CN112448400B - Robust optimal scheduling method and system for determining wind power primary frequency modulation reserve - Google Patents
Robust optimal scheduling method and system for determining wind power primary frequency modulation reserve Download PDFInfo
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- H—ELECTRICITY
- H02—GENERATION; CONVERSION OR DISTRIBUTION OF ELECTRIC POWER
- H02J—CIRCUIT ARRANGEMENTS OR SYSTEMS FOR SUPPLYING OR DISTRIBUTING ELECTRIC POWER; SYSTEMS FOR STORING ELECTRIC ENERGY
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- H02—GENERATION; CONVERSION OR DISTRIBUTION OF ELECTRIC POWER
- H02J—CIRCUIT ARRANGEMENTS OR SYSTEMS FOR SUPPLYING OR DISTRIBUTING ELECTRIC POWER; SYSTEMS FOR STORING ELECTRIC ENERGY
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Abstract
The invention discloses a robust optimal scheduling method and a robust optimal scheduling system for determining wind power primary frequency modulation reserve, which comprise the following steps: establishing primary frequency modulation standby constraint of a synchronous generator and a wind turbine generator based on the slope climbing rate of a speed regulator; establishing a two-stage economic optimization robust scheduling model containing primary frequency modulation standby constraints of the synchronous generator and the wind turbine generator; and screening out a key scene set in the wind power output scene set in a day, solving the robust optimization scheduling model aiming at the key scene set and determining the wind power primary frequency modulation standby. The method provided by the invention effectively reduces the calculation difficulty and can more accurately formulate the primary frequency modulation standby strategy.
Description
Technical Field
The invention belongs to the technical field of power systems, and particularly relates to a robust optimal scheduling method and system for determining wind power primary frequency modulation standby.
Background
With the rapid development of power systems and the improvement of environmental protection requirements of various countries in the world, renewable energy power generation represented by wind power and photovoltaic is more and more emphasized. It is worth noting that access to a large amount of renewable energy in a power system presents challenges to system frequency stabilization. Taking wind power which cannot be scheduled as an example, the influence of the wind power on system frequency control is mainly embodied in the following two points: (1) the converter decouples the frequency of a generator rotor and an electric power system, namely decoupling the mechanical power of a wind turbine generator and the electromagnetic power of the electric power system, so that a fan has no inertial response capability, and the wind turbine generator usually runs in a maximum power tracking mode and cannot reserve primary frequency modulation for standby; (2) wind power is connected to the power grid in a large scale to replace part of traditional synchronous generator sets with frequency modulation capacity, when frequency fluctuation is generated in the system due to faults and the like, inertia of the wind power sets is 0, standby cannot be provided, and inertia response capacity and frequency modulation standby capacity of the system are reduced.
Part of scholars and engineering experts provide a virtual synchronous machine technology, and links such as a motion equation, primary frequency modulation and the like of a rotor of a simulated synchronous generator are introduced into a power supply controller containing a power electronic converter, so that a new energy source unit adopting the device for grid connection has the characteristics of inertia, damping, frequency modulation, voltage regulation and the like of grid connection operation of the synchronous generator. The comparison shows that the virtual synchronous machine technology can provide larger inertia and system frequency stability compared with the droop control. Therefore, the virtual synchronous generator of the wind turbine generator has the capacity of participating in frequency modulation in the system operation process, researches on the participation of the wind turbine generator in the primary frequency modulation response of the power system, and has important significance in coordinating with other synchronous generator sets in the system to reserve primary frequency modulation for later use.
Disclosure of Invention
In order to solve the defects in the prior art, the invention provides a robust optimal scheduling method and a robust optimal scheduling system for determining wind power primary frequency modulation reserve, the virtual synchronous generator technology is utilized to enable a wind power generator set to have frequency modulation capacity, the primary frequency modulation reserve of the synchronous generator set in the wind power and power system is determined through robust optimal scheduling, the frequency modulation capacity of the wind power is fully utilized, and the frequency stability of the system is improved.
In order to achieve the above purpose, the invention adopts the following technical scheme: a robust optimization scheduling method for determining wind power primary frequency modulation reserve is characterized by comprising the following steps:
screening out a key scene set in the daily wind power output scene set;
solving a pre-established two-stage economic optimization robust scheduling model aiming at a key scene set of the wind power output in the day to obtain the output of a traditional synchronous generator set based on a wind power prediction expected value in the day, the unbalance reserve left for dealing with the error between the wind power output in the day and the prediction expected value, the output regulated again by the traditional synchronous generator set in the day, the primary frequency modulation reserve capacity and the load shedding capacity of the wind power generator set in the day and the traditional synchronous generator set;
the two-stage economic optimization robust scheduling model is obtained according to pre-established primary frequency modulation standby constraint of the synchronous generator based on the slope climbing rate of the speed regulator and primary frequency modulation standby constraint of the wind generation set;
the intra-day wind power output scene is data of active output power of the wind driven generators in a preset time period, and the intra-day wind power output scene set is a set of active output power data of a plurality of groups of wind driven generators in the preset time period; the intra-day wind power output key scene set represents a set of scenes in which the intra-day wind power output and the prediction deviation before the day exceed a set threshold value in the intra-day wind power output scene set.
The robust optimal scheduling method for determining wind power primary frequency modulation reserve is characterized by comprising the following steps of: the synchronous generator primary frequency modulation standby constraint based on the slope climbing rate of the speed regulator is specifically as follows:
wherein:
for the primary frequency modulation standby of the conventional synchronous generator set i, P loss For reduced active power output caused by a fault in a unit in an electric power system, C i For the i speed regulator of the synchronous generator set, M H Is a transient time constant, f, of the power system 0 For the initial normal operating frequency, f, of the power system d Representing the frequency of the dead zone, f M Representing the lowest point of the power system frequency for the case where the governor is at the maximum ramp rate.
The robust optimal scheduling method for determining wind power primary frequency modulation reserve is characterized by comprising the following steps of: the primary frequency modulation standby constraint of the wind turbine generator is as follows:
in the formula:
for the primary frequency modulation standby of the wind turbine generator, epsilon is the coefficient, P, for the active power output of the wind turbine generator N Rated installed capacity for wind turbine generator, C W For the speed regulator climbing rate after the wind turbine generator is simulated by the virtual synchronous generator set M H Is a transient time constant, f, of the power system 0 For the initial normal operating frequency, f, of the power system d Representing the dead band frequency, f M Lowest point of frequency, P, of electric system representing maximum rate of climb of speed governor loss For reduced active power output caused by a failure of a unit in the power system,
and
the actual wind power output and the wind power output in the maximum power tracking mode are respectively.
The robust optimal scheduling method for determining wind power primary frequency modulation reserve is characterized by comprising the following steps of: the two-stage economic optimization robust scheduling model specifically comprises the following steps:
the first stage is day-ahead economic optimization scheduling, and the output and power imbalance reserve of the traditional synchronous generator set under the wind power output expected value is determined; the second stage is a day-in stage, the minimum balance cost in a given wind power output scene set omega is taken as a target, the wind power output before the day is expressed by an expected value and is taken as a basic scene, the wind power output before the day is expressed by an superscript 0, and the day-in scene is expressed by an superscript s;
the two-stage economic optimization robust scheduling model objective function is as follows:
in the formula: t is a scheduling time interval, and T is 1-T; n is a radical of hydrogen G 、N W And N B The number of power nodes of the traditional synchronous generator set, the wind turbine generator set and the system is respectively 1-N G ；k＝1～(N G +N w )；m＝1～N B ；
And
the method comprises the steps that an active output and an unbalanced power of a traditional synchronous generator set i in a t period in a basic scene are respectively reserved up and down in a unit MW; c G,i 、
And
the active output cost, the power imbalance upper standby cost and the lower standby cost coefficient of the traditional synchronous generator set i are respectively calculated;
and
adjusting values of the active output of a traditional synchronous generator set i on the basis of the output of the generator set in a basic scene at t in a daily scene s;
is a primary standby of a traditional synchronous generator set or a wind turbine set k under a time t in a day scene s,
the primary standby cost coefficient of the traditional synchronous generator set or the wind turbine set k;
is the load shedding quantity, C, of the node m of the power system at the moment t L,m Cutting a load cost coefficient for a power system node m;
in the day-ahead scheduling, a wind power output predicted expected value is used as a basic scene, a scheduling strategy with the minimum output and unbalanced standby cost of the traditional synchronous generator set is searched, and scheduling constraints are as follows:
in the formula: i belongs to m, w belongs to m and l belongs to m and respectively represents a traditional synchronous generator set i, a wind turbine generator set w and a line l which are connected with a power system node m;
the expected output of the wind turbine generator w at t time in the basic scene; p is L,m,t The load on the node m of the power system is t;
the transmission power of a line l connecting nodes m and n of the power system at t in a basic scene;
and
the phase angles of the nodes m and n of the power system at t time in the basic scene are respectively; x is the number of mn Reactance of the line connecting the nodes m, n of the power system;
and P G,i The output of the traditional synchronous generator set i is respectively the upper limit and the lower limit;
the active output of a traditional synchronous generator set i in a t-1 time period in a basic scene; r U,i And R D,i Respectively an upper limit and a lower limit of the climbing of a traditional synchronous generator set i;
and P l mn The upper limit and the lower limit of the transmission power of a line l connected with nodes m and n of the power system are respectively set;
and
the lower limits of the upper standby and the lower standby of the traditional synchronous generator set i with unbalanced power in the period t are respectively set;
the method comprises the following steps of performing synchronous generator set output adjustment on each scene in a wind power output scene set omega during daily operation of a power system, and searching for the most serious scene adjustment cost, wherein the most serious scene represents the highest optimized scheduling cost in the scene, and the corresponding constraints are as follows:
in the formula: s represents the s th scene in the wind power output scene set omega, and the total number of scenes corresponding to s is the number of scenes in the wind power output scene set;
the actual output of the wind turbine generator w at the s day scene t;
representing the load on the power system node m at t;
the maximum cutting load;
the method is characterized in that primary frequency modulation standby of a traditional synchronous generator set or a wind turbine set y at the t moment of the s-th day scene is represented, and y is 1 to (N) G +N w -1)；C y Representing the climbing rate of a speed regulator of a traditional synchronous generator set or a wind turbine generator set y;
representing the primary frequency modulation standby of the wind turbine generator w at the t moment of the s day scene;
to representWind power output of the wind turbine generator in the mode of tracking the maximum power of the w at the moment t of the s-th intraday scene.
The robust optimal scheduling method for determining wind power primary frequency modulation reserve is characterized by comprising the following steps of: the method for screening out the key scene set with the concentrated wind power output scene in the day specifically comprises the following steps:
the method comprises the steps of calculating difference values between a predicted wind power output expected value in a preset time period before the day and wind power output in the preset time period contained in a given wind power output scene set in the day, summing the difference values, sorting the sum of the difference values obtained in all the scenes in a descending order, intercepting the previous x values according to a given threshold value, and forming an initial key scene set by the corresponding x scenes
Representing the wind power output corresponding to the s1 th intraday scene,
and representing the wind power output corresponding to the sx day internal scene.
The robust optimal scheduling method for determining wind power primary frequency modulation reserve is characterized by comprising the following steps of: the method comprises the following steps of solving a two-stage economic optimization robust scheduling model aiming at a key scene set of the intraday wind power output, obtaining the output of a traditional synchronous generator set based on a wind power prediction expected value in the day, reserving unbalanced equipment for dealing with errors existing between the intraday wind power output and the prediction expected value, adjusting the output of the intraday traditional synchronous generator set again, the primary frequency modulation reserve capacity and the load shedding capacity of the wind power generator set and the traditional synchronous generator set, and further obtaining the total scheduling economic cost in the day before the day, wherein the specific steps comprise:
1) for a set of key scenes omega m Solving the simplified objective function represented by the formula (29) to obtain the output of the traditional synchronous generator set based on the wind power prediction expected value in the basic scene in the day-ahead
And reserve power imbalance for error between the wind power output and the predicted expected value in the day
Lower reserve
Form a scheduling policy X of day ahead m At the same time, the key set omega is obtained by adding the constraint formula (30) m Corresponding second stage regulation costs, including output readjustment costs of the conventional generator set in the day
Primary frequency modulation spare cost of all units
And load shedding cost
Selecting the maximum adjusting cost corresponding to the key set as beta M ；
Beta is the adjustment cost of the second-stage day-internal operation stage, and the formula (29) is a simplification of the formula (11):
the β includes the following constraints:
2) set omega \ omega for scene m Each scene in (a) calculates the following objective function:
β s remove the critical scene set omega from the scene set omega m The objective function value corresponding to the external scene set is as shown in formula (31), the objective function of formula (31) needs to satisfy the constraints shown in formulas (19) - (28), and the objective function is specific to the scene set omega \ omega m The objective function value obtained by calculating each scene in the sequence is arranged to be the maximum value
The wind power output of the scene s' corresponding to the maximum objective function value is recorded as
Wherein: omega/omega m Representing the key scene set omega in the scene set omega m An outer set of scenes;
denotes the maximum objective function value β' s Wind power output under the corresponding s' th real-time scene;
3) if beta' S ＞β M Then, then
The newly found maximum objective function value beta 'in the third step' s Wind power output under corresponding s' th real-time scene
Added to the original key scene set omega m Turning to step 1); otherwise, outputting the scheduling strategy X of the step 1) m And the scheduling strategy of the step 2) and the total optimized scheduling cost in the day before, wherein the scheduling strategy of the step 2) is an upper adjustment value of the active output of the traditional synchronous generator set in the day on the basis of the output of the generator set in the basic scene
Lower adjustment value
Of wind-power and conventional synchronous generatorsIs ready for use at one time
And load shedding amount of power system node
And ending the iteration.
The robust optimal scheduling method for determining wind power primary frequency modulation reserve is characterized by comprising the following steps of: the preset time period is 24 time periods.
A robust optimization scheduling system for determining wind power primary frequency modulation reserve is characterized by comprising:
the key scene set screening module is used for screening key scene sets in the intra-day wind power output scene set;
the method comprises the steps of solving a pre-established two-stage economic optimization robust scheduling model module, solving a pre-established two-stage economic optimization robust scheduling model aiming at a key scene set of the wind power output in the day, and obtaining the output of a traditional synchronous generator set based on a wind power prediction expected value in the day, unbalanced standby reserved for dealing with errors existing between the wind power output in the day and the prediction expected value, the output of readjustment of the traditional synchronous generator set in the day, the primary frequency modulation standby capacity and the load shedding capacity of the wind power generator set in the day and the traditional synchronous generator set;
the two-stage economic optimization robust scheduling model is obtained according to pre-established primary frequency modulation standby constraint of the synchronous generator based on the slope climbing rate of the speed regulator and primary frequency modulation standby constraint of the wind generating set;
the intra-day wind power output scene is data of active output power of the wind driven generators in a preset time period, and the intra-day wind power output scene set is a set of active output power data of a plurality of groups of wind driven generators in the preset time period; the intra-day wind power output key scene set represents a set of scenes in which the intra-day wind power output and the prediction deviation before the day in the intra-day wind power output scene set exceed a set threshold value.
The robust optimization scheduling system for determining wind power primary frequency modulation reserve is characterized in that: further comprising: a model building module; the model building module comprises:
the synchronous generator primary frequency modulation standby model establishing unit is used for establishing primary frequency modulation standby constraint of the synchronous generator based on the slope climbing rate of the speed regulator;
the wind turbine generator primary frequency modulation standby constraint establishing unit is used for establishing primary frequency modulation standby constraints of the wind turbine generator;
the two-stage robust optimization scheduling model establishing unit is used for establishing a two-stage robust optimization scheduling model containing primary frequency modulation standby constraint of the synchronous generator and primary frequency modulation standby constraint of the wind generating set;
the robust optimization scheduling system for determining wind power primary frequency modulation reserve is characterized in that: the day wind power output key scene set screening module comprises:
the processing unit is used for making difference values between the wind power output expected value of the predicted preset time period in the day and the wind power output of the preset time period contained in the given wind power output scene set in the day, summing the difference values, and sequencing the sum of the difference values obtained in all the scenes in a descending order;
a screening unit for intercepting the previous x values according to a given threshold value, and forming an initial key scene set by the corresponding x scenes
Representing the wind power output corresponding to the s1 th intraday scene,
and representing the wind power output corresponding to the sx day scene.
Has the advantages that: on the basis of the related technical criteria of the virtual synchronous machine, the primary wind power frequency modulation standby constraint of the day-internal operation time scale is established, day-ahead and day-internal operation is coordinated, the problem of power imbalance caused by large-scale wind power grid connection is solved through robust optimization, wherein the primary frequency modulation standby capacity of a wind power unit and a synchronous generator adopting the virtual synchronous generator technology is calculated in the day-internal operation stage, the system frequency falling process is not out of limit after the synchronous generator unit fails, the wind power unit has the capability of quick response under the emergency conditions of unit failure, direct current blocking and the like, and enough primary standby can be reserved by fully utilizing the characteristics of the wind power unit to obtain the starting time for other frequency modulation measures of the system; in order to solve the problem, a key scene set is screened out, so that the calculation difficulty is reduced, and the model calculation efficiency is improved.
Drawings
FIG. 1 is a flow chart of a scheduling method according to an embodiment of the present invention;
FIG. 2 is a graph of governor power versus frequency for one embodiment of the present invention;
fig. 3 is a wind power primary frequency modulation standby explanatory diagram according to an embodiment of the present invention.
Detailed Description
The present invention is further illustrated by the following examples, which are intended to be purely exemplary and are not intended to limit the scope of the invention, which is to be given the full breadth of the claims appended hereto.
In the case of the example 1, the following examples are given,
as shown in fig. 1, a robust optimal scheduling method for determining wind power primary frequency modulation backup specifically includes the following steps:
step 2, the wind turbine generator has primary frequency modulation capability after using the virtual synchronous machine technology, and primary frequency modulation standby constraint of the wind turbine generator is established based on the primary frequency modulation capability;
step 3, aiming at uncertain natural characteristics of wind power output prediction, establishing a two-stage economic optimization robust scheduling model containing primary frequency modulation standby constraints of the synchronous generator and primary frequency modulation standby constraints of the wind power generator set;
and 4, screening out key scenes in the wind power output scene set, and solving the two-stage economic optimization robust scheduling model aiming at the key scene set to obtain the total optimization scheduling cost in the day before, the primary wind power reserve capacity in the day and the primary reserve capacity of the traditional generator.
The step 1, when the power system is scheduled day ahead, based on the synchronous generator dynamic process during primary frequency modulation, establishes the primary frequency modulation standby constraint of the synchronous generator based on the ramp rate of the speed regulator, and the specific steps include:
1.1 when the power system has reduced active output, the power system frequency is reduced, at the moment, the speed regulator responds in the standby range, and the mechanical power of the power system is increased to enable the mechanical power and the electromagnetic power to reach balance again. Neglecting load damping, the power system frequency variation versus power is as follows:
wherein: m H Is a transient time constant of the power system; f (t) is the power system frequency at time t; delta P is the deviation of the active output and the active load of the power system; p m (t) and P e (t) electrical power system mechanical power and electromagnetic power, respectively;
1.2 the two-sided integration of equation (1) yields:
wherein: f. of N The frequency of the lowest point after the generator set is in fault; f. of 0 Is the initial normal operating frequency of the power system; t is t N The time to reach the lowest point frequency in the process of frequency descending;
1.3 from the governor power-frequency variation diagram of fig. 2, equation (2) above can be equivalently in the form:
wherein: p loss Reduced active power output for a unit fault in the power system; t is t d Is the time to reach the dead band frequency during the frequency descent; c N The climbing rate of the speed regulator.
In fig. 2: p is l Represents t d And t N The change quantity of the difference value of the mechanical power and the electromagnetic power of the electric power system between the moments; f. of d Represents a dead band frequency;
representing the primary frequency modulation standby of a traditional synchronous generator set i, wherein i is less than or equal to the total number of the synchronous generator sets;
1.4 hypothesis that there is a maximum governor ramp rate C M ，f M Corresponds to C M Representing the lowest point of the frequency of the power system when the speed governor is at the maximum climbing rate, f in the formula (3) N And C N From C M And f M Instead, then:
wherein:
an equation is calculated for the power system transient time constant.
Because of the dead zone of the frequency modulation of the speed regulator, the power fluctuation of the system is supported by inertia in a short time, so that the system can pass through
Representing the power system transient time constant.
1.5 when considering only synchronous generator sets in the system, P is lost for a set fault loss After active power output, the primary backup of the power system should satisfy the following constraints:
wherein: c i The slope climbing rate of a speed regulator of the synchronous generator set i;
the method is used for standby primary frequency modulation of the traditional synchronous generator set i.
Equations (5) and (6) represent the primary frequency modulation standby constraint of the synchronous generator based on the ramp rate of the speed governor.
Step 2, establishing primary frequency modulation standby constraint of the wind turbine generator, specifically comprising the following steps:
2.1 the existing virtual synchronous machine control makes the wind generating set have the similar frequency modulation characteristic with the synchronous generating set, when the frequency deviation of the power system is more than f d And when the active output of the virtual synchronous machine is more than 20% of the rated installed capacity of the wind turbine generator, the active output of the virtual synchronous machine can be adjusted to participate in primary frequency modulation of the power system. When the frequency of the power system drops, the active output of the virtual synchronous machine is increased, the maximum value of the active output increase is at least 10% of the rated installed capacity of the wind turbine generator, but the value of the active output increase is not too large in order to ensure that the generated energy of the wind power plant is sufficient.
2.2 if the condition of reserving the primary frequency modulation reserve is met, determining the primary frequency modulation reserve constraint of the wind turbine generator according to the primary frequency modulation reserve constraint of the synchronous generator, and the method comprises the following steps:
wherein:
the method is used for primary frequency modulation standby of the wind turbine generator; c W The climbing rate of the speed regulator after the wind turbine generator is simulated by the virtual synchronous generator set;
2.3 determining primary frequency modulation standby constraint of the wind turbine generator according to the technical requirements of the virtual synchronous machine, as follows:
wherein: epsilon is a coefficient which can improve the active power output of the wind turbine generator and is generally a numerical value larger than 10%; p N Rated installed capacity of the wind turbine;
2.4 as shown in fig. 3, the primary frequency modulation standby constraint determined by combining the primary frequency modulation standby constraint of the synchronous generator and the technical requirement of the virtual synchronous machine is obtained, and the primary frequency modulation standby constraint finally applicable to the wind turbine generator is obtained as follows:
in the formula:
and
the actual wind power output and the wind power output in the maximum power tracking mode are respectively.
In step 3, the two-stage economic optimization robust scheduling model is established as follows:
in the optimization scheduling process, uncertainty of wind power output cannot be ignored, and day-ahead power imbalance reserve needs to be considered (for the day-ahead wind power output and prediction, adjustable reserve, namely day-ahead power imbalance reserve, is reserved for a traditional unit in the day), so the invention provides a day-ahead and day-ahead two-stage economic optimization robust scheduling model. Assuming that the load prediction is a determined value, under the wind power prediction expected value, the method determines the output and power imbalance reserve of the traditional synchronous generator set through day-ahead scheduling so as to deal with the error between the wind power output and the wind power prediction during real-time operation. Under the intra-day scale, 50 groups of wind power output in different days are set according to the fact that the deviation between the upper deviation and the lower deviation of the predicted wind power output value in the day ahead is within 15%, under the given different wind power output, the output of the traditional synchronous generator set needs to be adjusted again within the constraint range of output and power unbalance reserve determined in the day ahead, and on the basis, the traditional synchronous generator set and the wind power generator set need to be reserved for primary frequency modulation reserve and need to be subjected to load shedding if necessary.
3.1 in an optimized scheduling model, in a first stage, performing day-ahead economic optimized scheduling, and determining output and power imbalance reserve of a traditional synchronous generator set under a wind power output expected value (namely, wind power output predicted day-ahead); the second stage is a intraday stage, uncertainty is represented by a plurality of given wind power output scenes, a scene set containing all the given wind power output scenes is represented by omega, the wind power output scenes are data of active output power of the wind driven generators in 24 time periods, and the scene set of the wind power output scenes is a set of the active output power data of a plurality of groups of the wind driven generators in 24 time periods; the method aims at minimizing the balance standby cost in the wind power output scene set omega, and considers the output readjustment of the traditional units, the primary frequency modulation standby of all the units and the load shedding under the wind power output scene s in a day. In the model, the day-ahead wind power output is expressed by a prediction expected value, namely a wind power output basic scene, and is expressed by an superscript 0, and a day-inside wind power output scene is expressed by an superscript s. The specific mathematical expression of the objective function of the two-stage economic optimization robust scheduling model is as follows, and the objective function is obtained as the total optimization scheduling cost in the day before:
in the formula: t is a scheduling time interval, and 24h, T is 1-T; n is a radical of hydrogen G 、N W And N B The number of power nodes of the traditional synchronous generator set, the wind turbine generator set and the system is respectively 1-N G ；k＝1～(N G +N w )；m＝1～N B ；
And
the method comprises the steps that an active output and an unbalanced power of a traditional synchronous generator set i in a t period in a basic scene are respectively reserved up and down in a unit MW; c G,i 、
And
the coefficients of i active output cost, i power imbalance upper standby cost and i lower standby cost of the traditional synchronous generator set are respectively calculated;
and
adjusting values of the active output of a traditional synchronous generator set i on the basis of the output of the generator set in a basic scene at t in a daily scene s;
is a primary standby of a traditional synchronous generator set or a wind turbine set k at t in a scene s in the day,
a primary standby cost coefficient of a traditional synchronous generator set or a wind turbine set k;
is the load shedding quantity, C, of the node m of the power system at the moment t L,m Cutting a load cost coefficient for a power system node m;
3.2 for the objective function of the above formula (11), the day-ahead scheduling takes the predicted expected value of wind power output as a basic scene, and a scheduling strategy with the minimum output and unbalanced standby cost of the traditional synchronous generator set is searched, wherein the scheduling constraint is as follows:
in the formula: i belongs to m, w belongs to m and l belongs to m and respectively represents a traditional synchronous generator set i, a wind turbine generator set w and a line l which are connected with a power system node m;
the expected output of the wind turbine generator w at t time in the basic scene; p L,m,t The load on the node m of the power system is t;
the transmission power of a line l connecting nodes m and n of the power system at t in a basic scene;
and
the phase angles of the nodes m and n of the power system at t time in the basic scene are respectively; x is the number of mn Reactance of the line connecting the nodes m, n of the power system; p G,i And P G,i The output of the traditional synchronous generator set i is respectively the upper limit and the lower limit;
the method comprises the steps that i active output of a traditional synchronous generator set is obtained at a t-1 time period in a basic scene; r U,i And R D,i Respectively an upper limit and a lower limit of the climbing of a traditional synchronous generator set i;
and P l mn The upper limit and the lower limit of the transmission power of a line l connected with nodes m and n of the power system are respectively set;
and
the lower limits of the upper standby and the lower standby of the traditional synchronous generator set i with unbalanced power in the period t are respectively set;
3.3 when the power system operates in the day, the traditional generating set output adjustment is carried out on each scene in the wind power output scene set omega, the most serious scene adjustment cost is searched, the most serious scene adjustment cost comprises the traditional generating set output readjustment cost, the primary frequency modulation standby cost of all the generating sets and the load shedding cost, the most serious scene represents that the optimal scheduling cost is the highest under the scene, and the corresponding constraints are as follows:
in the formula: s represents the s th scene in the wind power output scene set omega, and the total number of scenes corresponding to s is the number of scenes in the wind power output scene set;
the wind turbine generator w outputs power at the t-th day scene;
representing the load on the power system node m at t;
the maximum cutting load;
the method is characterized in that primary frequency modulation standby of a traditional synchronous generator set or a wind turbine set y at the t moment of the s-th day scene is represented, and y is 1 to (N) G +N w -1)；C y Representing the climbing rate of a speed regulator of a traditional synchronous generator set or a wind turbine generator set y;
representing the primary frequency modulation standby of the wind turbine generator w at the t moment of the s day scene;
representing the wind power output of the wind turbine generator in the maximum power tracking mode at the t moment of the s-th real-time scene; the other variables have the same meaning as the variables in step 3.2, and the superscript s is the s-th day scene.
The two-stage economic optimization robust scheduling model is as follows: formulas (11) to (28).
In the step 4, a wind power output key scene is screened to obtain a robust optimal scheduling strategy considering wind power primary frequency modulation standby, and the specific steps are as follows:
4.1 solving the two-stage economic optimization robust scheduling model established by the invention directly has higher difficulty, and aiming at the min-max-min problem, the adjusting cost auxiliary variable beta of the second-stage daily operation stage can be introduced to replace the internal max-min problem, namely, the formula (11) is simplified as follows:
4.2 at the same time, add the following constraints:
introducing auxiliary variablesThe two-stage robust optimization scheduling model after beta is equivalent to the model before change, and the min-max-min three-layer optimization problem represented by the formula (11) becomes a single-layer optimization problem, but if all scenes in the scene set omega are considered at the same time and each scene corresponds to a series of real-time operation constraints, the problem scale is huge and is difficult to solve. Therefore, the invention provides an iteration method, which comprises two layers of problems, namely, a key scene set omega in a scene set omega is searched through a lower layer of problems m And the upper layer problem only aims at the key scene set omega m The objective function represented by equation (29) is solved. Key scene set omega m Representing a set of scenes with the most serious deviation between the wind power output in the day and the prediction in the day before in the scene set omega, wherein the upper layer problem aims at the key scene set omega m The calculated active power output of the traditional synchronous generator set can be readjusted within the standby constraint range in any scene at the daytime stage, as shown in a formula (24). The specific process is as follows:
1) the first step is as follows: the method comprises the steps of performing difference value on a wind power output expected value predicted in a preset time period (for example, 24 time periods) in the day and wind power output in the preset time period contained in a scene set, summing the difference values, sorting the sum of the difference values obtained in all the scenes in a descending order, intercepting the first x values according to a given threshold value, and forming an initial key scene set by the corresponding x scenes
Representing the wind power output corresponding to the s1 th intraday scene,
representing the wind power output corresponding to the sx day scene;
2) the second step is that: for a set of key scenes omega m Solving the simplified objective function represented by the formula (29) to obtain the traditional synchronous generator set output based on the wind power prediction expected value in the basic scene in the day ahead
And reserve on power imbalance for handling errors between the wind power output and the predicted expected value in the day
For later use
Form a scheduling policy X of day ahead m Meanwhile, the key set omega at the moment is obtained by adding the constraint formula (30) m And the corresponding second-stage adjusting cost is as follows: beta is a 1 ，…，β x Including the output readjustment cost of the conventional generator set in the day
Primary frequency modulation spare cost of all units
And load shedding cost
Selecting the maximum adjusting cost corresponding to the key set as beta M ；
3) The third step: aiming at the scene set omega \ omega, the day-ahead scheduling strategy obtained by the second step m Each scene in (a) calculates the following objective function:
β s remove the critical scene set omega from the scene set omega m The objective function value corresponding to the external scene set is as shown in formula (31), the objective function of formula (31) needs to satisfy the constraints shown in formulas (19) - (28), and the objective function is specific to the scene set omega \ omega m The objective function value obtained by calculating each scene in the sequence is arranged to be the maximum value
The maximum objective functionThe wind power output corresponding to the scene s' is recorded as
Wherein: omega/omega m Representing the key scene set omega in the scene set omega m An outer set of scenes;
denotes the maximum objective function value β' s Wind power output under the corresponding s' th real-time scene; one scene in the wind power output scene set omega is a preset time period output condition of one wind power generator;
4) if beta' S ＞β M If the key set screened out before is not representative of the most serious situation in the scene, then
Namely the newly found maximum objective function value beta 'in the third step' s Wind power output under corresponding s' th real-time scene
Added to the original key scene set omega m Turning to step 2); otherwise, outputting the scheduling strategy X of the second step m And the scheduling strategy of the third step is the upper adjusting value of the active output of the traditional synchronous generator set in the day on the basis of the output of the generator set in the basic scene and the total optimized scheduling cost in the day before
Lower adjustment value
Primary standby of wind turbine generator and traditional synchronous generator
And load shedding amount of power system node
And ending the iteration.
In the case of the example 2, the following examples are given,
a robust optimization scheduling system for determining wind power primary frequency modulation reserve is characterized by comprising:
the system comprises a daily wind power output key scene set screening module, a daily wind power output key scene set screening module and a daily wind power output key scene set screening module, wherein the daily wind power output key scene set screening module is used for screening a key scene set in a daily wind power output scene set;
the method comprises the steps of solving a pre-established two-stage economic optimization robust scheduling model module, solving a pre-established two-stage economic optimization robust scheduling model aiming at a key scene set of the daily wind power output to obtain the output of a traditional synchronous generator set based on a wind power prediction expected value, and reserving unbalanced standby for dealing with errors existing between the daily wind power output and the prediction expected value, and readjusting the output of the traditional synchronous generator set in the day, the primary frequency modulation standby capacity and the load shedding capacity of the wind power generator set in the day and the traditional synchronous generator set;
the two-stage economic optimization robust scheduling model is obtained according to pre-established primary frequency modulation standby constraint of the synchronous generator based on the slope climbing rate of the speed regulator and primary frequency modulation standby constraint of the wind generating set;
the intra-day wind power output scene is data of active output power of the wind driven generators in a preset time period, and the intra-day wind power output scene set is a set of active output power data of a plurality of groups of wind driven generators in the preset time period; the intra-day wind power output key scene set represents a set of scenes in which the intra-day wind power output and the prediction deviation before the day exceed a set threshold value in the intra-day wind power output scene set.
The system also includes a model building module; the model building module comprises:
the synchronous generator primary frequency modulation standby model building unit is used for building synchronous generator primary frequency modulation standby constraint based on the climbing rate of the speed regulator;
the wind turbine generator primary frequency modulation standby constraint establishing unit is used for establishing primary frequency modulation standby constraints of the wind turbine generator;
the two-stage robust optimization scheduling model establishing unit is used for establishing a two-stage robust optimization scheduling model containing primary frequency modulation standby constraint of the synchronous generator and primary frequency modulation standby constraint of the wind generating set;
the key scene set screening module for the wind power output in the day comprises:
the processing unit is used for making difference values between the wind power output expected value of the predicted preset time period in the day and the wind power output of the preset time period contained in the given wind power output scene set in the day, summing the difference values, and sequencing the sum of the difference values obtained in all the scenes in a descending order;
a screening unit for intercepting the previous x values according to a given threshold value, and forming an initial key scene set by the corresponding x scenes
Representing the wind power output corresponding to the s1 th intraday scene,
and representing the wind power output corresponding to the sx day scene.
The invention adopts a modified model and algorithm provided by IEEE57 node arithmetic test, wherein the unit on the node 3 is a wind turbine with the rated capacity of 140MW, the total installed capacity of the system is about 2000MW, and the arithmetic adopts 50 wind power output scenes to represent uncertain information. According to the China power grid operation standard, the rated frequency of a power grid is 50Hz, and the lowest limit of the frequency is 49.8 Hz.
The large-scale wind power integration causes the shutdown of part of traditional synchronous generator sets to meet the wind power consumption, and the method for replacing the synchronous generator by the wind power set is adopted to simulate the shutdown. The capacity of the fault unit is 20MW, and the initial frequency of the system is 50 Hz.
The method screens out a scene serial number [6 ] corresponding to a key scene set through an iteration method; 49], i.e. scenario 6 and 49. The cost of primary backup is not considered to be 5375256$, the cost is considered to be 5508326 $whenprimary frequency modulation backup is considered but wind power does not participate, and the cost is considered to be 5508085 $whenwind power participates. At the moment, the dispatching cost is obviously increased after the large-scale wind power system considers the frequency response once, and the increased cost is mainly the one-time standby or load shedding cost. The wind power scene set [ 6; 49] the uncertain information contained in the wind power generation system is basically the same as the day-ahead scheduling cost under the same condition, and the uncertain information comprises the output cost of the generator set and the reserved unbalanced power reserve cost corresponding to the wind power prediction error.
The method screens out wind power key scenes, reduces the calculation difficulty, improves the model calculation efficiency, and obtains the primary reserve capacity of the wind generation set with better economy based on the related technical criteria of the virtual synchronizer.
As will be appreciated by one skilled in the art, embodiments of the present application may be provided as a method, system, or computer program product. Accordingly, the present application may take the form of an entirely hardware embodiment, an entirely software embodiment or an embodiment combining software and hardware aspects. Furthermore, the present application may take the form of a computer program product embodied on one or more computer-usable storage media (including, but not limited to, disk storage, CD-ROM, optical storage, and the like) having computer-usable program code embodied therein.
The present application is described with reference to flowchart illustrations and/or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of the application. It will be understood that each flow and/or block of the flowchart illustrations and/or block diagrams, and combinations of flows and/or blocks in the flowchart illustrations and/or block diagrams, can be implemented by computer program instructions. These computer program instructions may be provided to a processor of a general purpose computer, special purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, create means for implementing the functions specified in the flowchart flow or flows and/or block diagram block or blocks.
These computer program instructions may also be stored in a computer-readable memory that can direct a computer or other programmable data processing apparatus to function in a particular manner, such that the instructions stored in the computer-readable memory produce an article of manufacture including instruction means which implement the function specified in the flowchart flow or flows and/or block diagram block or blocks.
These computer program instructions may also be loaded onto a computer or other programmable data processing apparatus to cause a series of operational steps to be performed on the computer or other programmable apparatus to produce a computer implemented process such that the instructions which execute on the computer or other programmable apparatus provide steps for implementing the functions specified in the flowchart flow or flows and/or block diagram block or blocks.
The above description is only a preferred embodiment of the present invention, and it should be noted that, for those skilled in the art, it is possible to make various improvements and modifications without departing from the technical principle of the present invention, and those improvements and modifications should be considered as the protection scope of the present invention.
Claims (2)
1. A robust optimization scheduling method for determining wind power primary frequency modulation reserve is characterized by comprising the following steps:
screening out a key scene set in the daily wind power output scene set;
solving a pre-established two-stage economic optimization robust scheduling model aiming at a key scene set of the wind power output in the day to obtain the output of a traditional synchronous generator set based on a wind power prediction expected value in the day, the unbalance reserve left for dealing with the error between the wind power output in the day and the prediction expected value, the output regulated again by the traditional synchronous generator set in the day, the primary frequency modulation reserve capacity and the load shedding capacity of the wind power generator set in the day and the traditional synchronous generator set;
the two-stage economic optimization robust scheduling model is obtained according to pre-established primary frequency modulation standby constraint of the synchronous generator based on the slope climbing rate of the speed regulator and primary frequency modulation standby constraint of the wind generating set;
the intraday wind power output scene is data of active output power of the intraday wind driven generators in a preset time period, and the intraday wind power output scene set is a set of active output power data of a plurality of groups of wind driven generators in the preset time period; the intra-day wind power output key scene set represents a set of scenes in which intra-day wind power output and a prediction deviation before the day in the intra-day wind power output scene set exceed a set threshold;
the synchronous generator primary frequency modulation standby constraint based on the slope climbing rate of the speed regulator specifically comprises the following steps:
wherein:
for the primary frequency modulation standby of the conventional synchronous generator set i, P loss For reduced active power output caused by a fault in a unit in an electric power system, C i For the i speed regulator of the synchronous generator set, M H Is the transient time constant, f, of the power system 0 For the initial normal operating frequency, f, of the power system d Representing the frequency of the dead zone, f M Representing the lowest frequency point of the power system under the condition that the speed regulator has the maximum climbing rate;
the primary frequency modulation standby constraint of the wind turbine generator is as follows:
in the formula:
for the primary frequency modulation standby of the wind turbine generator, epsilon is the coefficient, P, for the active power output of the wind turbine generator N Rated installed capacity, C, for a wind turbine W For the speed regulator climbing rate after the wind turbine generator is simulated by the virtual synchronous generator set M H Is the transient time constant, f, of the power system 0 For the initial normal operating frequency, f, of the power system d Representing the frequency of the dead zone, f M Representing the lowest point of the frequency of the power system with the speed regulator at the maximum ramp rate, P loss For reduced active power contribution due to a group fault in the power system,
and
respectively representing the actual wind power output and the wind power output in the maximum power tracking mode;
the two-stage economic optimization robust scheduling model specifically comprises the following steps:
the first stage is day-ahead economic optimization scheduling, and the output and power imbalance reserve of the traditional synchronous generator set under the wind power output expected value is determined; the second stage is a day-in stage, the minimum balance cost in a given wind power output scene set omega is taken as a target, the wind power output before the day is expressed by an expected value and is taken as a basic scene, the wind power output before the day is expressed by an superscript 0, and the day-in scene is expressed by an superscript s;
the two-stage economic optimization robust scheduling model objective function is specifically as follows:
in the formula: t is a scheduling time interval, and T is 1-T; n is a radical of G 、N W And N B The number of the traditional synchronous generator set, the wind turbine generator set and the system power nodes is respectively, i is 1 to N G ；k＝1～(N G +N w )；m＝1～N B ；
And
the method comprises the steps that i active output and power imbalance of a traditional synchronous generator set in a t period in a basic scene are respectively reserved in an upper portion and a lower portion, and unit MW is provided; c G,i 、
And
the active output cost, the power imbalance upper standby cost and the lower standby cost coefficient of the traditional synchronous generator set i are respectively calculated;
and
adjusting values of the active output of a traditional synchronous generator set i on the basis of the output of the generator set in a basic scene at t in a daily scene s;
is a primary standby of a traditional synchronous generator set or a wind turbine set k at t in a scene s in the day,
the primary standby cost coefficient of the traditional synchronous generator set or the wind turbine set k;
is the load shedding quantity, C, of the node m of the power system at the moment t L,m Cutting a load cost coefficient for a power system node m;
in the day-ahead scheduling, a wind power output predicted expected value is used as a basic scene, a scheduling strategy with the minimum output and unbalanced standby cost of the traditional synchronous generator set is searched, and scheduling constraints are as follows:
in the formula: i belongs to m, w belongs to m and l belongs to m and respectively represents a traditional synchronous generator set i, a wind turbine generator set w and a line l which are connected with a power system node m;
the expected output of the wind turbine generator w at t time in the basic scene; p L,m,t The load on the node m of the power system is t;
the transmission power of a line l connecting nodes m and n of the power system at t in a basic scene;
and
the phase angles of the nodes m and n of the power system at t time in the basic scene are respectively; x is a radical of a fluorine atom mn Reactance of the lines connecting the nodes m, n of the power system;
andP G,i the output of the traditional synchronous generator set i is respectively the upper limit and the lower limit;
the active output of a traditional synchronous generator set i in a t-1 time period in a basic scene; r U,i And R D,i Respectively an upper limit and a lower limit of the climbing of a traditional synchronous generator set i;
and l P mn the upper limit and the lower limit of the transmission power of a line l connected with nodes m and n of the power system are respectively set;
and
the lower limits of the upper standby and the lower standby of the traditional synchronous generator set i with unbalanced power in the period t are respectively set;
the method comprises the following steps of performing synchronous generator set output adjustment on each scene in a wind power output scene set omega during the day operation of a power system, searching for the most severe scene adjustment cost, wherein the most severe scene represents that the optimal scheduling cost is highest under the scene, and the corresponding constraints are as follows:
in the formula: s represents the s-th scene in the wind power output scene set omega, and the total number of scenes corresponding to s is the number of scenes in the wind power output scene set;
the actual output of the wind turbine generator w at the s-th intraday scene t;
representing the load on the power system node m at t;
the maximum cutting load;
the method is characterized in that primary frequency modulation standby of a traditional synchronous generator set or a wind turbine set y at the t moment of the s-th day scene is represented, and y is 1 to (N) G +N w -1)；C y Representing the climbing rate of a speed regulator of a traditional synchronous generator set or a wind turbine generator set y;
representing the primary frequency modulation standby of the wind turbine generator w at the t moment of the s day scene;
representing the wind power output of the wind turbine generator in the maximum power tracking mode at the t moment of the s-th intraday scene;
the method is characterized in that the key scene set in the day wind power output scene set is screened out, and specifically comprises the following steps:
the method comprises the steps of calculating difference values between a predicted wind power output expected value in a preset time period before the day and wind power output in the preset time period contained in a given wind power output scene set in the day, summing the difference values, sorting the sum of the difference values obtained in all the scenes in a descending order, intercepting the previous x values according to a given threshold value, and forming an initial key scene set by the corresponding x scenes
Representing the wind power output corresponding to the s1 th intraday scene,
representing the wind power output corresponding to the sx day scene;
the method comprises the following steps of solving a two-stage economic optimization robust scheduling model aiming at a key scene set of wind power output in a day, obtaining output of a traditional synchronous generator set based on a wind power prediction expected value in the day, reserving unbalanced standby reserved for dealing with errors existing between the wind power output in the day and the prediction expected value, adjusting output of the traditional synchronous generator set in the day again, primary frequency modulation standby capacity and load shedding of the wind power generator set and the traditional synchronous generator set, and further obtaining total scheduling economic cost in the day before the day, wherein the specific steps comprise:
1) for a set of key scenes omega m Solving the simplified objective function represented by the formula (29) to obtain the output of the traditional synchronous generator set based on the wind power prediction expected value in the basic scene in the day-ahead
And reserve on power imbalance for handling errors between the wind power output and the predicted expected value in the day
Lower reserve
Form a scheduling policy X of day ahead m At the same time, the key set omega is obtained by adding the constraint formula (30) m Corresponding second stage regulation costs, including output readjustment costs of the conventional generator set in the day
Primary frequency modulation spare cost of all units
And load shedding cost
Selecting the maximum adjusting cost corresponding to the key set as beta M ；
Beta is the adjustment cost of the second-stage day-internal operation stage, and the formula (29) is a simplification of the formula (11):
the β includes the following constraints:
2) aiming at a scene set omega \ omega m Each scene in (a) calculates the following objective function:
β s remove the critical scene set omega from the scene set omega m The objective function value corresponding to the external scene set is shown as formula (31), and the objective function of formula (31) needs to satisfyThe constraints shown in formulas (19) to (28) are aimed at the scene set omega \ omega m The objective function value obtained by calculating each scene in the sequence is arranged to be the maximum value
The wind power output of the scene s' corresponding to the maximum objective function value is recorded as
Wherein: omega/omega m Representing the key scene set omega in the scene set omega m An outer set of scenes;
denotes the maximum objective function value β' S Wind power output under the corresponding s' th real-time scene;
3) if beta' S ＞β M Then, then
The newly found maximum objective function value beta 'in the third step' S Wind power output under corresponding s' th real-time scene
Added to the original key scene set omega m In, go to step 1); otherwise, outputting the scheduling strategy X of the step 1) m And the scheduling strategy of the step 2) and the total optimized scheduling cost in the day before, wherein the scheduling strategy of the step 2) is an upper adjustment value of the active output of the traditional synchronous generator set in the day on the basis of the output of the generator set in the basic scene
Lower adjustment value
Primary standby of wind turbine generator and traditional synchronous generator set
And load shedding amount of power system node
The iteration is finished;
the preset time period is 24 time periods.
2. A robust optimization scheduling system for determining wind power primary frequency modulation reserve is characterized by comprising:
the system comprises a daily wind power output key scene set screening module, a daily wind power output key scene set screening module and a daily wind power output key scene set screening module, wherein the daily wind power output key scene set screening module is used for screening a key scene set in a daily wind power output scene set;
the method comprises the steps of solving a pre-established two-stage economic optimization robust scheduling model module, solving a pre-established two-stage economic optimization robust scheduling model aiming at a key scene set of the wind power output in the day, and obtaining the output of a traditional synchronous generator set based on a wind power prediction expected value in the day, unbalanced standby reserved for dealing with errors existing between the wind power output in the day and the prediction expected value, the output of readjustment of the traditional synchronous generator set in the day, the primary frequency modulation standby capacity and the load shedding capacity of the wind power generator set in the day and the traditional synchronous generator set;
the two-stage economic optimization robust scheduling model is obtained according to pre-established primary frequency modulation standby constraint of the synchronous generator based on the slope climbing rate of the speed regulator and primary frequency modulation standby constraint of the wind generating set;
the intraday wind power output scene is data of active output power of the intraday wind driven generators in a preset time period, and the intraday wind power output scene set is a set of active output power data of a plurality of groups of wind driven generators in the preset time period; the intra-day wind power output key scene set represents a set of scenes in which the intra-day wind power output and the prediction deviation before the day exceed a set threshold value in the intra-day wind power output scene set;
further comprising: a model building module; the model building module comprises:
the synchronous generator primary frequency modulation standby model establishing unit is used for establishing primary frequency modulation standby constraint of the synchronous generator based on the slope climbing rate of the speed regulator;
the wind turbine generator primary frequency modulation standby constraint establishing unit is used for establishing primary frequency modulation standby constraints of the wind turbine generator;
the two-stage robust optimization scheduling model establishing unit is used for establishing a two-stage robust optimization scheduling model containing primary frequency modulation standby constraint of the synchronous generator and primary frequency modulation standby constraint of the wind generating set;
the day wind power output key scene set screening module comprises:
the processing unit is used for making difference values between the wind power output expected value predicted in the preset time period before the day and the wind power output in the preset time period in the given day wind power output scene set, summing the difference values, and sequencing the sum of the difference values obtained in all the scenes in a descending order;
a screening unit for intercepting the previous x values according to a given threshold value, and forming an initial key scene set by the corresponding x scenes
Representing the wind power output corresponding to the s1 th intraday scene,
and representing the wind power output corresponding to the sx day internal scene.
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