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Extended Generation Control and Dispatch
GENERA TION SCHEDULING AND CONTROL
Copyright © IFAC Control of Power Plants and Power Systems. Munich. Germany. 1992
EXTENDED GENERATION CONTROL AND DISPATCH G. Schwarz and H. Hafner Departnu!nJ of Program and System Developnu!nt. Siemens AG .. Vienna. Austria
Abstract: An advanced software system for Generation Control and Dispatch is presented. It is placed on well tuned coordination of the components Automalic Generation COTllrol. Economic Dispatch and Reserve Monitoring. The features of these components and their interaction are described. In cases where network transport restrictions have to be regarded, an Optimal Power Flow can be incorporated. K£lwords: Automatic generation control; stabilized control. compensated regulation. economic dispatch; anticipatory dispatch; reserve monitor; reserve determination.
INTRODUcnON
COMPONENTS Automatic Generation Control The overall objective of AGC is the power output alteration of certain electric generators within a defmed network area to meet the area's obligations expressed by minimizing the following well known equation (secondary control):
Automatic generation coTllrol (ACC) combined with economic dispatch (ED) for calculating cost optimal generator base points are well known functions that have been introduced to many control centre systems. Nevertheless improvements can be achieved e.g. by measures that avoid unnecessary regulation activities in normal situations thus contributing to overall economy while guaranteeing quick response in exceptional situations. Further improvements are useful by integration of a reserve monitor (RM), which optimally assigns reserves considerating economic aspects as well as activation speed. An optimal power flow (OPP) can be incorporated in cases where network trartSport restrictions have to be regarded.
AGC - Automatic Generation P_temp Control P_EO EO - Economic Dispatch BP OPF - Optimal Power Flow RM - Reserve Monitor SEBP STLF- Short Term Load Forecast SEBF IS - Interchange Scheduling UC - Unit Commitment P_req PFC - Penalty Factor Calculation
ACE = 6P
+
B
x
6F
~
0
(1 )
where ACE = area control error. 6P = net interchange error. 6F = frequency error and B = system frequency bias. Time and energy can also be controlled by making small adjustments to the frequency and interchange reference values respectively. To eliminate an ACE which may arise caused by steadily increasing or decreasing load an additional value calculated by an anticipation logic (anticipatory cOTllrol) can be added to ACE. Generation calculation. The ACE is processed by a controller which can handle large and small signals differently. The parameters for splitting the signal into a trend component and a swing component are calculated dynamically by using statistical attributes (moving average and standard deviation) of the ACE. To stabilize control the difference of the expected unit generation (i.e. the total desired generation delayed by a first order filter) and the measured response of the units is fed back to the input of the controller (0 Fig.2). This provides the controller with the ability to manage non-linear and variable unit behaviour. Generation distribution. The resulting total desired generation (Pdes) can be divided into two parts:
- Temporary Generation - Total Generation of Economic Units - Base Points - Secure Economic Base Points - Secure Economic Participation Factors - Reserve Requirements
P
des
=
P
sust
+
P
temp
(2)
where Psust is the sustained (i.e. the sum over the current unit base points) and Ptemp is the temporary component. As shown in TABLE I the base point of each unit can be either specified by an operator entered value (base, ramp). by a schedule provided by an unit conunitrnent program (schedule) or it Can be calculated by ED (economic). Under normal conditions Ptemp is distributed to the regulating units proportional to their regulating ranges. Ptcmp
Fig. I Functional overview The components AGC, ED and RM are tasks included in the overall software package of generation coTllrol and scheduling (CCS) which is briefly outlined in Fig. I.
341
vernor is not a MW -value but e. g. a valve position, the relation between the unit output and the unit setpoint command may be non linear and variable. To eliminate the unit control error resulting from this, integral control action is provided for each unit(o Fig. 3). The input of the integral control module (i.e. the unit control error) is calculated as the difference of the measured unit active power output and the result of a dynamic unit simulation.
is kept low by redistributing it to Psust via EO. In emergency cases, i.e. when Ptemp is excessive, AGC uses the full emergency regulating ranges of units in regulating and in assist mode to ensure secure operation. In order to clear the regulating ranges and to keep the time low, during which generation distribution is done in a less economic way, EO is activated immediately when Ptemp exceeds a specified value. For units not remote controlled, but which should participate in the allocation of the sustained generation component (especially if it is calculated by EO, 0 advisory pass of EO) an advisory operating mode is provided. Units in the manual operating mode are not considered by the AGe.
~_I____- .____________________________~cr
TABLE 1 Unit Operating Modes
Pml Pri . Generation requirement lor unH i Pel . Generation oommand for un~ i Pmi . Measured active power output of Tul . Un~ tracking Integration time
Base Point Source
Operalor
Schedule Economic Dispatch
On Romoto Control
Off Romoto Control Station Manual Dispatch
Base Advisory
Base
Base Assist
Regulat ing
Manual
Ramp Advisory
Ramp
Base Assist
Ramp Regulating
Schedule Advisory
Schedulo
Schedule Assist
Schedulo Regulating
Economic Advisory
Economic
Economic
Economic Regulating
X X
Assist
Base
Pd
- Total desired genet' alian
GI
. Large signal gain
Gs Ti T vi Pri
un~
I
Fig. 3 Integral Control J.m.p!ementation options . Typically the control environment of an electrical network is a hierarchical one (0 Fig. 4). A system conlrol cenlre, supervising the whole interconnected network, determines area interchange values for the single network areas . The area COnlrol cenlre takes this value as interchange refererence and calculates setpoint values for each unit, which participates in secondary control. In the view of an area control centre a whole power plant can be treated as a single unit. In the latter case usually a further AGCIEO-system is implemented in the power station conlrol cenlre to distribute the total generation output calculated by the superior AGC to the single generators in an economic way. The AGC described in this paper is specially designed to act in all previous mentioned hierarchies. Furthermore in some applications it is neces sary to adapt unit setpoints, which can come either from the operator or from an external software system, to the interfacing requirements of the units. In this case the unit control function is able to work as stand alone system (without the load frequency control functionallity).
Generation Compensation. To achieve a similar average response time of slow and quick units under AGC-control thus avoiding swinging of the machines against each other the desired generation value of each unit is compensated with the integration time (fi) of the central controller (0 Fig.2). However the compensation is bypassed during emergency situations and also during crossing of prohibited regions to shorten the reaction time .
ACE · Area control er ror Pm . Total measured unit refere nce
___Pel
• Small signal gain • Integration ti me - Average response time at unit; - Generation requirement tor unit i
Fig. 4 Control Hierarchies
Fig. 2 Signal Flow Unit control. A selection between a manual (i.e. the unit desired generation is input by the operator) or an automatic mode (i.e. the unit desired generation is calculated by the central AGC algorithm) is provided. The set point values for manually controlled units can be economic values as supplied by the EO advisory calculation. The output of the unit control function, i.e. the unit control command, can be either a setpoint value or a raise/lower command.
Interface to EO. The results of EO are used by AGC in form of economic base points with target time stamps. AGC then drives the base points of the units in such a way that they equal the economic base points at the target time. In the other direction, EO uses the value of Ptemp calculated by AGC for distributing it to the units in economic mode.
If the controlquantity used for interfacing to the turbine go342
Standby reserve is the contribution from offline units which can be brought online manually (standby) or automatically (auto-standby). The time to bring a thermal unit online is dependent on the time the unit was actually offline. This characteristic is taken into account for calculation of standby reserve of thermal units (warm- standby). Each pumping unit can be defmed as being able to have its pumping action manually (tripping) or automatically (auto-tripping) interrupted in emergencies. However, a pumped hydro can be quick started as a generator or can be tripped while pumping and restarted as generator (tripping & standby). Radial feeders can be defined to be included in a load group. The load of these feeder are then summed to yield the total reserve contribution for the corresponding group. The load of such a feeder group can be shed either manually (tripping) or by an underfrequency relay (UlF loadsh£dding). Interchange contracts can be specified, which are not active during normal operation but can be activated by the operator in emergency situations (emergency agreements). The active reserve requirements for the system are defmed in terms of standard risk (loss of largest unit or loss of largest interchange or support to a partner in emergency) and a variation from this risk. The standard risk and its variations can vary throughout the day and from day to day. The interface to ED is the reserve requirements for units in economic mode, calculated every 5 minutes. If RM detects a system reserve deficiency, ED is activated immediately.
Reserve Monitor The task of RM is to check if the active resp. reactive power supply capability is greater or equal than necessary requirements. Active reserve monitor. For a power system that is capable to survive a disturbance and to return to normal operating state, its power supply capability must be greater than the demand for some specified points in time after disturbance. For each specified point in time the reserve contributions are totalled over all of the reserve sources for comparison with the requirements. These totals are referred to as reserve classes. The reserve classes and typical corresponding times are: o Responsive reserve ...............20 seconds o Fast ready reserve ...................2minutes o Slow ready reserve ............... l0 minutes o Fast operating reserve ..........30 minutes o Slow operating reserve ...........2 hours Power system sources which contribute to reserve can be either units, agreed imports, pumps or other interruptabel loads. Each reserve source can assist with a particular reserve contribution due to a certain reserve mechanism which is specific for the unit type and the time of the reserv~ class (0 TABLE 2). TABLE 2 Reserve Mechanism
~
Operating
Ready
Reserv Class Responsive Source
Fast
Slow
FastlSlow
Stoom Unhs
Stored Energy
Spinning
Spinning
Warm Standby
Gas Turbines
Spinning
Auto Standby
Stand by
Standby
Hydro Generators
Spinning
Spinning
Standby
Standby
Pumps
Auto Tripping
Auto Tripping
Tripping
Tripping
Pump Generators
Auto Tripping
Auto Tripping
Tripping & Standby
Tripping & Standby
Inter· change Interruptabie Load
C><~ C>< UIFLoad Shedding
Reactive reserve monitor. The inductive and capacitive reserve contributions of the reactive reserve elements are summed separately over the whole network area and over defmed parts of the area. The total inductive and capacitive reserve contribution of an area is checked against operator defmed requirements. Reactive reserve elements are: The reactive reserve of generators (dynamic reactive reserve) is calculated as the difference between the actual reactive output and the reactive rating, which is a function of the actual active output (generator capability curve). The reactive reserve of shunt elements (static reactive reserve) is taken as the difference between the actual arnoWlt ofreactive power and the nominal capacity.
Emergency Emergency Agreements Agreements Tripping
Economic Dispatch ED is the allocation or change in allocation of the power resources connected to the system at a particular time to meet the system load at that time in a marmer which minimizes the overall cost to the system. Four different dispatch calculations are performed to meet the realtime dispatch requirements (tertiary control) and in addition the advisory and schedule requirements of the dispatching personnel: The control pass serves to calculate the economic base point values for those units automatically controlled to their economic desired generation by AGe. The advisory pass serves to calculate the economic base point values for manually controlled units, for which a recommendation for economic loading is desired. The target pass serves for the computation of the optimum base load for all online units for most desirable system economics. The reschedule pass evaluates the economic base points for single time steps of the schedule modifying the scheduled base load of those units that participate in this calculation. In study mode ED is enabled to perform the same calculations (except control pass) with saved case data derived from a snapshot of realtime data, from archive or from
Tripping
Each reserve mechanism is associated with a particular reserve calculation model. In the context of ED and OPF the stored energy and spinning reserve mechanism are of special interest: Spinning reserve is the difference between the current loading point and the maximum unit output. The latter is defmed by the regulating high limit (0 Fig. 5). For steam units within the responsive reserve class it is reduced to a value specified by the capability of the high pressure turbine (stored energy reserve mechanism). Particularly for units, which are not highly loaded, the reserve contribution is not limited by the regulating high limit but by the ramping limitation. The maximum reserve contribution is given by the product of the time corresponding to the reserve class and the maximum loading rate. This means that the reserve contribution does not change with the unit loading. Only if the unit loaded more than e a certain level (i.e. the restrictive reserve loading point) the reserve contribution becomes restricted by the regulating high limit (0 Fig. 6). Other reserve mechanism only considered by RM are: 343
T*, e.g. 5 minutes). Regardless of the normal/feed forward mode the EO results handed over to AGC are base points with the target time stamp T*. The effect is that when T* is reached. Ptemp has been smoothly shifted to sustained ge· neration (Psust).
schedule. EO is based on the lamda dispatch, the principle of equal incremental costs. By application of a fast step.by.step al· gorithm, described by Schellstede and Wagner (1980), lamda is determined in a non·iterative process. This allows EO to be activated in very short cycles. The lamda dispatch algorithm operates with incremental cost curves for the determination of the optimal load allo· cation among thermal and hydro units . Hydro units are included in the optimization via the use of water consump· tion curves and water worth values (manually input or calculated by the water worth value calculation). For ther· mal units the incremental cost curve results from the incre· mental heat rate curve and the fuel price. The fuel price may result from different fuel types or different ratios of mixed fuels (multi-[ueled units). Incremental curves are approxi. mated by linear monotonously increasing segments. These are allowed to have flat or not continuous sections. Uneco· nomic loading regions around valve points are considered by not driving units into such regions. Transmission losses are taken into account by means of penalry factors (calcula· ted by the penalty fa ctor calculation), energy constraints by means of shadow cost factors (calculated by the unit com· mitment). Unit operating arrangements (0 Fig . 5) are modelled via generation limits, prohibited regions, regula. ting ranges and loading rates . To retain sufficient regulating capacity EO only takes partial use of the maximum loading rates.
Qptimizing under reserve constraints. Considering the to· tal amount of load to be economically distributed, EO checks the responsive and fast ready reserve requirements received from RM. If the requirements are not met. the re· serve contribution of the units in economic mode are increased by calculating new reserve limits for some of them (an example for two units is shown in Fig. 6). Generation Level
Unit 2 2nd run of EO RegUlating ---r-----...,.;.......-..;'~--- High
New L'oading
~nI
RestriCled
\
reserve lJax,'mum Re_orv" loading point'--!il~~.::::;..._M_ _ _ _~_._ _ _
Ladt of Reserve +_
.' New Reserve Limit New Loading Point
Old Loading Point
Regulating
Low
1st 2nd Unit I
run of EO
Fig. 6 Increase reserve contribition The minimum generation limits of those units which are loaded with a smaller load than the restrictive reserve loa· ding point (RRLP) for them (unit 1 in Fig. 4) are increased, so that the increments meet the reserve requirements. Though these loading offsets do not change the reserve contribution of these units, the corresponding unloading of units with a greater load than the RRLP (unit 2 in Fig. 6) by the same amount causes an increase of the reserve contribution. Activations. EO is activated cyclically (e.g. every two mi· nutes), spontanously or on operator request. Spontaneous activations result e.g from AGC or RM, as discussed abo· ve, or from changes in unit operating conditions or unit parameters (e.g. change of generation limits of economic units). Minimum unit capacity
Fig.5 Unit limits
MAN MACHINE INTERFACE The whole generation control & scheduling system inclu· ding the above described function and their man machine interface are integrated into an energy management system (EMS) based on the concept of a distributed system (Wol· ters, 1991). The visualizing is done via the open look surface.
Sustained generation comPQnent. The temporary compo· nent (Ptemp) of the total generation received from AGC is transferred to the sustained component by allocating it to the "economic" units. For the calculation of the total generation to be economically distributed (Ped), the sum of the current base points (Pbp) of the units in economic mode is determined. Two calculation modes are possible:
o
normal (after the fact) P
o
The selection path starts in the basic menu of the EMS, the so called basic signalling window (OFig . 7).
ed
=
LP bp +
P
'-EAL'T1IIIE _ -.aID •• ,.... Mrw:aM
(3a)
temp
IGenBumI [ill] [!ill OD c=J I[!] ~ [l] I
feed forward (copying with the system load development in the near future; anticipatory dispatch) p
ed
=
LP bp
+ P
te~p
+ P
Ffor w
~~~~~I~~~j IoPUI o~ DCaof' oRTU 0= I DCtrln
(3b)
Pforw represents the forecasted variations of the load, e.g as described by Strasser and colleagues (1990), and the sche· duled variations of interchanges and generators within a certain future time range (current time + observation time =
344
OResrc
Fig.7 Basic Signalling Window After dragging the big GCS·button into the workspace. a window for the GCS · overview (OFig . 8) display is opened. By use of the small GCS·button in the lower regi·
REAL'T1IIIE - (411) a. .. rat.... CCInhaIa. Sc~
[v]
ISINAUT -SPECTRUMII Generation Control and Scheduling - Overview
~
Power System
Ready
Responsive
Current Reserve
0.0
49.998
Generation
BOO
MW
I AGC I
0.0
ACE
72.5 402
MW MW MW MW
99.7
MW
Sustalned Manual Schedule Economic Total
MW
Temporary Gen. Total 1.4
MW
MW
Regulating Range Raise 100 lower 100
MW MW
System load
fast 0.0
slow MW
0.0 MW
0 . 0 MW
Hz
325
Interchange
1
Operating
slow fast 0.0 MW
MW
Frequency
Non-AGC Manual Sched. Economic
11
701
Forecast losses
~
normal
0.4
MW
@O
Base load
Gen. 325 MW 72.5 MW 401 MW 799 MW
lamda Generation
Control 403 MW 10 $IMWH
scheduled 72.5 MW
Advisory 401 MW 10 $IMWH Target 402 MW 10 $IMWH
MW
I~ [~
I
~
~
Cost
Current
0
$Ih
Target
0
$Ih
East West Antip
[
29.5 68.9 0.0
MW MW MW
0.0 0.0
MW MW
99.7
MW
Export Import Total IPFM I load Char.: Sit. 01 ITop 1
~
c::::::::J I WlC I
Fig. 8 GCS Overview
LVJ
REALTlIIE - (661) AGe epe ...
tu-e
ISINAUT-SPECTRUMII Automatic Generation Control- Operating I I
I
AGC
AREA
I Delta P
1
I AreaOVer
Center I
0.9 MW
Energy Correction man 0.0 MW
0.1 MWh 0.0 MW
aut
I 1
I
1
ACE
0.9 MW
1
I
50.000
I Delta F
Frequency Offset man 0.000 sch 0.000 aut 0.076 0.000
130
Hz Hz s' Hz +
Area Control Error
:J
11
I UnitOVer
IArea V
1 Bias
External Obligation
1
I UnitCtr1
B
0.9 MW
~
50.001
Hz
1
MW/Hz I
MW
I
Frequency Interchange Tie-line Bias Frequenc + Time Tie-line Bias + Time Interchange + Energy Tie-line Bias + Energy Tie-line Bias + Energy + Time
boost assist
100 MW 100 MW 146 MW 148 MW 544 MW 470 MW
Raise lower Raise lower Raise lower
limited
Temporary Generation
Control P""'MPtpr
19
MW
EllS MENU
Isubstval 11
U
lock
11
Sustained Generation BOO
1 1
Control Mode
normal
U 1.9
1
Control State
Internal Obligation
-{).1
I
1
I AGC Ust
active
IAGC
50.0 mHzls 0.0
1
Param
SelMode
RealTime
11 unlock
IIFrmSched 1
11
11 GCS
I AGe
1
I
MW
RealTimelO
Fig. 9 AGC-Operatmg DISplay
345
LvJ
R~L1WE -1!aonIm1D
I
I
I
I UnitPara I
AREA
Center {
{
I
UnitOver
I
11
Economic Dispatch - Operating Display
1 SINAUT -SPECTRUt.A 11
ED
D.lDh - ep.nlart DIIpIrf
I
I
EO-Param
I
I
{Area V EO - Results
manual start
EO - pass
Control Advisory Target Reschedule
Reschedule TIme Step
Last run at
Lamda
Activation mode
cycle time
spontan. 6: eycl
01:00
17:16:54
9,7
spontan.6: eycl
01:00
17:16:54
9,7
[$IMWh]
program status
mm:ss
0 0 0 0
no activation
0
Requested TIme Step
05:00
spontan. 6: eyel
17:16:54
9,7
00:00:00
0,0
00:00;00
0,0
hh:mm
00:00 dd:hh:mm
01 00:00
Fig. 10 EO-Operating Display For observing the AGC operation at the signal flow level a on of the basic signalling window an alarm list for GCS can special display is provided. be selected. The GCS-overview display contains an overview about all functions of GCS. The most important results of the functiCONCLUSION on are displayed. By selection the poke point for the desired The general task of Generation Control and Dispatch is to function to be selected, the corresponding operating display provide electrical energy with minimal operation cost whiappears ( OFig. 9, 10). le maintaining the reliability of operation. A close interAll displays are designed to have a button line in the header action of the software functions AGC. EO and RM is for selection all displays assigned to the selected function. prerequisite for meeting this task at a sufficiently high All information needed for normal operating is displayed in level. the operating and the unit overview displays. (An example In cases where network transport restrictions have to be for such an unit overview display is shown in Fig. 11). The regarded, a further improvement of reliability can be done most important parameters of the selected function (e.g. by incorporating an Optimal Power Flow as described by AGC-control mode) can be entered into these displays. Eichler and colleagues (1991). More detailled unit related information (unit parameters and The concept above described is implemented in an Energy Management System and will be included in a project scheduled for comrnisioning late 1992.
unit control display) can be displayed by dragging the corresponding button (C for unit control and P for unit parameters in Fig. 11) into the workspace. Because the parameter display contains "dangerous" information, it is possible to protect it against selection by unauthorized persons.
.
REALl1ME -(OM) MJt;,
~
.
ISINAUT -SPECTRu~11
Sun
Unit Operating
1
u_ _ _
AGe - Unit Overview
StaJU, ~ode
REFERENCES Eichler R., H. Hafner, and G. Schwarz (1991). Integration of the optimal power flow into generation control and dispatch. Proc. lEE Conference. London, England . Schellstede, G., and H. Wagner (1980). Design aspects of a software package for automatic generation control with instantaneous economic dispatch and load forecasting functions. Proc. IFAC Symposium. Pretoria, South Africa. Strasser, H., N. Friemelt, and G. Schellstede (1990). Short term load forecast using multiple regression analysis or adaptive regression analysis. Proc. PSCC Conference. Graz, Austria. Wolters, E.I. (1991). Distributed design for energy management systems. Proc. lEE Conference. London, England.
Temp.
Ref. Current
I I
Pari. /Plant A
III~Unit 1
act
III~UnitZ
Kt
I~.nna
aut
tCOMMIc
au lst
aut
econOMic assist
200 ~.O
200 ~.O
201
201 an
201
201 an
250
250 an
/Plant A
III~Unit 1
act
aut
250 0.0
aut
oase regulabng
25.0 0.7 25 .0 0.7 25.0 0.7
act
base
I
VIenna /Plant B act
III~Unit 1
base
III~UnitZ
oct aut oase regulaHng .et aut
III~Unit3
I~.ter
ffOP
III~
liKelier ffOK III~
~9ulabn9
25.3 25.1 on 25 . 3
25.1 an
25.3 25.1 an
aut
23.5
tctledt,lle ,tguldng
0.1
23.6 23.5 an
act lI.II lchsdule regulattng
24.5 0 .3
24.7 24.5 an
IVIII.Ch ffOV
I I I
Fig. 11 AGe-Unit Overview 346
Copyright © IFAC Control of Power Plants and Power Systems. Munich. Germany. 1992
EXTENDED GENERATION CONTROL AND DISPATCH G. Schwarz and H. Hafner Departnu!nJ of Program and System Developnu!nt. Siemens AG .. Vienna. Austria
Abstract: An advanced software system for Generation Control and Dispatch is presented. It is placed on well tuned coordination of the components Automalic Generation COTllrol. Economic Dispatch and Reserve Monitoring. The features of these components and their interaction are described. In cases where network transport restrictions have to be regarded, an Optimal Power Flow can be incorporated. K£lwords: Automatic generation control; stabilized control. compensated regulation. economic dispatch; anticipatory dispatch; reserve monitor; reserve determination.
INTRODUcnON
COMPONENTS Automatic Generation Control The overall objective of AGC is the power output alteration of certain electric generators within a defmed network area to meet the area's obligations expressed by minimizing the following well known equation (secondary control):
Automatic generation coTllrol (ACC) combined with economic dispatch (ED) for calculating cost optimal generator base points are well known functions that have been introduced to many control centre systems. Nevertheless improvements can be achieved e.g. by measures that avoid unnecessary regulation activities in normal situations thus contributing to overall economy while guaranteeing quick response in exceptional situations. Further improvements are useful by integration of a reserve monitor (RM), which optimally assigns reserves considerating economic aspects as well as activation speed. An optimal power flow (OPP) can be incorporated in cases where network trartSport restrictions have to be regarded.
AGC - Automatic Generation P_temp Control P_EO EO - Economic Dispatch BP OPF - Optimal Power Flow RM - Reserve Monitor SEBP STLF- Short Term Load Forecast SEBF IS - Interchange Scheduling UC - Unit Commitment P_req PFC - Penalty Factor Calculation
ACE = 6P
+
B
x
6F
~
0
(1 )
where ACE = area control error. 6P = net interchange error. 6F = frequency error and B = system frequency bias. Time and energy can also be controlled by making small adjustments to the frequency and interchange reference values respectively. To eliminate an ACE which may arise caused by steadily increasing or decreasing load an additional value calculated by an anticipation logic (anticipatory cOTllrol) can be added to ACE. Generation calculation. The ACE is processed by a controller which can handle large and small signals differently. The parameters for splitting the signal into a trend component and a swing component are calculated dynamically by using statistical attributes (moving average and standard deviation) of the ACE. To stabilize control the difference of the expected unit generation (i.e. the total desired generation delayed by a first order filter) and the measured response of the units is fed back to the input of the controller (0 Fig.2). This provides the controller with the ability to manage non-linear and variable unit behaviour. Generation distribution. The resulting total desired generation (Pdes) can be divided into two parts:
- Temporary Generation - Total Generation of Economic Units - Base Points - Secure Economic Base Points - Secure Economic Participation Factors - Reserve Requirements
P
des
=
P
sust
+
P
temp
(2)
where Psust is the sustained (i.e. the sum over the current unit base points) and Ptemp is the temporary component. As shown in TABLE I the base point of each unit can be either specified by an operator entered value (base, ramp). by a schedule provided by an unit conunitrnent program (schedule) or it Can be calculated by ED (economic). Under normal conditions Ptemp is distributed to the regulating units proportional to their regulating ranges. Ptcmp
Fig. I Functional overview The components AGC, ED and RM are tasks included in the overall software package of generation coTllrol and scheduling (CCS) which is briefly outlined in Fig. I.
341
vernor is not a MW -value but e. g. a valve position, the relation between the unit output and the unit setpoint command may be non linear and variable. To eliminate the unit control error resulting from this, integral control action is provided for each unit(o Fig. 3). The input of the integral control module (i.e. the unit control error) is calculated as the difference of the measured unit active power output and the result of a dynamic unit simulation.
is kept low by redistributing it to Psust via EO. In emergency cases, i.e. when Ptemp is excessive, AGC uses the full emergency regulating ranges of units in regulating and in assist mode to ensure secure operation. In order to clear the regulating ranges and to keep the time low, during which generation distribution is done in a less economic way, EO is activated immediately when Ptemp exceeds a specified value. For units not remote controlled, but which should participate in the allocation of the sustained generation component (especially if it is calculated by EO, 0 advisory pass of EO) an advisory operating mode is provided. Units in the manual operating mode are not considered by the AGe.
~_I____- .____________________________~cr
TABLE 1 Unit Operating Modes
Pml Pri . Generation requirement lor unH i Pel . Generation oommand for un~ i Pmi . Measured active power output of Tul . Un~ tracking Integration time
Base Point Source
Operalor
Schedule Economic Dispatch
On Romoto Control
Off Romoto Control Station Manual Dispatch
Base Advisory
Base
Base Assist
Regulat ing
Manual
Ramp Advisory
Ramp
Base Assist
Ramp Regulating
Schedule Advisory
Schedulo
Schedule Assist
Schedulo Regulating
Economic Advisory
Economic
Economic
Economic Regulating
X X
Assist
Base
Pd
- Total desired genet' alian
GI
. Large signal gain
Gs Ti T vi Pri
un~
I
Fig. 3 Integral Control J.m.p!ementation options . Typically the control environment of an electrical network is a hierarchical one (0 Fig. 4). A system conlrol cenlre, supervising the whole interconnected network, determines area interchange values for the single network areas . The area COnlrol cenlre takes this value as interchange refererence and calculates setpoint values for each unit, which participates in secondary control. In the view of an area control centre a whole power plant can be treated as a single unit. In the latter case usually a further AGCIEO-system is implemented in the power station conlrol cenlre to distribute the total generation output calculated by the superior AGC to the single generators in an economic way. The AGC described in this paper is specially designed to act in all previous mentioned hierarchies. Furthermore in some applications it is neces sary to adapt unit setpoints, which can come either from the operator or from an external software system, to the interfacing requirements of the units. In this case the unit control function is able to work as stand alone system (without the load frequency control functionallity).
Generation Compensation. To achieve a similar average response time of slow and quick units under AGC-control thus avoiding swinging of the machines against each other the desired generation value of each unit is compensated with the integration time (fi) of the central controller (0 Fig.2). However the compensation is bypassed during emergency situations and also during crossing of prohibited regions to shorten the reaction time .
ACE · Area control er ror Pm . Total measured unit refere nce
___Pel
• Small signal gain • Integration ti me - Average response time at unit; - Generation requirement tor unit i
Fig. 4 Control Hierarchies
Fig. 2 Signal Flow Unit control. A selection between a manual (i.e. the unit desired generation is input by the operator) or an automatic mode (i.e. the unit desired generation is calculated by the central AGC algorithm) is provided. The set point values for manually controlled units can be economic values as supplied by the EO advisory calculation. The output of the unit control function, i.e. the unit control command, can be either a setpoint value or a raise/lower command.
Interface to EO. The results of EO are used by AGC in form of economic base points with target time stamps. AGC then drives the base points of the units in such a way that they equal the economic base points at the target time. In the other direction, EO uses the value of Ptemp calculated by AGC for distributing it to the units in economic mode.
If the controlquantity used for interfacing to the turbine go342
Standby reserve is the contribution from offline units which can be brought online manually (standby) or automatically (auto-standby). The time to bring a thermal unit online is dependent on the time the unit was actually offline. This characteristic is taken into account for calculation of standby reserve of thermal units (warm- standby). Each pumping unit can be defmed as being able to have its pumping action manually (tripping) or automatically (auto-tripping) interrupted in emergencies. However, a pumped hydro can be quick started as a generator or can be tripped while pumping and restarted as generator (tripping & standby). Radial feeders can be defined to be included in a load group. The load of these feeder are then summed to yield the total reserve contribution for the corresponding group. The load of such a feeder group can be shed either manually (tripping) or by an underfrequency relay (UlF loadsh£dding). Interchange contracts can be specified, which are not active during normal operation but can be activated by the operator in emergency situations (emergency agreements). The active reserve requirements for the system are defmed in terms of standard risk (loss of largest unit or loss of largest interchange or support to a partner in emergency) and a variation from this risk. The standard risk and its variations can vary throughout the day and from day to day. The interface to ED is the reserve requirements for units in economic mode, calculated every 5 minutes. If RM detects a system reserve deficiency, ED is activated immediately.
Reserve Monitor The task of RM is to check if the active resp. reactive power supply capability is greater or equal than necessary requirements. Active reserve monitor. For a power system that is capable to survive a disturbance and to return to normal operating state, its power supply capability must be greater than the demand for some specified points in time after disturbance. For each specified point in time the reserve contributions are totalled over all of the reserve sources for comparison with the requirements. These totals are referred to as reserve classes. The reserve classes and typical corresponding times are: o Responsive reserve ...............20 seconds o Fast ready reserve ...................2minutes o Slow ready reserve ............... l0 minutes o Fast operating reserve ..........30 minutes o Slow operating reserve ...........2 hours Power system sources which contribute to reserve can be either units, agreed imports, pumps or other interruptabel loads. Each reserve source can assist with a particular reserve contribution due to a certain reserve mechanism which is specific for the unit type and the time of the reserv~ class (0 TABLE 2). TABLE 2 Reserve Mechanism
~
Operating
Ready
Reserv Class Responsive Source
Fast
Slow
FastlSlow
Stoom Unhs
Stored Energy
Spinning
Spinning
Warm Standby
Gas Turbines
Spinning
Auto Standby
Stand by
Standby
Hydro Generators
Spinning
Spinning
Standby
Standby
Pumps
Auto Tripping
Auto Tripping
Tripping
Tripping
Pump Generators
Auto Tripping
Auto Tripping
Tripping & Standby
Tripping & Standby
Inter· change Interruptabie Load
C><~ C>< UIFLoad Shedding
Reactive reserve monitor. The inductive and capacitive reserve contributions of the reactive reserve elements are summed separately over the whole network area and over defmed parts of the area. The total inductive and capacitive reserve contribution of an area is checked against operator defmed requirements. Reactive reserve elements are: The reactive reserve of generators (dynamic reactive reserve) is calculated as the difference between the actual reactive output and the reactive rating, which is a function of the actual active output (generator capability curve). The reactive reserve of shunt elements (static reactive reserve) is taken as the difference between the actual arnoWlt ofreactive power and the nominal capacity.
Emergency Emergency Agreements Agreements Tripping
Economic Dispatch ED is the allocation or change in allocation of the power resources connected to the system at a particular time to meet the system load at that time in a marmer which minimizes the overall cost to the system. Four different dispatch calculations are performed to meet the realtime dispatch requirements (tertiary control) and in addition the advisory and schedule requirements of the dispatching personnel: The control pass serves to calculate the economic base point values for those units automatically controlled to their economic desired generation by AGe. The advisory pass serves to calculate the economic base point values for manually controlled units, for which a recommendation for economic loading is desired. The target pass serves for the computation of the optimum base load for all online units for most desirable system economics. The reschedule pass evaluates the economic base points for single time steps of the schedule modifying the scheduled base load of those units that participate in this calculation. In study mode ED is enabled to perform the same calculations (except control pass) with saved case data derived from a snapshot of realtime data, from archive or from
Tripping
Each reserve mechanism is associated with a particular reserve calculation model. In the context of ED and OPF the stored energy and spinning reserve mechanism are of special interest: Spinning reserve is the difference between the current loading point and the maximum unit output. The latter is defmed by the regulating high limit (0 Fig. 5). For steam units within the responsive reserve class it is reduced to a value specified by the capability of the high pressure turbine (stored energy reserve mechanism). Particularly for units, which are not highly loaded, the reserve contribution is not limited by the regulating high limit but by the ramping limitation. The maximum reserve contribution is given by the product of the time corresponding to the reserve class and the maximum loading rate. This means that the reserve contribution does not change with the unit loading. Only if the unit loaded more than e a certain level (i.e. the restrictive reserve loading point) the reserve contribution becomes restricted by the regulating high limit (0 Fig. 6). Other reserve mechanism only considered by RM are: 343
T*, e.g. 5 minutes). Regardless of the normal/feed forward mode the EO results handed over to AGC are base points with the target time stamp T*. The effect is that when T* is reached. Ptemp has been smoothly shifted to sustained ge· neration (Psust).
schedule. EO is based on the lamda dispatch, the principle of equal incremental costs. By application of a fast step.by.step al· gorithm, described by Schellstede and Wagner (1980), lamda is determined in a non·iterative process. This allows EO to be activated in very short cycles. The lamda dispatch algorithm operates with incremental cost curves for the determination of the optimal load allo· cation among thermal and hydro units . Hydro units are included in the optimization via the use of water consump· tion curves and water worth values (manually input or calculated by the water worth value calculation). For ther· mal units the incremental cost curve results from the incre· mental heat rate curve and the fuel price. The fuel price may result from different fuel types or different ratios of mixed fuels (multi-[ueled units). Incremental curves are approxi. mated by linear monotonously increasing segments. These are allowed to have flat or not continuous sections. Uneco· nomic loading regions around valve points are considered by not driving units into such regions. Transmission losses are taken into account by means of penalry factors (calcula· ted by the penalty fa ctor calculation), energy constraints by means of shadow cost factors (calculated by the unit com· mitment). Unit operating arrangements (0 Fig . 5) are modelled via generation limits, prohibited regions, regula. ting ranges and loading rates . To retain sufficient regulating capacity EO only takes partial use of the maximum loading rates.
Qptimizing under reserve constraints. Considering the to· tal amount of load to be economically distributed, EO checks the responsive and fast ready reserve requirements received from RM. If the requirements are not met. the re· serve contribution of the units in economic mode are increased by calculating new reserve limits for some of them (an example for two units is shown in Fig. 6). Generation Level
Unit 2 2nd run of EO RegUlating ---r-----...,.;.......-..;'~--- High
New L'oading
~nI
RestriCled
\
reserve lJax,'mum Re_orv" loading point'--!il~~.::::;..._M_ _ _ _~_._ _ _
Ladt of Reserve +_
.' New Reserve Limit New Loading Point
Old Loading Point
Regulating
Low
1st 2nd Unit I
run of EO
Fig. 6 Increase reserve contribition The minimum generation limits of those units which are loaded with a smaller load than the restrictive reserve loa· ding point (RRLP) for them (unit 1 in Fig. 4) are increased, so that the increments meet the reserve requirements. Though these loading offsets do not change the reserve contribution of these units, the corresponding unloading of units with a greater load than the RRLP (unit 2 in Fig. 6) by the same amount causes an increase of the reserve contribution. Activations. EO is activated cyclically (e.g. every two mi· nutes), spontanously or on operator request. Spontaneous activations result e.g from AGC or RM, as discussed abo· ve, or from changes in unit operating conditions or unit parameters (e.g. change of generation limits of economic units). Minimum unit capacity
Fig.5 Unit limits
MAN MACHINE INTERFACE The whole generation control & scheduling system inclu· ding the above described function and their man machine interface are integrated into an energy management system (EMS) based on the concept of a distributed system (Wol· ters, 1991). The visualizing is done via the open look surface.
Sustained generation comPQnent. The temporary compo· nent (Ptemp) of the total generation received from AGC is transferred to the sustained component by allocating it to the "economic" units. For the calculation of the total generation to be economically distributed (Ped), the sum of the current base points (Pbp) of the units in economic mode is determined. Two calculation modes are possible:
o
normal (after the fact) P
o
The selection path starts in the basic menu of the EMS, the so called basic signalling window (OFig . 7).
ed
=
LP bp +
P
'-EAL'T1IIIE _ -.aID •• ,.... Mrw:aM
(3a)
temp
IGenBumI [ill] [!ill OD c=J I[!] ~ [l] I
feed forward (copying with the system load development in the near future; anticipatory dispatch) p
ed
=
LP bp
+ P
te~p
+ P
Ffor w
~~~~~I~~~j IoPUI o~ DCaof' oRTU 0= I DCtrln
(3b)
Pforw represents the forecasted variations of the load, e.g as described by Strasser and colleagues (1990), and the sche· duled variations of interchanges and generators within a certain future time range (current time + observation time =
344
OResrc
Fig.7 Basic Signalling Window After dragging the big GCS·button into the workspace. a window for the GCS · overview (OFig . 8) display is opened. By use of the small GCS·button in the lower regi·
REAL'T1IIIE - (411) a. .. rat.... CCInhaIa. Sc~
[v]
ISINAUT -SPECTRUMII Generation Control and Scheduling - Overview
~
Power System
Ready
Responsive
Current Reserve
0.0
49.998
Generation
BOO
MW
I AGC I
0.0
ACE
72.5 402
MW MW MW MW
99.7
MW
Sustalned Manual Schedule Economic Total
MW
Temporary Gen. Total 1.4
MW
MW
Regulating Range Raise 100 lower 100
MW MW
System load
fast 0.0
slow MW
0.0 MW
0 . 0 MW
Hz
325
Interchange
1
Operating
slow fast 0.0 MW
MW
Frequency
Non-AGC Manual Sched. Economic
11
701
Forecast losses
~
normal
0.4
MW
@O
Base load
Gen. 325 MW 72.5 MW 401 MW 799 MW
lamda Generation
Control 403 MW 10 $IMWH
scheduled 72.5 MW
Advisory 401 MW 10 $IMWH Target 402 MW 10 $IMWH
MW
I~ [~
I
~
~
Cost
Current
0
$Ih
Target
0
$Ih
East West Antip
[
29.5 68.9 0.0
MW MW MW
0.0 0.0
MW MW
99.7
MW
Export Import Total IPFM I load Char.: Sit. 01 ITop 1
~
c::::::::J I WlC I
Fig. 8 GCS Overview
LVJ
REALTlIIE - (661) AGe epe ...
tu-e
ISINAUT-SPECTRUMII Automatic Generation Control- Operating I I
I
AGC
AREA
I Delta P
1
I AreaOVer
Center I
0.9 MW
Energy Correction man 0.0 MW
0.1 MWh 0.0 MW
aut
I 1
I
1
ACE
0.9 MW
1
I
50.000
I Delta F
Frequency Offset man 0.000 sch 0.000 aut 0.076 0.000
130
Hz Hz s' Hz +
Area Control Error
:J
11
I UnitOVer
IArea V
1 Bias
External Obligation
1
I UnitCtr1
B
0.9 MW
~
50.001
Hz
1
MW/Hz I
MW
I
Frequency Interchange Tie-line Bias Frequenc + Time Tie-line Bias + Time Interchange + Energy Tie-line Bias + Energy Tie-line Bias + Energy + Time
boost assist
100 MW 100 MW 146 MW 148 MW 544 MW 470 MW
Raise lower Raise lower Raise lower
limited
Temporary Generation
Control P""'MPtpr
19
MW
EllS MENU
Isubstval 11
U
lock
11
Sustained Generation BOO
1 1
Control Mode
normal
U 1.9
1
Control State
Internal Obligation
-{).1
I
1
I AGC Ust
active
IAGC
50.0 mHzls 0.0
1
Param
SelMode
RealTime
11 unlock
IIFrmSched 1
11
11 GCS
I AGe
1
I
MW
RealTimelO
Fig. 9 AGC-Operatmg DISplay
345
LvJ
R~L1WE -1!aonIm1D
I
I
I
I UnitPara I
AREA
Center {
{
I
UnitOver
I
11
Economic Dispatch - Operating Display
1 SINAUT -SPECTRUt.A 11
ED
D.lDh - ep.nlart DIIpIrf
I
I
EO-Param
I
I
{Area V EO - Results
manual start
EO - pass
Control Advisory Target Reschedule
Reschedule TIme Step
Last run at
Lamda
Activation mode
cycle time
spontan. 6: eycl
01:00
17:16:54
9,7
spontan.6: eycl
01:00
17:16:54
9,7
[$IMWh]
program status
mm:ss
0 0 0 0
no activation
0
Requested TIme Step
05:00
spontan. 6: eyel
17:16:54
9,7
00:00:00
0,0
00:00;00
0,0
hh:mm
00:00 dd:hh:mm
01 00:00
Fig. 10 EO-Operating Display For observing the AGC operation at the signal flow level a on of the basic signalling window an alarm list for GCS can special display is provided. be selected. The GCS-overview display contains an overview about all functions of GCS. The most important results of the functiCONCLUSION on are displayed. By selection the poke point for the desired The general task of Generation Control and Dispatch is to function to be selected, the corresponding operating display provide electrical energy with minimal operation cost whiappears ( OFig. 9, 10). le maintaining the reliability of operation. A close interAll displays are designed to have a button line in the header action of the software functions AGC. EO and RM is for selection all displays assigned to the selected function. prerequisite for meeting this task at a sufficiently high All information needed for normal operating is displayed in level. the operating and the unit overview displays. (An example In cases where network transport restrictions have to be for such an unit overview display is shown in Fig. 11). The regarded, a further improvement of reliability can be done most important parameters of the selected function (e.g. by incorporating an Optimal Power Flow as described by AGC-control mode) can be entered into these displays. Eichler and colleagues (1991). More detailled unit related information (unit parameters and The concept above described is implemented in an Energy Management System and will be included in a project scheduled for comrnisioning late 1992.
unit control display) can be displayed by dragging the corresponding button (C for unit control and P for unit parameters in Fig. 11) into the workspace. Because the parameter display contains "dangerous" information, it is possible to protect it against selection by unauthorized persons.
.
REALl1ME -(OM) MJt;,
~
.
ISINAUT -SPECTRu~11
Sun
Unit Operating
1
u_ _ _
AGe - Unit Overview
StaJU, ~ode
REFERENCES Eichler R., H. Hafner, and G. Schwarz (1991). Integration of the optimal power flow into generation control and dispatch. Proc. lEE Conference. London, England . Schellstede, G., and H. Wagner (1980). Design aspects of a software package for automatic generation control with instantaneous economic dispatch and load forecasting functions. Proc. IFAC Symposium. Pretoria, South Africa. Strasser, H., N. Friemelt, and G. Schellstede (1990). Short term load forecast using multiple regression analysis or adaptive regression analysis. Proc. PSCC Conference. Graz, Austria. Wolters, E.I. (1991). Distributed design for energy management systems. Proc. lEE Conference. London, England.
Temp.
Ref. Current
I I
Pari. /Plant A
III~Unit 1
act
III~UnitZ
Kt
I~.nna
aut
tCOMMIc
au lst
aut
econOMic assist
200 ~.O
200 ~.O
201
201 an
201
201 an
250
250 an
/Plant A
III~Unit 1
act
aut
250 0.0
aut
oase regulabng
25.0 0.7 25 .0 0.7 25.0 0.7
act
base
I
VIenna /Plant B act
III~Unit 1
base
III~UnitZ
oct aut oase regulaHng .et aut
III~Unit3
I~.ter
ffOP
III~
liKelier ffOK III~
~9ulabn9
25.3 25.1 on 25 . 3
25.1 an
25.3 25.1 an
aut
23.5
tctledt,lle ,tguldng
0.1
23.6 23.5 an
act lI.II lchsdule regulattng
24.5 0 .3
24.7 24.5 an
IVIII.Ch ffOV
I I I
Fig. 11 AGe-Unit Overview 346