A wind power plant station control method and device considering rotor rotating speed dynamic constraint

Abstract

The application discloses a wind power plant control method and device considering rotor speed dynamic constraint, and the method comprises the following steps: obtaining the operation parameters of synchronous units in a power grid; constructing an additional active control model of the wind power plant containing power optimization control; linearizing the power grid frequency and the synchronous unit output power according to the operation parameters and the additional active control model combined with the piecewise function principle to obtain a total power increment piecewise linear expression of the wind power plant; performing piecewise fitting according to the wind power coefficient and the rotor speed to obtain a first equation; obtaining a rotor speed piecewise expression according to the wind power plant rotor motion equation, the first equation and the total power increment piecewise linear expression; adjusting the control parameters of the wind power plant in each speed section according to the rotor speed piecewise expression; the control parameters at least include primary frequency modulation parameters; and controlling the wind power plant according to the control parameters.

Description

Technical Field

[0001] This invention relates to the field of power system technology, and in particular to a wind farm control method and device that considers dynamic constraints on rotor speed. Background Technology

[0002] With technological breakthroughs and cost reductions, new energy sources are rapidly replacing fossil fuels in the global energy mix. This shift will lead to a gradual depletion of power system inertia and primary frequency regulation capabilities, severely impacting power system frequency stability. Wind power, as one of the most widely used new energy generation technologies, can effectively improve power system frequency stability if its inherent primary frequency regulation capabilities are properly utilized.

[0003] The frequency regulation capability of a wind farm is closely related to the wind energy it captures, and the kinetic energy contained in its rotor can provide effective frequency regulation support for the power grid. Currently, there are three common methods for wind farms to participate in primary frequency regulation: reserved power reserve, overspeed load shedding control, and releasing rotor kinetic energy. Reserved power reserve lowers the steady-state operating point of the wind farm, giving it more kinetic energy to release and the ability to increase power output, but its main drawback is poor power generation economics. Essentially, overspeed load shedding also falls under the category of releasing rotor kinetic energy, but the difference is that overspeed load shedding reduces power output while increasing rotor speed by adjusting the wind farm's operating point, thereby obtaining more kinetic energy to release. However, when using the above three control methods, if the primary frequency regulation parameters of the wind farm are not adjusted reasonably, the problem of secondary frequency drop caused by excessive kinetic energy release will be faced.

[0004] Therefore, a new technical solution is urgently needed to solve the technical problem of how to perform primary frequency regulation parameter tuning for wind farms based on dynamic constraints of rotor speed. Summary of the Invention

[0005] This invention provides a wind farm control method and device that considers dynamic constraints on rotor speed, in order to solve the technical problem of how to perform primary frequency regulation parameter tuning of wind farms based on dynamic constraints on rotor speed.

[0006] To achieve the above objectives, the present invention provides a wind farm control method considering dynamic constraints on rotor speed, comprising:

[0007] Obtain the operating parameters of the synchronous generator units in the power grid; construct an additional active power control model for the wind farm with power optimization control; and linearize the power grid frequency and the output power of the synchronous generator units based on the operating parameters and the additional active power control model, using the piecewise function principle, to obtain a piecewise linear expression for the total power increment of the wind farm.

[0008] The first equation is obtained by piecewise fitting based on the wind power coefficient and rotor speed; the piecewise expression of rotor speed is obtained based on the rotor motion equation of the wind farm, the first equation, and the piecewise linear expression of the total power increment; the control parameters of the wind farm for each speed segment are tuned based on the piecewise expression of rotor speed; the control parameters include at least the primary frequency regulation parameters; the wind farm is controlled based on the control parameters.

[0009] Preferably, based on the operating parameters and the additional active power control model, combined with the piecewise function principle, the grid frequency and synchronous generator output power are linearized to obtain the piecewise linear expression for the total power increment of the wind farm, including:

[0010] Based on the operating parameters and the additional active power control model, combined with the piecewise function principle, the grid frequency and synchronous generator output power are linearized to obtain piecewise linear expressions for frequency deviation and power increment, respectively. Based on the additional active power control model, the piecewise linear expression for frequency deviation, and the piecewise linear expression for power increment, the piecewise linear expression for the total power increment of the wind farm is obtained.

[0011] Preferably, based on the operating parameters and the additional active power control model, combined with the piecewise function principle, the grid frequency and synchronous generator output power are linearized to obtain the piecewise linear expressions for frequency deviation and power increment, respectively:

[0012] Operating parameters include the configuration parameters of the synchronous generator and the governor data; a speed control system model is obtained based on the governor data; and a frequency response equation containing the power increment of the wind farm is obtained based on the configuration parameters, the speed control system model, and the preset low-frequency fault.

[0013] The frequency deviation time-domain expression of the power grid is obtained based on the frequency response equation, the additional active power control model, and the preset frequency security constraints; the frequency deviation time-domain expression is linearized based on the piecewise function principle to obtain the piecewise linear expression of the power grid frequency deviation.

[0014] The first expression is obtained based on the speed control system model and the time-domain expression of the frequency deviation; the first expression is then subjected to an inverse Laplace transform to obtain the time-domain expression of the power increment of the synchronous generator; the power increment time-domain expression is linearized based on the principle of piecewise functions to obtain the piecewise linear expression of the power increment of the synchronous generator.

[0015] Preferably, the method further includes obtaining the slopes of the piecewise linear expression for the frequency deviation and the piecewise linear expression for the power increment, including:

[0016] During a single frequency modulation period, the time-domain expression and the piecewise linear expression of the frequency deviation are integrated to obtain the first integral and the second integral, respectively. The first integral and the second integral are then equalized and solved to obtain the slope of the piecewise linear expression of the frequency deviation.

[0017] During a single frequency modulation period, the time-domain expression and the piecewise linear expression of the power increment are integrated to obtain the third and fourth integral expressions, respectively. The third and fourth integral expressions are then solved by making them equal to obtain the slope of the piecewise linear expression of the power increment.

[0018] Preferably, the piecewise expression for the rotor speed is obtained based on the rotor motion equation of the wind farm, the first equation, and the piecewise linear expression for the total power increment, including:

[0019] Based on the rotor motion equation, the first equation, and the piecewise linear expression of the total power increment of the wind farm, the piecewise rotor motion equation is obtained. The differential equation is then solved based on the piecewise rotor motion equation to obtain the piecewise expression of the rotor speed. The piecewise expression of the rotor speed includes the medium and low speed segment, the high speed segment, and the constant speed segment.

[0020] Preferably, the control parameter tuning for wind farms in each speed segment, based on the segmented expression of rotor speed, includes:

[0021] The control parameters of each wind farm in the low-to-medium speed segment are tuned according to the piecewise expression of rotor speed and the piecewise linear expression of total power increment. The control parameters of each wind farm in the low-to-medium speed segment include the additional active power control transfer function and primary frequency regulation parameters of the additional active power control model.

[0022] The control parameters of each wind farm in the high-speed segment are tuned according to the segmented expression of rotor speed; the control parameters of each wind farm in the high-speed segment include the primary frequency regulation parameters;

[0023] The control parameters of each wind farm station in the constant speed segment are determined based on the segmented expression of rotor speed and the segmented rotor motion equation; the control parameters of each wind farm station in the constant speed segment include virtual inertia parameters and primary frequency regulation parameters;

[0024] After completing the control parameter tuning for each wind farm section, the preset system frequency response index for each wind farm section is calculated. Then, based on the preset frequency safety constraints, it is determined whether the primary frequency regulation parameters for each speed segment meet the constraints. If not, the power support tuning of the primary frequency regulation parameters for each speed segment is performed through the preset fast frequency regulation resources.

[0025] Preferably, the control parameters for each wind farm in the low-to-medium speed segment are tuned according to the piecewise expression for rotor speed and the piecewise linear expression for total power increment, including:

[0026] Integrating the piecewise linear expression of the total power increment yields the fifth integral expression; solving the fifth integral expression by setting it equal to 0 yields the total primary frequency regulation gain of the wind farm segmented for medium and low speeds.

[0027] The distribution coefficient of the medium- and low-speed segment is obtained based on the rotor kinetic energy of each station in the medium- and low-speed segment.

[0028] The additional active power control transfer function and primary frequency regulation parameters of each wind farm in the medium-low speed segment are obtained based on the total primary frequency regulation gain and allocation coefficient of the wind farm in the medium-low speed segment.

[0029] Substitute the additional active power control transfer function and primary frequency regulation parameters of each wind farm in the low-to-medium speed segment into the rotor speed segment expression to calculate the minimum wind farm speed during the primary frequency regulation period. If there is a limit violation, reduce the primary frequency regulation parameters until the minimum speed is higher than the minimum critical speed.

[0030] Preferably, the control parameters for each wind farm in the high-speed segment are tuned according to the segmented expression of rotor speed, including:

[0031] Set the allocation coefficient of the wind farm in the high-speed segment to 0 and substitute it into the rotor speed segment expression to obtain the second expression; based on the second expression, perform primary frequency regulation parameter optimization for the high-speed segment, select the maximum primary frequency regulation parameter that makes the speed of the wind farm in the high-speed segment greater than or equal to the upper boundary value of the low-speed zone at the end of the primary frequency regulation, and obtain the primary frequency regulation parameters of each wind farm in the high-speed segment.

[0032] Preferably, the control parameters for each wind farm station in the constant speed segment are tuned according to the segmented rotor speed expression and the segmented rotor motion equation, including:

[0033] Based on the virtual inertia coefficient and primary frequency regulation parameters of wind farms in constant speed segments, a constant speed segmented power increment expression is constructed; the allocation coefficient of wind farms in constant speed segments is set to 0, and a third expression is obtained based on the constant speed segmented power increment expression, the segmented rotor motion equation, and the rotor speed segmented expression; based on the third expression and the rotor speed constraint and power up-adjustment space constraint, the virtual inertia parameters and primary frequency regulation parameters of each wind farm in the constant speed zone are obtained.

[0034] The present invention also provides a wind farm control device that considers dynamic constraints on rotor speed, for implementing the method of the present invention.

[0035] The present invention has the following beneficial effects:

[0036] The wind farm control method of this invention, which considers dynamic constraints on rotor speed, linearizes the system frequency and synchronous turbine output power, further derives a linear expression for the total output power of the wind farm, and substitutes it into its rotor motion equation to obtain a piecewise expression. This simplifies the calculation of wind farm rotor speed prediction during primary frequency regulation and provides a theoretical basis for primary frequency regulation parameter optimization tuning strategies based on optimal frequency trajectories. Different primary frequency regulation parameter optimization tuning schemes are adopted for wind farms in different rotor speed ranges to ensure that the rotor speed of wind farms in the low-to-medium speed range can automatically recover to the initial level after the primary frequency regulation ends. It also makes full use of the rotational kinetic energy of wind farms in the high-speed and constant-speed ranges to provide stronger and more durable primary frequency regulation support capabilities. This allows wind farms in the low-to-medium speed range to take into account both frequency regulation and speed self-recovery, while wind farms in the high-speed and constant-speed ranges can release their own rotor kinetic energy as much as possible under the premise of considering the minimum rotor speed constraint, providing more durable and stable power support for the system. The method of this invention performs primary frequency regulation parameter tuning for wind farms based on dynamic constraints of rotor speed, effectively reducing the model complexity of dynamic frequency analysis of the system.

[0037] The wind farm control device of the present invention, which considers dynamic constraints on rotor speed, is used in the method of the present invention and has the same beneficial effects as the method of the present invention.

[0038] In addition to the objectives, features, and advantages described above, the present invention has other objectives, features, and advantages. The invention will now be described in further detail with reference to the accompanying drawings. Attached Figure Description

[0039] The accompanying drawings, which form part of this invention, are used to provide a further understanding of the invention. The illustrative embodiments of the invention and their descriptions are used to explain the invention and do not constitute an undue limitation of the invention. In the drawings:

[0040] Figure 1 This is a schematic diagram of the method flow of a preferred embodiment of the present invention.

[0041] Figure 2 This is a schematic diagram of the IEEE 39-node system according to a preferred embodiment of the present invention.

[0042] Figure 3 This is a schematic diagram of the wind speed and rotational speed range of a wind farm station according to a preferred embodiment of the present invention.

[0043] Figure 4 This is a schematic diagram comparing the simulation results and linearization results of the system frequency deviation in a preferred embodiment of the present invention.

[0044] Figure 5 This is a schematic diagram comparing the simulation results and linearization results of the synchronous generator power generation of a preferred embodiment of the present invention.

[0045] Figure 6 This is a schematic diagram comparing the simulation results and linearization results of the increased power generation of a wind farm in a preferred embodiment of the present invention.

[0046] Figure 7 This is a schematic diagram comparing the rotor speed of a wind farm station according to a preferred embodiment of the present invention.

[0047] Figure 8 This is a schematic diagram of the system frequency trajectory under four different frequency modulation control strategy scenarios in a preferred embodiment of the present invention.

[0048] Figure 9 This is a schematic diagram comparing the increased power generation of wind farms W1 and W2 according to a preferred embodiment of the present invention.

[0049] Figure 10 This is a schematic diagram comparing the increased power generation of wind farms W3 and W4 according to a preferred embodiment of the present invention.

[0050] Figure 11 This is a schematic diagram comparing the rotor speeds of wind farms W1 and W2 according to a preferred embodiment of the present invention.

[0051] Figure 12 This is a schematic diagram comparing the rotor speeds of wind farms W3 and W4 according to a preferred embodiment of the present invention. Detailed Implementation

[0052] The embodiments of the present invention will be described in detail below with reference to the accompanying drawings, but the present invention can be implemented in many different ways as defined and covered by the claims.

[0053] See Figure 1 In a preferred embodiment of the present invention, a wind farm control method considering dynamic constraints on rotor speed is provided, comprising:

[0054] Q1. Obtain the operating parameters of synchronous generator units in the power grid; construct an additional active power control model for wind farms that includes power optimization control.

[0055] In a preferred embodiment of the present invention, the operating parameters include the configuration parameters of the synchronous generator and the governor data; the configuration parameters include start-up and shutdown status, installed capacity and inertial time constant.

[0056] The governor data for synchronous generator units generally includes prime mover parameters and governor parameters. The prime mover model includes a steam turbine model and a water turbine model; the governor model includes a steam turbine governor and a water turbine governor.

[0057] In a preferred embodiment of the present invention, the additional active power control model for wind farms, including power optimization control, includes:

[0058] ;

[0059] in, Add active power control transfer functions to all wind farms. For power grid frequency deviation, For the speed control system transfer function, For the total power increase of wind farms, This represents the total primary frequency regulation gain of the wind farm. During the primary frequency regulation period, the wind farm transmits signals through... as well as This process achieves power release and absorption, thereby restoring the rotor speed of the wind farm, hence the name. This is a power optimization control component for wind farms.

[0060] Q2. Based on the operating parameters and the additional active power control model, combined with the piecewise function principle, the grid frequency and synchronous generator output power are linearized to obtain a piecewise linear expression for the total power increment of the wind farm. Q2 specifically includes:

[0061] Based on the operating parameters and the additional active power control model, combined with the piecewise function principle, the grid frequency and synchronous generator output power are linearized to obtain piecewise linear expressions for frequency deviation and power increment, respectively. Based on the additional active power control model, the piecewise linear expression for frequency deviation, and the piecewise linear expression for power increment, the piecewise linear expression for the total power increment of the wind farm is obtained.

[0062] In a preferred embodiment of the present invention, the grid frequency and synchronous generator output power are linearized based on operating parameters and an additional active power control model combined with the piecewise function principle, resulting in piecewise linear expressions for frequency deviation and power increment, respectively:

[0063] The speed control system model is obtained based on the governor data, including:

[0064] ;

[0065] Where s is the Laplace operator, For power grid frequency deviation, For the speed control system transfer function, For the power increment of synchronous units, For high-pressure cylinder coefficient, The reheat time constant is This is the adjustment coefficient.

[0066] The frequency response equation, incorporating power increments at wind farms, is derived based on configuration parameters, a speed control system model, and pre-set low-frequency faults. Pre-set low-frequency faults include sudden load increases, synchronous generator tripping, and DC bipolar blocking. The frequency response equation includes:

[0067] ;

[0068] in, The equivalent inertia coefficient of the power grid. Let be the rotational inertia of the i-th synchronous generator unit. Let the assembly capacity of the i-th synchronous machine be... This represents the start-up and shutdown status of the i-th synchronous generator unit. This represents the total number of synchronous generating units in the power grid. This is the equivalent damping coefficient. Let be the damping coefficient of the i-th synchronous generator unit. Let i be the installed capacity of the i-th wind farm. The operating status of the i-th wind farm station is as follows: This represents the total number of wind farms in the power grid. For total capacity, For the increase in active power of wind farms; The power imbalance in the power grid is determined by the preset low-frequency faults selected in this embodiment.

[0069] Based on the frequency response equation, the additional active power control model, and the preset frequency security constraints, the time-domain expression for the power grid frequency deviation is obtained, including:

[0070] ;

[0071] in, The frequency deviation under the optimal frequency trajectory. and These are the coefficients of the time-domain expression of the frequency response equation. and These are the maximum deviation limit of the power grid frequency and the maximum rate of change limit of the frequency, respectively, where e is the natural base. In a preferred embodiment of the present invention, the preset frequency safety constraints include the maximum rate of change constraint of the frequency, the maximum deviation constraint of the frequency, and the quasi-steady-state frequency deviation constraint, etc.

[0072] The time-domain expression of frequency deviation is linearized based on the piecewise function principle to obtain a piecewise linear expression of the power grid frequency deviation. Setting the occurrence time of the low-frequency accident as time 0, the time-domain expression and the piecewise linear expression of frequency deviation are integrated during the first frequency regulation period to obtain the first and second integral expressions, respectively. The first and second integral expressions are then solved by setting them equal to obtain the slope of the piecewise linear expression of frequency deviation. Specifically, this includes:

[0073] ;

[0074] ;

[0075] ;

[0076] in, The piecewise linear expression for the frequency deviation of the power grid. This is the second integral expression. For the first integral, The slope of the piecewise linear expression for the frequency deviation. Let t be the end time of the primary frequency regulation of the power grid.

[0077] The first expression is obtained based on the speed control system model and the time-domain expression of the frequency deviation. Specifically, the time-domain expression of the frequency deviation is subjected to a Laplace transform and then input into the speed control system model to obtain the first expression, which includes:

[0078] ;

[0079] The first expression is subjected to an inverse Laplace transform to obtain the time-domain expression for the power increment of the synchronous generator unit. Based on the piecewise function principle, the time-domain expression for the power increment is linearized to obtain a piecewise linear expression for the power increment of the synchronous generator unit. During the first frequency regulation period, the time-domain expression and the piecewise linear expression for the power increment are integrated to obtain the third and fourth integral expressions, respectively. The third and fourth integral expressions are then equated and solved to obtain the slope of the piecewise linear expression for the power increment. Specifically, this includes:

[0080] ;

[0081] ;

[0082] ;

[0083] in, This is the third integral expression. and These are the coefficients in the time-domain expression of the power increment of synchronous generator units. This is a piecewise linear expression for the power increment of a synchronous generator unit. This is the fourth integral expression. Let be the slope of the piecewise linear expression for the power increment of the synchronous generator unit.

[0084] In a preferred embodiment of the present invention, the piecewise linear expression for the total power increment of the wind farm is obtained based on the additional active power control model, the piecewise linear expression for frequency deviation, and the piecewise linear expression for power increment. ,include:

[0085] ;

[0086] Q3. Based on the wind power coefficient and rotor speed, a piecewise fitting is performed to obtain the first equation; based on the rotor motion equation of the wind farm, the first equation, and the piecewise linear expression of the total power increment, a piecewise expression for the rotor speed is obtained.

[0087] In a preferred embodiment of the present invention, the piecewise expression for the rotor speed is obtained based on the rotor motion equation of the wind farm, the first equation, and the piecewise linear expression for the total power increment, including:

[0088] Based on the rotor motion equation, the first equation, and the piecewise linear expression of the total power increment of the wind farm, the piecewise rotor motion equation is obtained. The differential equation is then solved based on the piecewise rotor motion equation to obtain the piecewise expression of the rotor speed. The piecewise expression of the rotor speed includes the medium and low speed segment, the high speed segment, and the constant speed segment.

[0089] In a preferred embodiment of the present invention, the rotor motion equation of the wind farm includes:

[0090] ;

[0091] in, The moment of inertia of the wind turbine. The rotor speed, and These are mechanical power and electromagnetic power, respectively. air density, The wind power coefficient, For the tip speed ratio, The pitch angle is the propeller angle. The radius of the wind turbine blade. This refers to wind speed.

[0092] In a preferred embodiment of the present invention, due to the wind power coefficient With rotor speed There is a highly nonlinear relationship between them. To simplify analysis and calculation, [the following is omitted]. Piecewise fitting is performed to obtain the first equation, which includes:

[0093] ;

[0094] Where i is the segment number. and Here are the fitting coefficients, and N is the number of segments. This is the mechanical power coefficient.

[0095] In a preferred embodiment of the present invention, a piecewise rotor motion equation is obtained based on the rotor motion equation of the wind farm, the first equation, and the piecewise linear expression of the total power increment. The differential equation is then solved based on the piecewise rotor motion equation to obtain a piecewise expression for the rotor speed, including:

[0096] The equations of motion for the segmented rotor include:

[0097] ;

[0098] In this context, the subscript j of each variable represents the wind farm index number added to the original variable meaning. Let J be the electromagnetic power of the j-th wind farm at time 0. is the allocation coefficient for the j-th wind farm, used to distribute the total power increment to each wind farm.

[0099] Let y = Substituting these equations into the piecewise rotor motion equations and solving the differential equations, we obtain the piecewise expression for the rotor speed, including:

[0100] ;

[0101] in, , and Let be the constant of the piecewise differential equation for the rotor speed of the j-th wind farm, given at time 0. Time and Moment The value is determined.

[0102] Q4. Based on the segmented expression of rotor speed, the control parameters of the wind farm for each speed segment are tuned; the control parameters include at least the primary frequency regulation parameters; the wind farm is controlled according to the control parameters.

[0103] In a preferred embodiment of the present invention, the control parameter tuning of the wind farm for each speed segment according to the segmented expression of rotor speed includes:

[0104] The control parameters for each wind farm in the low-to-medium speed segment are tuned based on the piecewise expression for rotor speed and the piecewise linear expression for total power increment. The control parameters for each wind farm in the low-to-medium speed segment include the additional active power control transfer function of the additional active power control model and the primary frequency regulation parameters. Specifically, these include:

[0105] For wind farms in the low-to-medium speed range, in order to ensure that the kinetic energy released during the primary frequency regulation period is 0, the distribution coefficient is determined based on the magnitude of the rotor kinetic energy and the primary frequency regulation parameters are solved. Since the rotor speed of wind farms in the low-to-medium speed range is low, excessive release of rotor kinetic energy will lead to grid disconnection and cause a secondary frequency drop. Therefore, it is necessary to restore the speed during the primary frequency regulation period.

[0106] Integrating the piecewise linear expression for the total power increment, we obtain the fifth integral expression. :

[0107] ;

[0108] Solving the fifth integral expression to zero yields the total primary frequency regulation gain of the wind farm in the low-to-medium speed segment. .

[0109] The distribution coefficient for the medium- and low-speed segments is obtained based on the rotor kinetic energy of each station in the medium- and low-speed segment:

[0110] ;

[0111] in, For the rotor kinetic energy of the j-th wind farm station; This is the minimum critical speed; and These represent the total number of wind farms with rotor speeds in the low-speed and medium-speed ranges, respectively.

[0112] Based on the overall primary frequency regulation gain and allocation coefficient of the wind farms in the medium- and low-speed segments, the additional active power control transfer function and primary frequency regulation parameters of each wind farm in the medium- and low-speed segments are obtained:

[0113] ;

[0114] in, , and These are the additional active power control transfer function, allocation coefficient, and primary frequency regulation parameters for the j-th wind farm in the low-speed zone. , and These are the additional active power control transfer function, allocation coefficient, and primary frequency regulation parameters for the j-th wind farm in the medium-speed range.

[0115] Substitute the additional active power control transfer function and primary frequency regulation parameters of each wind farm in the low-to-medium speed segment into the rotor speed segment expression to calculate the minimum wind farm speed during the primary frequency regulation period. If there is a limit violation, reduce the primary frequency regulation parameters until the minimum speed is higher than the minimum critical speed.

[0116] The control parameters for each wind farm station in the high-speed segment are tuned according to the segmented expression of rotor speed; the control parameters for each wind farm station in the high-speed segment include primary frequency regulation parameters. Specifically, these include:

[0117] Because high-speed segmented wind farms possess greater rotor kinetic energy, they can provide more sustained and stable primary frequency regulation power without additional power absorption. Therefore, setting the allocation coefficient of the high-speed segmented wind farm to 0 and substituting it into the rotor speed segmented expression yields the second expression:

[0118] ;

[0119] in, Let be the primary frequency regulation parameters for the j-th high-speed wind farm. and The two constants in the piecewise differential equation of the rotor speed of the j-th high-speed wind farm can be derived from time 0 and Moment Sure.

[0120] Based on the second expression, the primary frequency regulation parameters for high-speed segmentation are optimized. The maximum primary frequency regulation parameter is selected such that the wind farm speed in the high-speed segment is greater than or equal to the upper boundary value of the low-speed zone at the end of the primary frequency regulation. The primary frequency regulation parameters for each wind farm in the high-speed segment are then obtained.

[0121] ;

[0122] Where pu is the per-unit value; The upper boundary value of the low-speed range is set to 0.9pu in this embodiment of the invention.

[0123] The control parameters for each wind farm station in the constant speed segment are determined based on the segmented expression of rotor speed and the segmented rotor motion equation. The control parameters for each wind farm station in the constant speed segment include virtual inertia parameters and primary frequency regulation parameters. Specifically, these include:

[0124] A control strategy combining virtual inertia control and primary frequency regulation control is employed for primary frequency regulation of the power grid. Control parameters are tuned based on rotor speed constraints and power generation ceiling constraints. In the constant speed segment, the rotor speed of the wind farm has reached its rated value, and it remains almost unchanged as power increases. Although the wind farm possesses greater rotor kinetic energy at this point, its power increase potential is limited due to converter capacity constraints. Therefore, to provide more stable power output, virtual inertia control is added to the primary frequency regulation control of the wind farm.

[0125] Based on the virtual inertia coefficient and primary frequency regulation parameters of the constant-speed segmented wind farm, a constant-speed segmented power increment expression is constructed:

[0126] Let the virtual inertia coefficient and primary frequency regulation parameters of the j-th wind farm station within the constant speed segment be respectively... and When the system frequency deviation is as shown in the time-domain expression for the frequency deviation, the power increment of the wind farm is... It can be represented as:

[0127] ;

[0128] Observing the above formula, we can see that when At that time, the power increment of the wind farm station It will equal a constant value. This allows for more stable and sustained power support, and makes it easier to predict the lowest point of rotor speed during primary frequency regulation.

[0129] Let the distribution coefficient of the wind farm in the constant speed segment be 0, and obtain the third expression based on the constant speed segment power increment expression, the segmented rotor motion equation, and the segmented rotor speed expression:

[0130] ;

[0131] in, The constant of the differential equation for the rotor speed of the j-th constant-speed segmented wind farm can be obtained from time 0. Sure.

[0132] Based on the third expression and the constraints of rotor speed and power increase space, the virtual inertia parameters and primary frequency regulation parameters of each wind farm in the constant speed zone are obtained, specifically including:

[0133] Similar to the handling methods for wind farms in the high-speed range, it is necessary to release the rotor kinetic energy as much as possible while ensuring that the rotor speed does not exceed the minimum critical speed during the primary frequency regulation period. To ensure The engine speed should not be lower than the upper boundary value of the low-speed range at any given time. and First maximum feasible value and for:

[0134] ;

[0135] On the other hand, since the output active power level of wind farms within the constant speed segment is relatively high, the power adjustment space is relatively limited. Therefore, in order to avoid triggering its power limiting during the first frequency regulation process, it is necessary to adjust the power adjustment space according to the available power. and Constraints are applied. When the maximum power adjustment space of the j-th wind farm is... hour, and Second maximum feasible value and for:

[0136] ;

[0137] Therefore, the parameter tuning of the j-th wind farm within the constant speed segment must meet the following conditions:

[0138] ;

[0139] In a preferred embodiment of the present invention, after the control parameters of each wind farm section are tuned, the preset system frequency response index of each wind farm section is calculated, and the primary frequency regulation parameters of each speed segment are judged to meet the preset frequency safety constraints. If they do not meet the constraints, the power support tuning of the primary frequency regulation parameters of each speed segment is performed through preset fast frequency regulation resources.

[0140] After completing the initial frequency regulation parameter tuning for each speed segment, the maximum frequency change rate of the system is... Deviation from maximum frequency Represented as:

[0141] ;

[0142] in, and The numbers of wind farms in the high-speed segment and the constant-speed segment are respectively; , , and These represent the installed capacity of the j-th wind farm in the low-speed, medium-speed, high-speed, and constant-speed segments, respectively.

[0143] When the system's maximum rate of frequency change and maximum frequency deviation do not meet the safety constraints, i.e. and , For the maximum rate of change of frequency, safety constraints To meet the maximum frequency deviation safety constraints, additional power support is required from other fast frequency regulation resources in the system (such as energy storage power stations or high-voltage DC). At this point, the system's inertia and primary frequency regulation requirements ( and This can be represented as:

[0144] ;

[0145] The above additional requirements will be borne by the remaining frequency modulation resources in the system. The virtual inertia coefficient of the j-th frequency modulation resource station. With virtual droop coefficient It can be determined by the following formula:

[0146] ;

[0147] in, and These represent the total number of remaining frequency regulation resources and the installed capacity of the j-th frequency regulation resource station, respectively.

[0148] The wind farm control method of this invention, which considers dynamic constraints on rotor speed, linearizes the system frequency and synchronous turbine output power, further derives a linear expression for the total output power of the wind farm, and substitutes it into its rotor motion equation to obtain a piecewise expression. This simplifies the calculation of wind farm rotor speed prediction during primary frequency regulation and provides a theoretical basis for primary frequency regulation parameter optimization tuning strategies based on optimal frequency trajectories. Different primary frequency regulation parameter optimization tuning schemes are adopted for wind farms in different rotor speed ranges to ensure that the rotor speed of wind farms in the low-to-medium speed range can automatically recover to the initial level after the primary frequency regulation ends. It also makes full use of the rotational kinetic energy of wind farms in the high-speed and constant-speed ranges to provide stronger and more durable primary frequency regulation support capabilities. This allows wind farms in the low-to-medium speed range to take into account both frequency regulation and speed self-recovery, while wind farms in the high-speed and constant-speed ranges can release their own rotor kinetic energy as much as possible under the premise of considering the minimum rotor speed constraint, providing more durable and stable power support for the system. The method of this invention performs primary frequency regulation parameter tuning for wind farms based on dynamic constraints of rotor speed, effectively reducing the model complexity of dynamic frequency analysis of the system.

[0149] In a preferred embodiment of the present invention, a wind farm control device considering dynamic constraints on rotor speed is also provided to implement the method of the present invention.

[0150] The wind farm control device of the present invention, which considers dynamic constraints on rotor speed, is used in the method of the present invention and has the same beneficial effects as the method of the present invention.

[0151] Verification section:

[0152] To verify the feasibility and accuracy of the method of this invention, an IEEE 39-node system was built on the DIgSILENT / PowerFactory2022 software platform, and a specific implementation example analysis was conducted. The computational programs were all compiled using MATLAB on a computer.

[0153] Using the IEEE 39-node system as the test system, such as Figure 2 As shown, Figure 2In this context, HVDC represents high-voltage direct current. The conventional synchronous turbine system includes 9 thermal power units and 1 hydropower unit. The thermal power units use the IEEE-G1 governor-prime mover model, and the hydropower unit uses the IEEE-G3 governor-prime mover model. For renewable energy, 60 doubly-fed wind turbines with a rated output of 6MW are connected at nodes 3, 15, 16, and 23 respectively, forming 4 wind farms (W1 to W4); 2 energy storage power stations with a rated power of 60MW are connected at nodes 2 and 19 respectively; and a 400MW high-voltage direct current line is connected at node 26. The total installed capacity of the synchronous turbines in the system is 6500MVA, the inertial time constant is 4.153s, the total system load demand is 7500MW, and the load damping coefficient is 1. The wind speed and rotational speed ranges for each wind farm in this example are as follows: Figure 3 As shown, in Figure 3 In the diagram, the horizontal axis v represents wind speed, v min1 To cut off the wind speed, v min2 To activate the wind speed, v s v is the wind speed at the lower boundary of the constant rotation speed region. n For the rated wind speed, v max This represents the maximum wind speed. S I S II-1 S II-2 S III S IV and S V These are the numberings for the cut-in zone, startup zone, MPPT zone, constant speed zone, constant power zone, and cut-out zone, respectively. The vertical axis P and... These represent the active power and rotor speed of the wind farm, respectively. N The rated power of the wind farm. At the lowest speed, This is the lower boundary speed of the constant speed region. The rated speed is used. Wind farms with rotor speeds in the cut-in, start-up, and constant power zones do not participate in system frequency regulation. Wind farms in the MPPT (Maximum Power Point Tracking) zone and constant speed zone participate in system inertia and primary frequency regulation response through additional active power control. It should be noted that the research focus of this invention is not on how to rationally divide each speed range. Therefore, the MPPT zone is divided into three parts, representing low, medium, and high speed zones, with speed ranges of [0.7, 0.9], [0.9, 1.1], and [1.1, 1.2], respectively. In addition, the constant speed zone speed is 1.2.

[0154] Based on the improved IEEE 39 system described above, a synchronous generator unit, a wind farm, and an energy storage power station were constructed in MATLAB / Simulink. After a load surge of 8% of the system capacity, the maximum frequency deviation and maximum rate of frequency change constraints were set as follows: =-0.40Hz and =-0.40Hz / s, that is =-0.4, =1. First, the control parameters of the synchronous generator speed control system are obtained through system identification methods. , as well as Furthermore, by linearizing the system frequency and the output power of the synchronous generator, the linearized frequency slope can be obtained. =-0.2 and linearized power slope =-0.0145. Next, based on the linearized frequency and power curve, the linearized power of the wind farm is constructed. By integrating it (assuming the wind farm participates in primary frequency regulation for 20 seconds) and setting the integral value to 0, the total primary frequency regulation gain of the wind farm (per unit value, with the reference capacity being the total system capacity) can be obtained. =-7.57. Figures 4 to 7 The paper presents a comparison between the system linearized frequency, the linearized power of the synchronous unit, the linearized power of a single wind farm, and the corresponding rotor speed with the actual simulation curves. It can be seen that after linearizing the power generation of the wind farm, the changes in rotor speed during the primary frequency regulation can still be simulated well. The lowest speed (per unit value) is 1.1138, which has a relative error of 0.3143% compared with the actual simulation result of 1.1173. The speed at the end of the primary frequency regulation is 1.1989, which has a relative error of 0.0205% compared with the actual simulation result of 1.1987. This effectively verifies the accuracy of the method of the present invention and provides convenience for the subsequent tuning of frequency control parameters of wind farms.

[0155] Based on the initial rotational speeds of the four wind farms, their respective rotational speed ranges were determined. The rotor speeds (per unit value) of W1 to W4 were 0.8862, 1.0517, 1.1624, and 1.2, respectively, placing them in the low, medium, high, and constant speed ranges. The distribution coefficient between W1 and W2 was determined based on the magnitude of the rotor kinetic energy. and The values ​​were 0.3843 and 0.6157 respectively, thus determining... and The values ​​are -2.9092 and -4.6608 respectively. The W3 station, located in the high-speed range, has a distribution coefficient... =0, with the target speed being greater than 0.9 at the end of the first frequency regulation, the primary frequency regulation coefficient is set to . =-0.5542. Combined with... , as well as The tuning results show that the system frequency does not yet meet the constraints (the lowest frequency is 49.5489 Hz, and the maximum frequency change rate is -0.4135 Hz / s), indicating an inertial deficit. =0.8408s and primary frequency modulation deficit =-1.1838. To maximize the utilization of W4's rotor kinetic energy, it is made to bear the inertial deficit. At the same time The setting is set to -0.5948 to ensure that the speed is not lower than 0.8 at the end of the first frequency regulation. The remaining first frequency regulation deficit (-0.5890) is shared by the two energy storage power stations and the high-voltage DC according to the power reserve.

[0156] To demonstrate the superiority of the method of this invention, three different control methods, including the method of this invention, are compared below. Control method 1 employs the same additional active power control strategy for all wind farms across all speed ranges, namely, absorbing the output power of synchronous generators and releasing zero energy during primary frequency regulation, so that the speed returns to the initial level at the end of primary frequency regulation. Control method 2 is the method of this invention. In control method 3, all wind farms use traditional virtual droop control, i.e., the primary frequency regulation control parameters remain constant. Figure 8 The paper presents the system frequency trajectories in four scenarios, including when the wind farm does not participate in frequency regulation. It is evident that, compared with different control methods, the method of this invention not only makes the system frequency dynamic process smoother and avoids secondary frequency drops, but also more effectively limits the maximum frequency deviation. The system frequency response indicators under the four control methods are shown in Table 1. It is clear that the method of this invention is superior to the other two methods in suppressing the maximum frequency change rate, maximum frequency deviation, and quasi-steady-state frequency deviation. In contrast, the traditional constant parameter control method causes a secondary frequency drop when the wind farm exits frequency regulation, which is detrimental to the stability and recovery of the transient frequency. Figures 9 to 12 The power and speed curves of wind farms under control method 1 and the method of this invention were compared. It can be seen that in control method 1, all four wind farms (W1 to W4) achieved speed self-recovery during the first frequency regulation process. However, its power support effect was very limited, with a significant drop in power level in the later stage of the first frequency regulation. In particular, W4 even reached the power limit after a frequency drop of 0.66 seconds. In contrast, the method of this invention allows W1 and W2 in the low-to-medium speed range to release more rotor kinetic energy while ensuring speed self-recovery. At the same time, it enables W3 and W4 in the high-speed and constant-speed ranges to provide more sustained power support for the system. For example, after determining the frequency regulation parameters of W4 using the method of this invention, its speed is maintained at 0.8 (per unit value) after participating in the first frequency regulation for 20 seconds, thereby avoiding premature exit from frequency regulation due to reaching the minimum speed and causing a secondary drop.

[0157] Table 1 Frequency response indicators under different control methods in the embodiments of the present invention

[0158] ;

[0159] The above description is merely a preferred embodiment of the present invention and is not intended to limit the invention. Various modifications and variations can be made to the present invention by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.

Claims

1. A wind farm control method considering dynamic constraints on rotor speed, characterized in that, include: Obtain the operating parameters of synchronous generator units in the power grid; Construct an additional active power control model for wind farms that includes power optimization control; Based on the operating parameters and the additional active power control model, combined with the piecewise function principle, the grid frequency and synchronous generator output power are linearized to obtain a piecewise linear expression for the total power increment of the wind farm, including: The operating parameters include the configuration parameters of the synchronous generator units and the governor data; a speed control system model is obtained based on the governor data; a frequency response equation containing the power increment of the wind farm is obtained based on the configuration parameters, the speed control system model, and a preset low-frequency accident; a time-domain expression for the frequency deviation of the power grid is obtained based on the frequency response equation, the additional active power control model, and preset frequency safety constraints; the time-domain expression for the frequency deviation is linearized based on the piecewise function principle to obtain a piecewise linear expression for the frequency deviation of the power grid; a first expression is obtained based on the speed control system model and the time-domain expression for the frequency deviation; the first expression is subjected to an inverse Laplace transform to obtain a time-domain expression for the power increment of the synchronous generator units; the time-domain expression for the power increment is linearized based on the piecewise function principle to obtain a piecewise linear expression for the power increment of the synchronous generator units; a piecewise linear expression for the total power increment of the wind farm is obtained based on the additional active power control model, the piecewise linear expression for the frequency deviation, and the piecewise linear expression for the power increment. The first equation is obtained by piecewise fitting based on the wind power coefficient and rotor speed; the piecewise expression of rotor speed is obtained based on the rotor motion equation of the wind farm, the first equation, and the piecewise linear expression of the total power increment; the control parameters of the wind farm for each speed segment are tuned based on the piecewise expression of rotor speed; the control parameters include at least the primary frequency regulation parameters; the wind farm is controlled based on the control parameters.

2. The wind farm control method considering dynamic constraints on rotor speed according to claim 1, characterized in that, It also includes obtaining the slopes of the piecewise linear expression for the frequency deviation and the piecewise linear expression for the power increment, including: During a single frequency modulation period, the time-domain expression of the frequency deviation and the piecewise linear expression of the frequency deviation are integrated to obtain a first integral and a second integral, respectively; the first integral and the second integral are then solved to obtain the slope of the piecewise linear expression of the frequency deviation. During a single frequency modulation period, the time-domain expression of the power increment and the piecewise linear expression of the power increment are integrated to obtain the third integral and the fourth integral, respectively; the third integral and the fourth integral are then solved to obtain the slope of the piecewise linear expression of the power increment.

3. The wind farm control method considering dynamic constraints on rotor speed according to claim 2, characterized in that, Based on the rotor motion equation of the wind farm, the first equation, and the piecewise linear expression of the total power increment, the piecewise expression of the rotor speed is obtained as follows: Based on the rotor motion equation of the wind farm, the first equation, and the piecewise linear expression of the total power increment, the piecewise rotor motion equation is obtained. The differential equation is solved based on the piecewise rotor motion equation to obtain the piecewise expression of the rotor speed. The piecewise expression of the rotor speed includes medium and low speed segments, high speed segments, and constant speed segments.

4. The wind farm control method considering dynamic constraints on rotor speed according to claim 3, characterized in that, The control parameter tuning for wind farms in each speed segment, based on the aforementioned rotor speed segment expression, includes: The control parameters of each wind farm in the low-to-medium speed segment are tuned according to the piecewise expression of rotor speed and the piecewise linear expression of total power increment; the control parameters of each wind farm in the low-to-medium speed segment include the additional active power control transfer function and primary frequency regulation parameters of the additional active power control model; The control parameters of each wind farm in the high-speed segment are tuned according to the rotor speed segment expression; the control parameters of each wind farm in the high-speed segment include primary frequency regulation parameters; The control parameters of each wind farm station in the constant speed segment are tuned according to the segmented rotor speed expression and the segmented rotor motion equation; the control parameters of each wind farm station in the constant speed segment include virtual inertia parameters and primary frequency regulation parameters; After the control parameters of each wind farm section are set, the preset system frequency response index of each wind farm section is calculated, and the primary frequency regulation parameters of each speed segment are judged in combination with the preset frequency safety constraints. If they are not satisfied, the power support of the primary frequency regulation parameters of each speed segment is set by using preset fast frequency regulation resources.

5. The wind farm control method considering dynamic constraints on rotor speed according to claim 4, characterized in that, The control parameters for each wind farm in the low-to-medium speed segment are determined based on the piecewise expression for rotor speed and the piecewise linear expression for total power increment, including: Integrating the piecewise linear expression of the total power increment yields the fifth integral expression; setting the fifth integral expression equal to 0 and solving it yields the total primary frequency regulation gain of the wind farm in the medium-low speed segment. The distribution coefficient of the medium- and low-speed segment is obtained based on the rotor kinetic energy of each station in the medium- and low-speed segment. The additional active power control transfer function and primary frequency regulation parameters of each wind farm in the medium-low speed segment are obtained based on the total primary frequency regulation gain and allocation coefficient of the wind farm in the medium-low speed segment. Substitute the additional active power control transfer function and primary frequency regulation parameters of each wind farm in the medium-low speed segment into the rotor speed segmented expression to calculate the minimum wind farm speed during the primary frequency regulation period. If there is a limit violation, reduce the primary frequency regulation parameters until the minimum speed is higher than the minimum critical speed.

6. The wind farm control method considering dynamic constraints on rotor speed according to claim 5, characterized in that, The control parameters for each wind farm in the high-speed segment are tuned according to the rotor speed segment expression, including: Set the allocation coefficient of the wind farm in the high-speed segment to 0 and substitute it into the rotor speed segment expression to obtain the second expression; based on the second expression, perform primary frequency regulation parameter optimization for the high-speed segment, select the maximum primary frequency regulation parameter that makes the speed of the wind farm in the high-speed segment greater than or equal to the upper boundary value of the low-speed zone at the end of the primary frequency regulation, and obtain the primary frequency regulation parameters of each wind farm in the high-speed segment.

7. The wind farm control method considering dynamic constraints on rotor speed according to claim 6, characterized in that, The control parameters for each wind farm in the constant speed segment are determined based on the segmented rotor speed expression and the segmented rotor motion equation, including: Based on the virtual inertia coefficient and primary frequency regulation parameters of wind farms in the constant speed segment, a constant speed segment power increment expression is constructed; the allocation coefficient of the wind farms in the constant speed segment is set to 0, and a third expression is obtained according to the constant speed segment power increment expression, the segmented rotor motion equation, and the rotor speed segment expression; based on the third expression and the rotor speed constraint and power up-adjustment space constraint, the virtual inertia parameters and primary frequency regulation parameters of each wind farm in the constant speed zone are obtained.

8. A wind farm control device considering dynamic constraints on rotor speed, for implementing the method described in any one of claims 1 to 7.

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