lecture 44 45 agc 1 and 2
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autmatic generation cntrlTRANSCRIPT
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Lecture 44 and 45
AUTOMATIC GENERATION CONTROL
1.0 INTRODUCTION
Maintaining power system frequency at constant value is very important for the health of the power generating equipment and the utilization equipment at the customer end. The
job of automatic frequency regulation is achieved by governing systems of individual
turbine-generators and Automatic Generation Control (AGC) or Load frequency control( LFC) system of the power system.
2.0 FREQUENCY VARIATION IN A SINGLE MACHINE
To understand the variation of frequency in a power system, we can consider a singlemachine connected to an isolated load, as shown in the figure below.
Fig.1 SINGLE TURBINE GENERATOR WITH LOAD
Normally, the turbine mechanical power (Pm) and the electrical load power (Pl) are
equal. Whenever there is a change in load, with mechanical power remaining the same
the speed (ω) of the turbine generator changes as decided by the rotating inertia (M) of the rotor system, as given by the following differential equation..
Pm-Pl = M [d ω/dt ]
The governing system senses this change in speed and adjusts steam control valve so
that mechanical power (Pm) matches with the changed load (Pl). Speed variation stops but at a different steady value. The change in frequency (Δω) at steady state can be
described using the following equation in terms of change in load (Δ Pl) and a factor R called ‘speed regulation or ‘droop’.
Δω = - [Δ Pl ]( R)
A 20 % change in load (Δ Pl = 0.2 per unit) causes 1 % change in frequency (Δω = 0.01 p.u) with a per unit (p.u) droop value of 0.05. Similarly full load throw off (Δ Pl = - 1.0)
Pm
PlTurbine Gen
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causes 5 % change in speed. (Δω = + 0.05). This is described by the well known droop
characteristic.
3.0 NEED FOR SUPPLEMENTARY CONTROL
Now when there is a load change, speed settles down after a transient period at a value
different from the original steady speed. This new speed value is dictated by the droop
value. For instance a 100 % load rejection will cause the machine speed to settle down at105 % speed, with a droop value of 5 %, as shown in the figure below. During the
transient, speed may touch a higher value as shown in the figure (by TSR: transient speed
rise). The speed however has to be brought back to the original value for which speed/load reference (Pref) has to be adjusted either by the operator or by a supplementary
control system.
In the speed control system block diagram shown in Fig. 4, when elec. load changes,
reference set point is to be adjusted to restore speed to the pre-disturbed value. This is
equivalent to shifting the speed droop characteristic to match the new operating load asshown in Fig. 5.
Load
100%
Time sec
t
100%0%
Speed (%)
TSR
(6 - 10%)
5% Droop
Fig 3 LOAD REJECTION RESPONSE
Frequency
(Hz)
50
5% Droop
Load 0% 50% 100%
Fig.2 SPEED REGULATION CHARACTERISTIC
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4.0 AUTOMATIC GENERATION CONTROL (AGC)
Automatic Generation Control (AGC) usually implemented in Energy Managementsystem (EMS) of Energy Control centers (ECC) consists of
Load frequency control
Economic Dispatch
Interchange scheduling
In this section Load frequency control is described.
LOAD FREQUENCY CONTROL
The speed/ frequency variation concept can be extended from a single turbine- generator
system to a power system comprising several turbine- generators as shown in Fig.6. Now
the mismatch between the total power generated and the total electrical load causes thefrequency change as dictated by the combined system inertia. The governors of all the
Frequency
(Hz)
50
Load 0% 50% 100%
Fig.5 SHIFTING OF SPEED REGULATION
CHARACTERISTIC
SPE
E
DValvePosition
Pref SET
-Mechanical
Power
GOVERNOR TURBINE ROTOR
INERTIA
Fig 4 GOVERNING SYSTEM FUNCTIONAL BLOCK DIAGRAM
Elec.load
Operating point
shifted to 50 %
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machines sense the frequency and the mechanical power outputs will be changed
automatically to match the combined generation with the new combined load. This actionis called primary regulation.
But frequency remains at a new value and set points must be adjusted, just as in single
machine case for frequency restoration. This job is done by the Automatic Load Frequency controller (ALFC) as shown in Fig. 7. This process of set point adjustment is
called secondary regulation.
When load change occurs frequency varies and the regulation initially for the first few
seconds is due to the action of the governors of all generating units and subsequently the
Load frequency control system prevails.
5.0 POWER SYSTEM FREQUENCY CONTROL :INDIAN SCENARIO
In India, the power system is divided into regions. Load Despatch Center in each regionmonitors the frequency by interacting with State Load Despatch Centers and generating
Pref
-Combined Mechanical
Power
Composite
Governor Composite
Turbine
Power System
Inertia
Fig 6 BLOCK DIAGRAM SHOWING POWER SYSTEM FREQUENCY VARIATION
Total Elec.
load
Fre uenc
Set point
○
Generator
Power
Frequency
Total Generation
Total
Load
Primary regulation
Other m/c
To
Other
Machines
Set point Area
Freq-
uency
Secondary regulation
-
-
○
○
○
AUTOMATIC
LOAD REQUENCY
CONTROLLER
Governor Turbine
GRID
INERTIA
Fig 7 AUTOMATIC LOAD RFEQUENCY CONTROL SYSTEM
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stations under the control of States and the generating companies like NTPC, NHPC. The
Regional Load Despatch Centers (RLDC) function under Power Grid Corporation of India. So, for the purpose of frequency each region can be considered as one coherent
unit. For instance Southern RLDC comprises AP, TN, Karnataka, Kerala and Goa.
SRLDC is located in Bangalore.
For the load frequency control, the generating units at Hydro power plant are normally
adjusted as the response is faster to raise/lower the power. Thermal power plants have
‘rate’ limitations due to thermal stresses. But all units are expected to participate in primary regulation.
Load – Generation imbalance causes frequency variation. Load is never constant. Precisefrequency control is possible only if there is a surplus generating capacity, which is not
the case in many states. Hence load shedding is resorted to for frequency management.
There is no AUTOMATIC load frequency control in many regions as many utilities want
to generate to the maximum possible extent and would not like their generation levelsadjusted by ALFC. Mostly manual control is only exercised to maintain frequency.
In many cases, generators are not allowed to participate in primary regulation also i.e.,
the natural tendency of the governors to raise/ lower generation when frequency falls/
rises is suppressed. With the result, frequency is always less than the rated value of 50Hz. When sudden disturbances occur, system collapses causing blackouts. The situation
has vastly improved in the recent years after the introduction of availability cased tariff
(ABT) and free governor mode of operation (FGMO) regimes.
6.0 FREE GOVERNOR MODE OF OPERATION (FGMO)
To maintain grid discipline, all generating units shall have their governors in free
operation (natural governing ) at all times.
In Indian grid code the following specifications are given.
The rated System frequency is 50 Hz and the target range for control should be 49.0 Hz – 50.0 Hz the statutory acceptable limits are 48.5 - 51.5Hz.
Each operating machine should pick up load as below:Up to MCR: 5% extra load for at least 5 minutes.
Above MCR :105 % of MCR
Facility available like load limiters, ATRS etc, shall not be used to suppressnatural governor action in any manner
All governors shall have a droop of between 3% and 6%.
No dead band or time delays should be deliberately introduced
Each Generating Unit shall be capable of instantaneously increasing output by 5%when the frequency falls, limited to 105% MCR.
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Ramping back to the previous MW level (in case the increased output level cannot be sustained) shall not be faster than 1% per minute.
At 49 Hz, all constituents shall resort to adequate manual load shedding instantly,
Operating frequency should not touch such level, which may trigger Under Frequency Relay (UFR) operation; as UFR actuated shedding is meant only for
taking care of contingencies like sudden losses of bulk generation etc. The recommended rate for changing the governor setting, i.e., supplementary
control for increasing or decreasing the output (generation level) for all generating
units, irrespective of their type and size, would be one (1.0) per cent per minute or
as per manufacturer’s limits.
However, if frequency falls below 49.5 Hz, all partly loaded generating units shall
pick up additional load at a faster rate, according to their capability.
Implementation of FGMO in power plant
In a typical 200 MW/ 250 MW thermal power plant, implementation scheme isshown in the figure below.
LOAD
CORRECTION OF
+/-APPOX 2.5 MW
FOR +/- 1 KG/CM2
TURB MAX
LOAD LIMIT.
(220 MW)
BOILER FUEL
CONTROL.
CORRECTION
DUE TO PR.
VARIATIONS
MIN
TURBINE
CONTROL.
DEAD TIME (2.5 MINUTES)
SCHEME OF FGMO.
FGMO WORKS WITHIN THE LOAD SET PT
LIMITS OF 175 MW TO 220 MW ONLY
CMC LOAD ST. PT.
LOAD CORRECTION
DUE TO FREQ. +/- 20 MW
MIN.
CMC MAX LOAD
LIMIT. ( 220 MW)
LOAD SET POINT.
Fig 8 IMPLEMENTATION OF FGMO IN A TYPICAL 210 MW PLANT
The Coordinated Master Control ( CMC) scheme gives commands to the turbinecontrol as well as the boiler fuel control to raise/lower generation. When frequency
changes these command signals are modified with a limit of plus or minus 20MW as
shown below in Fig.9.
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In case CMC is not there FGMO can be implemented in the Load control loop of theelectro hydraulic turbine controller (EHTC).
Fig.9
7.0 AUTOMATIC GENERATION CONTROL : DESIGN AND IMPLEMENTATION ASPECTS
The objective of the AGC in an interconnected power system is to maintain the frequency of each area
and to keep tie-line power close to the scheduled values by adjusting the MW outputs the AGC generators
so as to accommodate fluctuating load demands.
The components of AGC in the modern power system are:
Load-frequency control (LFC) Economic dispatch (ED)
Interchange scheduling (IS)
When frequency changes, under primary regulation, governors respond immediately. But as mentioned
earlier, frequency does not get restored but will settle down at a different value. At this point of time LFC
function comes in to the picture.LFC maintains the system frequency by performing the function of Secondary Regulation. It provides generation set points to the generators participating in the frequency
regulation. But these set points may not be the optimum from cost point of view. Economic dispatch (ED)
function readjusts the set points of the generations after the time scale of LFC.
In a large interconnected power system there are a number of areas connected by tie lines with share
agreements with neighbors. The LFC and ED functions have to take care of these agreements. This
function is performed by Interchange Scheduling (IS).. Each of these areas is responsible for generatingenough power to meet its own customers or "native load." By keeping the generated power equal to the
power consumed by the load, utilities keep the overall system frequency at 50 Hz. Not only must areas
adjust their generation to meet their own changing native load, but they must also maintain anyscheduled tie-line transactions. It is possible, by monitoring both the tie-line flow and the system frequency
to determine the proper generation action (raise or lower). Thus, electric utilities use an automatic
generation control (AGC) system to balance their moment-to-moment electrical generation to load
within a given control area.
+20 MW
- 20 MW
50 51 Hz 52 Hz48Hz 49Hz
LOAD CORRECTION WITHOUT DEAD BAND
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The current practice of the load frequency control (LFC) function of automatic generation control (AGC) is
based on a strategy known as 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:
The term (T,-T, ) is the difference between the actual and the schleduled net interchange on the tie lines.
The term representing the area's natural response to frequency deviations is lOp(f,-f,). The coefficient, p, isknown as the system natural response coefficient. It is difficult to obtain an accurate value of p since itdepends on the governor reslponse capability of the generating units presently on-line and the frequency
dependence of the constantly changing load. This characteristic is expressed as:
where, (1/R) is the generator regulation or droop, D is the load damping Characteristic.
Figure 10: AREA CONTROL ERROR WITH FREQUENCY
Area Control Error (ACE)
ACE = Δ Net Interchange + β Δ f
Δ Net Interchange = Interchange error = Scheduled – ActualΔ f = Δ ω = frequency deviationβ = frequency bias ( pu MW/ pu frequency)
Basic Idea in AGC design is that when :ACE> 0 generation decreased and ACE<0 generation is
increased.
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
LFC Implementation:
Ideally ΔPrefi = -ACEi
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More practically it is necessary to use integral control ( or Proportional integral control)
ΔPrefi = - Ki ∫ ACEi dt
Note in steady state ΔPrefi must become constant and ACEi=0. Then necessarily Prefi=ΔPli.
Integral control with stable gain Ki guarantees zero error.
Load Frequency ControlLFC Implementation
FrequencyMeasuredAt a centralLocation Tie line flows(MW)
DesiredFrequency
Net Interchange
ACE
Filters K ∫ Allocation To Plants
Other Considerations
∆Pref To Units
Economic Dispatch SeverityActual Unit Movement Unit Energy BalanceMinimum Movement Response Rate Time error
~every 4 sec
~every 4 sec
Fig 11 LOAD FREQUENCY CONTROL SCHEME
In the modern Energy Management Systems (EMS) automatic load frequency control
system (ALFC) is part of Automatic Generation Control (AGC).
In power systems, where automatic control does not exist, manual control of set points is
done on instructions from dispatch center.
In this response curve taken from published literature, a loss of generation has resulted in
a frequency fall from 60.01 Hz to 59.209 Hz and due to governor actions (primaryregulation), frequency starts increasing and it should have settled around 59.75 Hz as
shown
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below.
Fig. 12 Typical frequency response of a 60-Hz power system with AutomaticGeneration Control (AGC) for a step load increase
But Automatic Generation Control (AGC) system which includes Load Frequency
Control (LFC) acts on the set points of the governors and frequency gets restored to the
60 Hz value as shown in the response curve (Fig. 12).
For a similar system, measured frequency variation when large generation is lost is
shown in Fig. 13.
Fig. 13 Typical frequency response of a 60-Hz power system with Automatic
Generation Control (AGC) for a generation loss
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The AGC implemented in developed countries includes load frequency control (LFC),
economic dispatch (ED) and interchange scheduling (IS). These are implemented asapplication programs in Energy Management System (EMS) software located in Energy
Control Centers. (ECC).
The implementation scheme for AGC is shown in Fig. 14 .The AGC function withinSCADA/EMS will receive frequency, generations (MW) etc., signals through remote
terminal units (RTUs).
Fig. 14 Typical implementation schemeof Automatic Generation Control (AGC)
When there is a frequency change primary control action is performed by the governors
of prime movers. After few seconds Secondary Control function by Automatic generationcontroller (AGC) is initiated. AGC computes the set point changes required to restore the
frequency to the set value and issues commands to participating generating units.
8.0 CONCLUSIONS
The basic concepts of power system load frequency control system are described in this
article. In the literature, it is also referred to as Automatic Generation Control (AGC)where apart from load frequency control, economic allocation is also included. The
Energy
Management
System(EMS)
-AutomaticGeneration
Control (AGC)
ElectroHydraulic
Governor
(EHG)
Electro
HydraulicGovernor
(EHG)
Electro
HydraulicGovernor
(EHG)
Electro
HydraulicGovernor
(EHG)
Turbine-
Generator
(TG)
Turbine-
Generator
(TG)
Turbine-Generator
(TG)
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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computer based Energy Management System (EMS) installed in modern power systems
includes AGC also.
The concepts of Free governor mode of operation (FGMO) and implementation are also
described.
9.0 REFERENCES
1. Frequency Control Concerns In The North American Electric Power SystemDecember 2002 by B. J. Kirby, J. Dyer, C. Martinez, Dr. Rahmat A. Shoureshi
R. Guttromson, J. Dagle, December 2002, ORNL Consortium for Electric Reliability
Technology Solutions
2. N. Jaleeli, D.N. Ewart, and L.H. Fink, “Understanding Automatic Generation Control,
“IEEE Transactions on Power System, Vol. 7, No. 3 August 1992, pp. 1106- 1122.
3. A.J. Wood and B.F. Wollenberg, Power Generation, Operation, & Control, JohnWiley & Sons, 1984.
4. R.L. King and R. Luck, “Intelligent Control Concepts for Automatic Generation
Control of Power Systems,” NSF Annual Report ECS-92-16549, March 31, 1995.
5. P. Kundur, Power System Stability and Control, The EPRI Power System Engineering
Series, McGraw-Hill, 1994
6. C. Concordia, F. P. deMello, L.K. Kirchmayer and R. P. Schulz, "Effect of Prime-
Mover Response and Governing Characteristics on System Dynamic Performance,"American Power Conference, 1966, Vol. 28, pp. 1074-85, IEEE transactions on Power
Systems, Vol. XX, 1999
7. Dynamic Analysis of Generation Control Performance Standards Tetsuo Sasaki,Kazuhiro Enomoto
8. Nasser Jaleeli, Louis S. VanSlyck: “NERC’S NEW CONTROL PERFORMANCESTANDARDS”, IEEE Trans. on Power Systems,Vol.14,No.3,pp.1092-1099,1999
9. North American Electric Reliability Council, NERC Operating Manual, Policy 10,
available at ⟨http://www.nerc.com.