lecture 44 agc 1

AGC

• AGC componentsLoad frequency control (LFC)Economic Dispatch(ED)Interchange Scheduling (IS) • AGC is also referred as System Control Load Dispatch

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Generator Turbine Governor Behavior

•Generation (Mechanical Power) – Load (Electrical Power) imbalance results in change in machine speed, frequency and power flow

•Machine electro‐mechanical dynamics is described by swing equation

•A single generator and load is analyzed and then generalized to large system


Pm

Pl

Pm‐Pl = M [dω/dt]

For small changes in parametersΔ Pm‐ Δ Pl = M[d (Δ ω) / dt]


1/(Ms)

A sustained load – generation imbalanced would lead to a continuous change in frequency!!

Δ Pm(s)

Δ Pl(s)

Δ ω(s)

Load response to frequency change

• For Rotating components of load the real power increases with frequencyΔ Pl(s) = Δ Pl(s)+ DΔ ω(s)

Δ Pl(s) now is an ‘incipient’ load change ( a motor starts)DΔ ω(s) represents the response that the additional load causes frequency to drop, all motors slow down, and so load drops as DΔ ω(s)


Δ Pm(s)‐ Δ Pl(s)‐D Δ ω(s) = sM Δ ω(s)

Δ ω(s)= [Δ Pm(s)‐ Δ Pl(s)]/ (Ms+D)

1/(Ms+D)

Δ Pm(s) +

Δ Pl(s) ‐Δ ω(s)


Measures speed(frequency) and adjusts valves to change generation

Frequency drops => Raise generation

The Governor

PmPl

Pe

Speed

Governor Desired Generation


Pm

Pl

Pe

Speed

Governor

Desired Generation

Generator Turbine Governor BehaviorSteady State Response

Steady state error

Using energy balance

Δ Pl ‐ D Δω ‐ (1/R) Δω = 0

Load Load GenerationChange Response Change from

Governor

Δω = ‐ Δ Pl /( D+1/R)

Typical R = 0.05 pu ( 5% factory set)

For ΔP = 1 , D = 1, R=0.05 Δω = 1/21 = ‐ 0.0476 pu

Single Turbine Generator with load

• For a change in load, speed/ frequency changes (with generation remaining unchanged):

• [Pm – Pl] = M [dω/dt ] Rotor Inertia Equation

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Pm

PlTurbine Gen

Speed Change due to load imbalance

• The governing system senses change in speed and adjusts steam control valve ( gate) so that mechanical power (Pm) matches with the changed load (Pl).

• The change in frequency (Δω) at steady state can be described using the DROOP equation in terms of change in load (Δ Pl) and a factor R called ‘speed regulation or ‘droop’.Δω = ‐ [Δ Pl ]( R) Droop equation

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Single Turbine Generator with load

• [Pm – Pl] = M [dω/dt ] Rotor Inertia Equation• Δω = ‐ [Δ Pl ]( R) Droop regulation equation

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Pm

PlTurbine Gen

LOAD DROP RESPONSE

Load

100%

Time(sec)

t

100%80%

Speed(%)

Speed does not returnTo 100 %

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Proportional Control : Droop

Rotor Inertia_

+

Load

Generation

Speed Reference

Speed‐

+

Control action stops when the power error has zero value

Speed error

Speed error present at steady state

Steady state: Generation = Load , butMachine speed differentfrom Speed set point

Proportional

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1.0

1.0

Power (p.u)

Speed( p.u)

Droop Characteristic

0.5

1.02

0.0

1.04

1.0 p.u or 100 % change

0.04 p.uor 4 %change

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NEED FOR SUPPLEMENTARY CONTROL

• Speed variation stops but at a different steady value.

• The speed however has to be brought back to the original value for which speed/ load reference has to be adjusted either by the operator or by a supplementary control system called Load Frequency Control (LFC) system

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20

+

Pref

-

Combined Mechanical

Power

+Composite Governor Composite Turbine Power System

Inertia

BLOCK DIAGRAM SHOWING POWER SYSTEM FREQUENCY VARIATION

Total Elec. load

Frequency

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Set point○

Generator Power

Frequency

Total Generation

TotalLoad

Primary regulation

Other m/c

To OtherMachines

Set point AreaFreq-uency

Secondary regulation

-- +

++

+○

○

○

AUTOMATICLOAD REQUENCY

CONTROLLER

Governor Turbine GRIDINERTIA

Fig 7 AUTOMATIC LOAD RFEQUENCY CONTROL SYSTEM

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Energy Management System(EMS)-Automatic Generation Control (AGC)

Electro Hydraulic Governor (EHG)




Turbine-Generator (TG)




Set Point

Set Point

Set Point

Set Point

Frequency (f)

f

f

f

SYSTEM CONTROL CENTER (SCC)

HYDRO POWER PLANTS

Telemetry

------…..

Generation Signals (MW)

System Frequency

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Load Frequency ControlLFC Implementation

FrequencyMeasured At a centralLocation Tie line flows(MW)

Desired Frequency

Net Interchange

ACE

Filters K ∫ AllocationTo Plants

Other Considerations

∆PrefTo Units

Economic Dispatch SeverityActual Unit Movement Unit Energy BalanceMinimum Movement Response Rate Time error

~ every 4 sec

~ every 4 sec

Multiple Generators and Areas

Pm1

P1l

Pe1

Pm2

Pl2

Pe2

jX

Area 1 or Gen 1 Tie Line Area 2 or Gen 2

Ptie

Now look at two generators or areas connected by a line or network

If load changes in any area how do frequencies and line power Ptie change?

We will want to restore both to nominal value

A simple model for the line is just a series inductive reactance

Multiple Generators and Areas

Pm1

P1l

Pe1

Pm2

Pl2

Pe2

jX

Area 1 or Gen 1 Tie Line Area 2 or Gen 2

Ptie

Qualitative Response

Load increase in area 1Area 1 frequency dropsArea 1 voltage phase angle falls behind are 2Ptie decreases (stabilizes Area 1 frequency, drags down area 2)Area 2 frequency dropsBoth governors raise generationSteady state achieved at a lower frequency and PtieArea 1 assists Area 2 in meeting the load increase; frequency drop is lower

Area Control Error (ACE)

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• TIE‐LINE BIAS CONTROL. In this control strategy each area of an interconnected system tries to regulate its area control error (ACE) to zero, where:

Difference between the actual (a) and the scheduled (s) net interchange on the tie lines. Frequency error

System natural response coefficient

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ACE Generation

ACE > 0, DECREASE Generation

ACE< 0 , INCREASE GENERATION

Load Frequency Control

• Governors ensure that frequency is restored to near‐nominal

• This happens irrespective of location of load/generation change

• The purpose of LFC is to reallocate generation so – System wide frequency is restored – Each area meets its obligation Load+Interchange

Load Frequency Control• Definition

– Area Control Error (ACE)

ACE = Δ Net Interchange + β Δ f

Δ Net Interchange = Interchange error = Scheduled – Actual

Δ f = Δ ω = frequency deviationβ = frequency bias ( pu MW/ pu frequency)

Definition is sometimes written with negative sign on both terms

Load Frequency Control• Basic Idea

– ACE> 0 decrease generation– ACE<0 increase generation

• Assume load increases in one area only– Frequency drops everywhere Δf<0– Interchange from affected area decreases Δ Net Interchange <0– Interchange from other areas increases Δ Net Interchange >0

– Affected area has negative ace– In other are ACE is small or zero

– Affected area increases generation– Others stay put

Load Frequency ControlProperties of ACEAs long as one frequency bias β≠0

If all areas have ACE=0

then Δω = 0and all Δ Net Interchange =0

Driving ACE to zero restores frequency and interchange


Properties of ACE 1Two areas ( loss ignored)

ACE 1 = ΔNet Interchange + β1 ΔωACE 2 = ‐ΔNet Interchange + β2 ΔωΔω= (ACE1+ACE2)/(β1 + β2 )

= 0 if ACE1=ACE2=0 and β1 + β2 ≠0Then Interchange error is also zero


Properties of ACE 1Two areas ( loss ignored)ACE 1 = ΔNet Interchange + β1 ΔωACE 2 = ‐ΔNet Interchange + β2 ΔωΔω= (ACE1+ACE2)/(β1 + β2 )

= 0 if ACE1=ACE2=0 and β1 + β2 ≠0Then Interchange error is also zeroReasonable values of β1 , β2 will work

Load Frequency ControlProperties of ACE 2

Choose βi = Di + 1/RiIdeally

ΔNet Interchange = ‐(Di+1/Ri) Δω –ΔPliΔNet Interchange +Di+1/Ri) Δω = –ΔPliACEi = ‐PLi !!!!!!!!

Since 1/Ri >> Di we know Di+1/Ri pretty well

ACE measures area load change– should give us good control

From LFC to Economic Allocation

Time

MW

ΔωGovernor~seconds

LFC~minutes

Units pick up load α capacity

LFC distributes based on response

Economic dispatch

AGC Scheme

From Grainger and Stevenson Jr)

From LFC to Economic Allocation

Time

MWEconomic dispatch

Coal

Gas

Pref changes

The Economic dispatch problem• Given

– N units on‐line– System Load + Loss

– Equals Area Net Generation‐ Net Interchange when ACE~0

• Determine – MW allocation(Schedule) for each Unit– Minimize Fuel and Variable O&M cost

• Constraints A constrained– Unit capacity, Reserves optimization problem

The Economic dispatch problem

Minimize Pi

CT= C1(P1)+C2(P2)+…+CN(PN)

P1+P2+…+PN= PT

Pimin≤ Pi≤ Pimax i=1,2,…,N

Ci(Pi) = Fuel + Variable O&M cost ($/H) unit iPi = Net MW output Unit IPimin, Pimax = Min and Maximum Capacity Unit i

Load Variation with frequency

• Motor load in particular is affected by frequency • When frequency drops, motors slow down, produce less work, and consume less energy

• Frequency drops by 1%, motor load will drop 3%.• Non‐motor resistive load generally remainsconstant.• The net for both of the above is a general rule ofthumb:+/‐ 1% change in freq. = +/‐ 2% change in load

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Deadband

• An additional feature displayed by generators. • Deadband is the amount of frequency change a governor must “see” before it starts to respond.

• Deadband was really a natural feature of the earliest governors caused by gear lash (looseness or slop in the gear mechanism)

• Deadband serves a useful purpose by preventing governors from continuously “hunting” as frequency varies ever so slightly

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Policy of the NERC

• Generators with nameplate ratings of 10• MW or more must have governors installed.• Governors should provide 5% droop.• Deadband on all governors must be set to

+/‐ 0.036 Hz (on 60 Hz system)

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FRC

• Frequency Response or Frequency Response Characteristic (FRC) is the change in frequency that occurs for a change in load‐resource balance in a control area or interconnection

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• Example:• If a generator of 1,000 MW is lost somewhere in a control area, frequency will decline.

• The actual amount of decline will depend on:• Characteristics of the load (how much motor load)

• The total governor response available• Number of generators on line• Their relative loading• Their governor settings

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53

Graph shows frequency excursionsvs. generation loss

Line represents the averagefrequency response of 1,500MW/0.1 Hz.

• Graph shows frequency excursions• vs. generation loss• • 350 events were tracked in WECC• from 1994 to 2002• • Line represents the average• frequency response of 1,500• MW/0.1 Hz.• Note: The total Frequency• Response in an Interconnection• is the sum of the responses• from all control areas within the• Interconnection

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• As mentioned, Frequency Response Characteristic (FRC) is the actual response provided by control areas for a particular set of events.

• Control areas use Automatic Generator Control (AGC) systems to meet their minute‐to‐minute obligations to serve their internal load.

• When an excursion happens external to a control area, there should be an immediate outflow from the control area to arrest frequency decline.

• The outflow itself is from “load rejection” and governor• response.• In order to prevent AGC from “fighting” this natural frequency

support, a “Bias” term is added to the ACE equation.

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lecture 44 agc 1

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