Overview of the Automatic Generation Control

Saad N. Al-DuwaishSOD/SCADA

P.Box # 5190 SCECO HQ.Dammam,Saudi Arabia 31422

Abstract

Automatic Generation Control (AGC) is the controlling link between the dispatch office and the generating plantsthat it supervises. The dispatcher, with the aid of the optimization and security analysis functions decides on thecorrect level of internal generation for his system and contracts to purchase or sell power in order to meet hiscompany’s load in the most economic manner. The AGC is assigned the responsibility of adjusting generatoroutputs to maintain system frequency at the nominal value, and maintain the scheduled interchange in the mosteconomical way. The AGC system consists of equipment and computer programs implementing closed loopfeedback control of frequency and net interchange, Generator outputs, tie-line flows, and frequency are measured,compared with set points, and adjusted to correct error in the controlled quantities. As with any feedback system,dynamic behavior is of prime importance. Correspondingly, the prime technical objective in the design of the AGCsystem is the correct accommodation of the dynamic characteristics of the power system to achieve prompt, smooth,and stable maneuvering of generation in response to system disturbance and changes of operating setpoints.This paper gives an overview of the AGC data, AGC control modes, AGC operation modes, unit control modes andthe most important AGC features.

1. Introduction

Automatic Generation Control (AGC) regulatesthe power output of electric generators within aprescribed control area in response to change insystem frequency, tie line loading, or the relation ofthese to each other [1]. The AGC program providesclosed-loop control that assigns the automaticallycontrolled generation in such a way that the controlarea load is satisfied while the desired frequency andinterchange schedules are maintained. The programrecognizes both economic and regulation limits andprotects against rate- of- change Violations as well asgovernor wind-up. Each unit can be placed in one ofseveral control modes.

Three disallowed regions can be specified for eachunit such that the unit will not be allowed to dwellwithin these regions. Area control can be selected toutilize flat tie, flat frequency or tie-line bias control,with or without automatic inadvertent payback ortime error correction. Figure 1 is a block diagramrepresentation of the AGC system showing majorsoftware subsystems and data flow to, from, andwithin the system [2].

AreaTime and Frequency Deviation

Freq.

Load Frequency Control Data

Pulses Setpt.

Net interchange Base points and participation factors

Tie Line and Generator Output Data

Interchange Schedules

Economic Dispatch Control Data

AGC Operator

Area Control Error

Power

Allocation

Generator Control

Power System

Time and Frequency. Deviation Hardware

Economic Dispatch Control

Subsystem

Interchange Scheduling Subsystem

Figure 1: Block diagram of automatic generationcontrol interaction

2. AGC DATA

2.1 Input Data1) Scheduled interchange2) Tie line telemetry (MW)

3) Actual unit generation (MW)4) Frequency (Actual & Desired)5) Economic Dispatch program (ED) data

2.2 Output Data2.2.1 Control Output1) Raise/Lower pulses:when a generator is controlled by raise/lower pulses,the calculated unit control error (in MW) is thenconverted to raise/lower control MW pulses,representing an Incremental generation controlcommand. The sign convention for the unit controlerror is such that negative error means a raise ingeneration output is required, while the conventionfor the control pulses is reversed. For Raise/Lowercontrol type units, the control pulses ranging from -7to +7,are subsequently encoded into a 4-bit digitalword transmission to the RTUs at the power plants.Three bit used for magnitude and one bit used forsign “+” for raise generation,”-” for lowergeneration.

2) set point control :If a generating unit is equipped with a set pointcontrol mechanism, the updated unit set point iscalculated as the (LAST SET POINT - THE UNITCONTROL ERROR). After some test’s, the updatedset point is then converted into 12-bit digital wordfor transmission to the Ruts at the power plant witheleven bits used for magnitude and one used for signor special indicator.

3) Trip/Close units :For the trip/close type units, the control pulse 0 or 1are sent to the RTUs, 0 corresponds to an open (trip)command (lower generation) and 1 corresponds to aclose command (raise generation).

2.2.2 AGC performance monitoring dataAGC monitors the response of each unit to thecontrol signal when the unit controls error exeds it’sdedband. The process starts by saving (at firstmonitoring cycle only) the current actual generationand the sign of unit control error. A counter is thenincremented at every subsequent cycle. If the counterreaches a maximum count before the unit generationhas changed for at least a fixed percentage of theactual MW output, or the control error has changedsign, the unit is said to be not responding. Messageis output to inform the dispatcher, and the unitcontrol mode is switched to MAN.

3. AGC Control Modes

The following AGC control modes are provided toallow AGC to be operated under various systemoperational conditions [2].

1) Tie Line Bias Control (TLBC)2) Constant Frequency Control (CFC)3) Constant Net Interchange Control (CNI)4)Tie Line Bias Control Plus Time error correctionThe control mode is selected by the dispatcher viabuttons located on the operator panel of each console.

4. Calculation of Area Control Error(ACE) AGC control the units so that area control error(ACE) is kept close to zero.Calculate Area controlerror (ACEC) calculates the ACE based on AGCcontrol mode ( TLBC/CNIC/CFC/TLBC+TIMEERROR CORRECTION) as shown in Table 1 [1].

Control Mode Area Control Error (ACE) =TLB NIERR + 10.0 * FBIAS *

FREQECFC KFC * 10.0 * FBIAS * FREQECNI KCNI * NIDEV

TLB&TimeError

Correction

NIERR + 10.0 * FBIAS *FREQE + TEBIAS * 10

*TIMERR Table 1: computation of ACE where:

FBIAS is the system frequency bias in MW/.1 HZ.

TBIAS is the time error bias in MW/0.1 sec. TIMERR is the system time error KFC is the weighting factor for ACE in the

CFC mode KCNI is the weighting factor for ACE in the

CNI mode NIERR is the net interchange control errorand it is determined as: NIERR = KLAG * (NIDEV - NIERR1) +

NIERR1. For calculation of lagged interchange error see

figure 2.

- NIERR1 NIERR1

NIDEV NIERR

KLAG (interchange lag factor)

+

1 cycle delay

* +

+

Figure 2 Calculation of Lagged InterchangeError

TECOMP is the Time error correction component

of ACE . It is determined as: TECOMP = TEBIAS ∗ TIMERR ∗ 10 Where: TEBIAS Is a tuning coefficient in MW/.1 sec TIMERR Is the actual time error NOTE: TECOMP is applicable only in the tie

line bias control (TLBC) mode.

5. AGC Operational ModesDepending on ACE value, the operational modes ofthe AGC are classified in to:

Normal : ACE < X MWEmergency Assist : ACE ≥ X MW

The figure, X MW (ACEAST) ACE assist, isselected so that big load does not cause the system togo to Emergency Assist Mode every time it changes.

In the normal state of operation of AGC, generatingunits are available for control within the range(NHDL, NLDL) where NHDL is the normal highdispatch limit and NLDL is the normal low dispatchlimit of the unit. Normally, these two limits arecomputed by the economic dispatch program.However, they can be overridden by the dispatchers.The unit operates based on the principle of economicdispatch within this range.

In the emergency assist state of operation of AGC,the unit is available for control within the range(HDL,LDL) where HDL is the high dispatch limitand LDL is the low dispatch limit of the unit. Therange (NHDL,NLDL) is a proper subset of the range(HDL,LDL).

6. Unit Control Modes:

Unit control mod is usually specified by thedispatcher . Five basic modes are provided asfollows:

6.1 Off-Line (Off)UAV: Unit is totally shut down.AVL: Unit is off the bus & not synchronizes.

6.2 ManualThe output of the unit is controlled by the plantoperator (not controlled by the AGC).

6.3 Regulation (REG)The desired output of the unit is controlled by AGCon basis of ACE.These are the units that mostly used to correct ACEin the normal operation mode.By using or overriding the base points and/orparticipation factors produced by ED the followingsub-modes are available

6.3.1 Normal Regulation (ECON) ED calculates the base point and participationfactor. Thus, the unit provides regulating controlaction while remaining generally optimally loaded.

6.3.2 Optimally Loaded

The base point is calculated by ED but theparticipation factor is set to zero by the dispatcher.AGC keeps the unit optimally loaded following loadtrends, but does not contribute to regulation.

6.3.3 Base Loaded

The base point and the participation factors areentered by the dispatcher .The unit participates inregulating the dispatcher entered base point .If thedispatcher enters only a base point and noparticipation factor, ED assigns a zero participationfactor .In this case, the unit is permissively controlledby AGC to the base point without participating inregulation .If only the participation factor isoverridden with a positive non-zero value, the unitoperates in a mode similar to NORMALREGULATION, but with a different amount ofcontrol activity and a less accurate conformance tooptimal loading between ED values.

6.4 Ramp Load (RMP):The unit is ramped toward base point at a dispatcherentered ramp rate. Control is mandatory while theunit is being ramped. When the base point isreached, the unit control mode is delayed and thecontrol action of the unit is inhibited, if it opposesACE when the EACC determined control urgency(Master controller gain) is high, or the system is inan Emergency Assist State.

In addition, if a unit is found outside it’s economiclimits and AGC is not in Emergency Assist State, theunit is placed on ramp mode to bring it back insidethe economic band .In such cases, the original unitcontrol mode and base point are restored at the endof the ramp.

6.5 Base Load Regulation (BLR)The unit provides additional system regulation whenthe system becomes rate limited as a result of theother units in regulating mode having insufficientresponse capability .The base point and participationfactor are normally entered by the dispatcher .If not,ED determines an optimum base point and sets theunit participation factor to zero. When control actionis in the direction that would require units assignedto BLR to move away from their base point, theyarerequired to do so only after the units inREGULATION mode have been allocated thenecessary control action. However, control action isallocated first to the BLR units when the controlaction is in the direction to bring units back to theirpoint.

To summarize, the above control modes can bedistinguished based on the way the desiredgenerations (base points) and participation factorsare handled as shown in Table 2 [2].

CONTROLMODE

BASEPOINT

PARTICIPATION FACTOR

off line (OFF) X Xmanual (MAN) ME+ 0.0 by ED

Normal reg.submode ECON

(REG)ED ED / 0.0*

submode =Base(REG)

ME+ or/F*NHDL ME+

ramp load(RMP)

ME+ 0.0 by ED

base load reg.(BLR)

submode = ED ME+ or 0.0

ECON(BLR) by EDsubmode =

BASE (BLR)ME+ or/F*NHDLor ED (for steam

units)

ME+ or 0.0by ED

ME+ = Manual Entry 0.0* = set to zero manuallyTable 2: Distinction of Control Modes

7. AGC Features

7.1 Generator Rate Limiting

Generator rate limiting is said to have occurred whenthe stored thermal energy has been substantiallyreduced. And to prevent this from happening, aresponse rate limiting logic is used in AGC .For eachunit, a reference generator is undated in each AGCcycle for detecting the rate limiting condition. Thereference generation is updated based on the unitsustained pick-up rate (GNDEL). TheoreticallyGNDEL represents the capacity of a unit (hydro orthermal) to support the specified load change withoutsubstantially affecting process variables (e.g., boilertemperature, throttle pressure, etc., for thermalunits). That is, the amount of energy withdrawn fromthe boiler is balanced by the energy input to theboiler.

The AGC will detect the rate limiting by checking:

GA - GR > GNREG ⇒ unit is said to be ratelimited. Where GA is the Actual generation., GR isthe reference generation, and GNREG is the storedthermal Energy.

7.2 Control Deadband

Control deadbands are provided to preventunnecessary output of control to units during quiteACE periods .The deadbands are ignored whencontrol is required. Logic is provided to monitor theunit’s response to control, using this deadbandvalue,if the calculated unit control error exceeds itsdeadband.

8. Conclusion

The Automatic Generation Control is assigned theresponsibility of adjusting generator outputs to meetthe following functions:

1. Maintain system frequency at the nominal value.

2. Maintain scheduled interchange.

3. Utilize economic dispatch (ED) program data toachieve the above objectives in the mosteconomic way.

AGC as with any feedback system, dynamic behavioris of prime importance. In this paper an overview ofthe AGC data, AGC control modes, AGC operationmodes, unit control modes and some of the mostimportant AGC features is presented.

References

1. N. Cohn, Control of Generation and Power Flow onInterconnected Power Systems, John Wiley, 1971.

2. LN6000 AGC Operation Manual.

3. N. Jaleeli, D. Ewart, and L. Fink, “UnderstandingAutomatic Generation Control”, Transaction onPower Systems, Vol. 7, No. 3, 1992.

4. IEEE Standard 94, “Definitions for AutomaticGeneration Control”, IEEE Transactions on PowerSystems, Vol. PAS-89.