the corresponding wind turbine to generate a set of degraded control commands for each wind turbine.

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