Automatic Generation Control Dr M S R Murty
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Automatic Generation Control (AGC) • Automatic frequency regulation by governing systems of individual turbine‐ generators and Automatic Generation Control (AGC) or Load frequency control ( LFC) system of the power system. • In Energy Management system (EMS) at the Energy Control Center (ECC) 2
AGC • AGC components Load frequency control (LFC) Economic Dispatch(ED) Interchange Scheduling (IS) • AGC is also referred as System Control Load Dispatch 3
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
Generator Turbine Governor Behavior Pm‐Pl = M [dω/dt]
Pl Pm
For small changes in parameters Δ Pm‐ Δ Pl = M[d (Δ ω) / dt]
Generator Turbine Governor Behavior Δ Pm(s)
1/(Ms)
Δ Pl(s) A sustained load – generation imbalanced would lead to a continuous change in frequency!!
Δ ω(s)
Load response to frequency change • For Rotating components of load the real power increases with frequency Δ 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)
Generator Turbine Governor Behavior 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)
Δ Pm(s) + 1/(Ms+D) Δ Pl(s) ‐
Δ ω(s)
Generator Turbine Governor Behavior Pe Pl Pm
Speed
Governor
Desired Generation
The Governor Measures speed(frequency) and adjusts valves to change generation Frequency drops => Raise generation
Generator Turbine Governor Behavior Pe Pl Pm Speed
Governor
Desired Generation
Generator Turbine Governor Behavior Steady State Response Using energy balance
Δ Pl ‐
D Δω ‐ (1/R) Δω = 0
Load Load Generation Change Response Change from Governor
Steady state error
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 Turbine
Gen
Pl
Pm
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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 13
Single Turbine Generator with load • [Pm – Pl] = M [dω/dt ] Rotor Inertia Equation • Δω = ‐ [Δ Pl ]( R) Droop regulation equation
Turbine
Gen
Pl
Pm
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LOAD DROP RESPONSE Load
100% 80%
Speed (%)
t
100%
Speed does not return To 100 % Time(sec)
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Proportional Control : Droop Load Speed error _
Speed Reference Proportional
+ ‐
+ Generation
Rotor Inertia
Speed
Control action stops when the power error has zero value
Speed error present at steady state
Steady state: Generation = Load , but Machine speed different from Speed set point 16
Droop Characteristic Speed( p.u) 0.04 p.u or 4 % change
1.04 1.02 1.0
0.0
0.5
1.0 Power (p.u)
1.0 p.u or 100 % change 17
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 18
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Pref Composite Governor
+
Power System Inertia
Composite Turbine
+
Frequency
Total Elec. load Combined Mechanical Power
BLOCK DIAGRAM SHOWING POWER SYSTEM FREQUENCY VARIATION
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Set point ○
To Other Machines
Set point
Secondary regulation
AUTOMATIC LOAD REQUENCY CONTROLLER
Governor
Generator Other m/c Power ○ + Turbine
○
-
Total Load
+
-
GRID INERTIA
+ ○ Frequency
+
Area Frequency
Total Generation Primary regulation
Fig 7 AUTOMATIC LOAD RFEQUENCY CONTROL SYSTEM
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Generation Signals (MW)
Frequency (f)
Telemetry
Set Point Electro Hydraulic Governor (EHG)
-----….. Energy Management System (EMS) -Automatic Generation Control (AGC)
TurbineGenerator (TG)
f Set Point Electro Hydraulic Governor (EHG)
TurbineGenerator (TG)
Set Point
f Electro Hydraulic Governor (EHG)
SYSTEM CONTROL CENTER (SCC)
TurbineGenerator (TG) f
Set Point
System Frequency
Electro Hydraulic Governor (EHG)
TurbineGenerator (TG)
HYDRO POWER PLANTS
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Load Frequency Control
LFC Implementation
Frequency Measured At a central Location
Tie line flows(MW)
~ every 4 sec
Net Interchange Desired Frequency
ACE Filters
K
∫
Allocation To Plants
Other Considerations Economic Dispatch Actual Unit Movement Minimum Movement
∆Pref To Units ~ every 4 sec
Severity Unit Energy Balance Response Rate
Time error
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Multiple Generators and Areas Ptie
Pe1
Pe2 jX
P1l Pm1
Pl2 Pm2
Area 1 or Gen 1
Tie Line Area 2 or Gen 2
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 Ptie Pe1
Pe2
jX P1l Pm1 Area 1 or Gen 1 Qualitative Response
Pm2 Tie Line Area 2 or Gen 2
Load increase in area 1 Area 1 frequency drops Area 1 voltage phase angle falls behind are 2 Ptie decreases (stabilizes Area 1 frequency, drags down area 2) Area 2 frequency drops Both governors raise generation Steady state achieved at a lower frequency and Ptie Area 1 assists Area 2 in meeting the load increase; frequency drop is lower
Pl2
Area Control Error (ACE) • 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 26
ACE Generation
ACE > 0, DECREASE Generation ACE< 0 , INCREASE GENERATION 27
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 deviation β = 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 Control Properties of ACE As long as one frequency bias β≠0 If all areas have ACE=0 then Δω = 0 and all Δ Net Interchange =0
Driving ACE to zero restores frequency and interchange
Load Frequency Control Properties of ACE Two areas ( loss ignored) ACE 1 = ΔNet Interchange + β1 Δω ACE 2 = ‐ΔNet Interchange + β2 Δω Δω= (ACE1+ACE2)/(β1 + β2 ) = 0 if ACE1=ACE2=0 and β1 + β2 ≠0 Then Interchange error is also zero
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Load Frequency Control Properties of ACE Two areas ( loss ignored) ACE 1 = ΔNet Interchange + β1 Δω ACE 2 = ‐ΔNet Interchange + β2 Δω Δω= (ACE1+ACE2)/(β1 + β2 ) = 0 if ACE1=ACE2=0 and β1 + β2 ≠0 Then Interchange error is also zero Reasonable values of β1 , β2 will work
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Load Frequency Control Properties of ACE
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Choose βi = Di + 1/Ri Ideally ΔNet Interchange = ‐(Di+1/Ri) Δω –ΔPli ΔNet Interchange +Di+1/Ri) Δω = –ΔPli ACEi = ‐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 Economic dispatch MW LFC distributes based on response Units pick up load α capacity
Δω Governor ~seconds
LFC ~minutes
Time
AGC Scheme From Grainger and Stevenson Jr)
From LFC to Economic Allocation Economic dispatch MW
Pref changes
Coal
Gas
Time
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 CT= C1(P1)+C2(P2)+…+CN(PN) P1+P2+…+PN= PT Pi Pimin≤ Pi≤ Pimax
i=1,2,…,N
Ci(Pi) = Fuel + Variable O&M cost ($/H) unit i Pi = Net MW output Unit I Pimin, 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 remains constant. • The net for both of the above is a general rule of thumb: +/‐ 1% change in freq. = +/‐ 2% change in load 40
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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 42
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 52
Graph shows frequency excursions vs. generation loss
Line represents the average frequency response of 1,500 MW/0.1 Hz. 53
• • • • • • • • • • • •
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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