Effects of the Droop Speed Governor and Automatic Generation Control AGC on Generator Load Sharing of Power System

International Journal of Applied Power Engineering (IJAPE)
Vol.4, No.2, August 2015, pp. 84~95
ISSN: 2252-8792  84
Journal homepage: http://iaesjournal.com/online/index.php/IJAPE
Effects of the Droop Speed Governor and Automatic
Generation Control AGC on Generator Load Sharing of Power
System
Youssef Mobarak
Department of Electrical Engineering, Faculty of Engineering, Rabigh, King Abdulaziz University, Saudi Arabia
Article Info ABSTRACT
Article history:
Received Mei 12, 2015
Revised Jun 20, 2015
Accepted Jul 26, 2015
In power system, as any inequality between production and consumption
results in an instantaneous change in frequency from nominal, frequency
should be always monitored and controlled. Traditionally, frequency
regulation is provided by varying the power output of generators which have
restricted ramp rates. The Automatic Generation Control AGC process
performs the task of adjusting system generation to meet the load demand
and of regulating the large system frequency changes. A result of the
mismatches between system load and system generation, system frequency
and the desired value of 50 Hz is the accumulation of time error. How
equilibrium system frequency is calculated if load parameters are frequency
dependent, and how can frequency be controlled. Also, how do parameters of
a speed governor affect generated power. The transient processes before
system frequency settles down to steady state. Finally, AGC in what way is it
different from governor action. This paper presents new approaches for AGC
of power system including two areas having one steam turbines and one
hydro turbine tied together through power lines.
Keyword:
Automatic Generation Control
Frequency control
Power control
Power quality
Power system interconnection
Copyright © 2015 Institute of Advanced Engineering and Science.
All rights reserved.
Corresponding Author:
Youssef Mobarak,
Departement of Electrical Engineering,
Faculty of Energy Engineering, Aswan University,
81528, Aswan, Egypt.
Email: ysoliman@kau.edu.sa
1. INTRODUCTION
In general, electrical power systems are interconnected to provide secure and economical operation.
The interconnection is typically divided into coalmen, with each consisting of one or more power utility
companies [l]-[4]. The control areas are connected by transmission lines commonly referred to as tie-lines
and the power flowing between control areas is called tie-line interchange power. One of the main
responsibilities of each control area is to supply sufficient generation to meet the load demand of its
customers, either with its own generation sources or with power purchased from other control areas. The
speed-governing system provides a primary control function that responds quickly to frequency changes
caused by a change in the active power balance between generation and load. For governs with speed-droop
characteristics, a steady-state frequency deviation from the desired system frequency remains following the
primary control action. This deviation is corrected using the AGC function. Compared to the primary control
process, this control is slower to respond to changes in the load demand. AGC has been utilized by power
utilities for several decades. The approach used today generality provides acceptable levels of performance
based primary upon AGC operation criteria specified by the North American Electric Reliability Council
(NERC) [5]-[9].
AGC is an important problem in power system operation and control, whenever a small load
perturbation occurs, it causes the changes in tie-line power flow and frequency deviation. Many

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Effects of the Droop Speed Governor and Automatic Generation Control AGC on… (Youssef Moubarak)
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investigations in the area of AGC of interconnected power systems have been carried out in the past [10]-[13]
and number of control strategies have been proposed to improve the performance of AGC. Present AGC
schemes used to combat this problem utilize a static, linear system response characteristic to mode1 the
actual variable, non-linear system response to frequency deviations. For interconnected power systems, the
AGC control signal is determined from the sum of the tie-line power interchange between interconnected
systems and the system frequency deviation weighted by a bias factor, which is the system response
characteristic approximation. For an isolated power system, such as the NLH system, the control signal relies
entirely on the weighted frequency deviation. Thus the approximation of the SRC becomes increasingly
important in the AGC process of an isolated power system. 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 AGC or Load frequency control LFC system of the power system [14]-[20].
Direct speed governing and the supplemental adjustment of speed governor set points are the
methods used on present day power systems for matching generation to load, for the allocation of generation
output among generation sources, and for the achievement of desired system frequency. This tutorial
provides the reader with basic information on speed governors and their application for system control. All
speed governors, whether mechanical-hydraulic, electrohydraulic, or digital electro-hydraulic, have similar
steady-state speed-output characteristics, so their application for system control (for slow changes) is the
same. A large frequency deviation can have undesirable effects on power system like damaging equipment,
degrading load performance, causing the transmission lines to be overloaded, interfering with system
protection schemes and eventually, leading to an unstable condition for the power system. Thus, controlling
frequency is an essential task for the power system operator. For keeping the frequency of a power system
within a required range, the generation and demand should be kept in balance. In spite of considerable effort
for forecasting electricity demand, making a completely accurate prediction is impossible. Second-to-second
and minute-to-minute fluctuations are very difficult to foresee, which may result in a difference between load
and dispatched generation [21]-[28].
Faster ramping results in more accurate response to the AGC signal and avoids overshooting. On the
other hand, ramping too slowly may cause the resource to work against the needs of the system and impose
the need to commit additional regulation resources. As the current compensation method, which is solely
based on the capacity reserved for regulation, does not acknowledge the greater amount of frequency
regulation service being provided by faster-ramping resources [29]-[33], FERC order forced all RTOs and
ISOs to have a two level payments based on capacity and performance which have to consider the accuracy
in following the AGC dispatch signal. Before deciding to have any additional payment to faster ramping
resources because of their performance and accuracy, we should investigate to see if there is any adverse
effect of very fast response to frequency fluctuations. Based on these effects we can decide about the real
value of these resources. In this paper, we studied these effects by modeling the dynamic behavior of power
system. The rest of the paper is organized as follow. Section 2 describes the economic dispatch and
limitations of prime mover systems. Section 3 introduced a frequency and speed governor control model.
Section 4 introduced AGC model. Simulations results will be discussed in section 5, and the conclusion is
presented in section 6.
2. RESEARCH METHOD
The change in generation in steady state after a load change (due to governor and AGC action), may
not be the most optimal one from an economic standpoint. Note that different generators may have different
cost of generating power. A power plant or system operator may wish to re-adjust the generated power in
various units for maximum economic benefit. This adjustment of generation is generally done manually and
is often called "tertiary control". Of course, how this re-adjustment is done is dependent on generation cost,
power –pricing mechanism and the ownership of generation. Interestingly, if power pricing itself is made a
function of frequency, then tertiary control also may contribute to (slow) frequency control. This idea (called
Availability Based Tariff) is implemented in some regions of our country [34]. Generation reserves available
for control of frequency are typically only a fraction of the existing generation. Moreover, there are practical
constraints like limits on the rate of rise of prime mover power (in a steam turbine) to avoid rapid heating.
While an initial sudden change of about 10% can be tolerated, subsequently, rate of rise is limited to 2% (of
plant MW rating) per minute. The boiler in a steam prime mover is relatively slow in maintaining the steam
pressure by increasing fuel input. Thus as control valves open, restoration of steam pressure is slow. For
some types of hydro turbines, there are forbidden operating zones due to cavitation effects in turbines. In
countries like ours, where substantial generation shortage exists, load shedding may be done to keep
frequency within bounds. In a two-area system, if governors are present on some machines in both areas

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power flow in certain ac line, which connects two areas is to be regulated, and frequency has to be brought
back to its nominal value after any load generation change then the references of at least two governors (one
in each area) in the system should be changed to achieve these objectives [35].
3. FREQUENCY AND SPEED GOVERNOR CONTROL:
In a previous works that frequency deviation can be quite substantial more than 3.0Hz for 10%
change in load. In fact this deviation is considered unacceptably large (at this frequency, the generators will
trip due to over-speeding) [36]. Therefore, depending on the frequency dependence of load, which is quite
weak to bring about load generation balance is not a good operating practice. Therefore it is important to
introduce frequency dependence of generated power. This is done by a speed control mechanism known as
speed governing. Speed dependence can be introduced by having a feedback control system as shown in the
Figure (1). A schematic is oversimplified, especially in the case of thermal/nuclear reactors, which have a
more complicated control structure involving a boiler and reactor [37]. These additional controllers regulate
other parameters like steam pressure by control of fuel, air and feed water. Therefore, strictly speaking,
output power for steam turbines is not a function of control valve position alone. However, we shall use this
simplified model to illustrate the concepts of speed control.
Figure 1. Speed governing feedback control system
The exact nature of generator power frequency steady state relationship can be set by the controller
parameters and Pm0 the initial setting. Typically, in steady state, the generated output power in per unit is
related to change of speed by the following relationship:
( ) ( ) (1)
Where: f0 is the rated frequency in Hz, ω represents the angular electrical speed in rad/s, and kG is the per unit
change in power for per unit change in frequency. If the base value of power is taken to be the generator rated
active power, then reciprocal of kG is also known as the droop. Pm0 is the output when f-fref=0. kG, Pm0 and fref
equivalent ωref can be set by system/plant operators. Normally kG is set after proper co-ordination among
various generators. It is not usually tinkered with during operation. However, Pm0 and fref are adjusted by
system operators or by slow acting automatic controllers to make change in generated power. We have seen
the effect of speed droop settings on sharing of excess load between generators in steady state. Although we
have considered only the steady state conditions, it is to be noted that governors, turbines and generators (and
practically all constituents of a power system) are governed by dynamic equations. This means that steady
state is not reached instantaneously. Indeed, if the transient processes are not stable, the system will not settle
down to the steady state. Thus it is important to consider the dynamical equations which govern the physical
structures, especially the prime mover system. While dynamical modelling of components is beyond the
scope of this studied, we will briefly discuss the working of a steam governor. A speed governor is a device
which senses speed deviation from its reference value and appropriately changes control valve position in a
steam turbine or gate position in a hydraulic turbine. This is achieved in older units using mechanical and
hydraulic arrangements (mechanical hydraulic governors), while in modern units, the sensing and computing
functions are done electrically (electrohydraulic governors). A speed governor should allow us to change the
governor gain and also change the speed and/or load reference. A governor may also have additional
parameters which tailor its dynamic response so that instability does not take place. We study the frequency

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transients for a simplified two generator system with speed governing, by a studied system consider two
identical generators supplying two loads as shown in the Figure (2).
The generator field voltage is controlled to maintain its terminal voltage. A simplified model of
generator is used a voltage source behind an equivalent reactance xg. The load are voltage dependent but not
frequency dependent, and are of unity power factor, and V0=1.0pu.
( ) , and ( )
(2)
A simplified composite transfer function of governor and turbine for both generators and all values are on a
common base as follows:
( ) ( ), (3)
and
Figure 2. Two area studied system model
Assume that for both generators, Pm0i=0.5 and CGi=20, ωrefi=ω0=2π×50. Here, CGi represents the gain of a
proportional speed controller. Note that in steady state:
( ) (4)
Thus CGi is related to the drop of the generator characteristic. The variation in generator speeds if load #1 is
increased by 10%.
( ) (5)
Assume inertia constant of each generator H=3MJ/MVA, xg=0.5, xe=0.2, R=0.02, X=0.2. Initially the voltage
at the load buses #1 and #2 are 1.0 pu. The natural transients associated with the electrical network/loads are
assumed to be fast compared to the electro-mechanical transients; therefore the network and loads are

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represented by their sinusoidal steady state equations. The variation in generator speeds can be obtained by
numerically integrating the swing equations and the dynamical equations corresponding to the speed
governors and turbines. They are:
( )
( ) ( ) (6)
( ) (7)
The dynamical equations of the turbine governor for each generator can be written as follows:
( ( )) (8)
( ) ( ) (9)
Where: ΔPsi is a state of the system. Verify that these yield the transfer function:
( ) ( ) (10)
and ( ̅ ̅ )
Where ̅ and ̅ are the generator terminal voltages and current respectively. These may be obtained by
solving the network in terms of δ1 and δ2. The initial conditions of the various state are as follows: Initial
Conditions:
(11)
There is no power flow initially on the line connecting bus #1 and #2. Thus θ1=θ2 initially. If the initial phase
angle at load bus #1 is taken to be zero, then θ1=θ2=0.0. δ1=19.29o
, δ2=19.29o
. verify that E1=E2=1.0595, so
that the load bus voltages are 1.0 pu.
4. AUTOMATIC GENERATION CONTROL AGC:
We saw the load sharing in a multi-generator power system can be achieved using droop
characteristics of governors. The sharing according to droop is irrespective of load location. However if non-
zero governor droops are used a steady state frequency error will remain which needs to be corrected.
Moreover, since all the governors respond to the load change irrespective of load location, there may be
undesirable exchange of power between different areas of the grid. This is manifested as a change in the
flows of lines interconnecting these areas. To ensure that frequency steady state error is corrected and
generators in a particular area take on the burden of their own load, the load reference Pm0 of governors is
adjusted slowly. This control is also called secondary control. This correction may be done over several
minutes as opposed to 5-10 seconds for initial or primary control action of governors. Thus, while primary
control (governor action) ensures that a large and sudden frequency fall or rise is prevented, secondary
control or AGC ensures that frequency is brought back to the nominal value and inter-area power flow is
regulated. Any change of reference value will lead to a change in sharing among the generators. Thus by
slowly changing the reference of speed governors we can over-ride the sharing which is imposed by the
droop characteristics, and which generators should change their governor references and what the exact value
of these changes.
It is not feasible to independently change more than one governor reference in one area, otherwise
there is no unique value of reference change for different governors. Thus if more than one governors in an
area are on AGC, then their actions have to be in a pre-decided proportion and not independent of one

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another. The AGC concept is illustrated by the following schematic in the Figure 3. Each generator which
has a governor can be represented as follows. The value of the load reference Pm0 is adjusted by AGC. The
following Figure 4 shows how a generator in each area in a two area system receives feedback from a tie line
P12. The feedback is combined with the speed deviation signal in a certain proportion decided by the constant
B. It is then fed to an integral controller, the output of which changes Pm0.
Figure 3. Generator, turbine, and governor model
An integral controller acts on this error to change the load reference of both governors. Since an
integral controller drives its input to zero in steady state, it follows that in steady state:
( ) , ( ) , and (12)
Losses are assumed to be small, ω1=ω2 in steady state and typically ωref=ω0
Then it follows that if B1 and B2 are greater than zero, ω1=ω2=ω0, and , which means
that in steady state, both frequency deviation and tie line power flow deviation are made to go to zero by the
AGC. While any value of the weighting factors which are non-zero gives the same result in steady state, they
are chosen such that the transient response is good. We consider the same two generator, two load system, let
Generator 1 and load at bus 1 be in Area 1 and Generator 2 and load at bus 2 be in area 2. The line between
bus 1 and 2 is the inter-area tie line suppose that the aim of the AGC is to keep interchange between the two
areas via the tie line zero as well as bring the deviation in frequency to zero.
The action of AGC and governor is represented as follows: Generator power is given by: Pmi=Pm0i+ΔPmi,
governor action on both generators causes a change in power ΔPmi as follows:
( ( ) ) ( ) (13)
Where, ΔPm0i represents the change in the load reference due to AGC, which is given by the following
transfer function:
( ( ) ) (14)
( ( ) ) ( ( ) ) (15)

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Figure 4. Measured deviation in power flow on tie line ∆P12 with AGC
The values k1, k2, B1, and B2 are decided based on obtaining good time response no overshoots and
undershoots. Note that , losses are assumed to be small. We now see what happens for a
10% load change at bus 1 by numerical integration of the differential equations. Assume that: B1=B2=20, and
k1=k2=0.01
( ) (16)
( ) (17)
And losses are assumed to be small, ω1=ω2 in steady state and typically ωref=ω0. Therefore: It
follows that if B1 and B2 are nonzero, ω1=ω2= ω0, and ΔP12=0. Please read the notes given on the figure to
understand the behavior of the AGC.
5. RESULTS AND DISCUSSIONS
The results of the numerical integration using a MATLAB/SIMULINK simulation model as shown
in Figure 2. For the step increase in load #1 by 10%, and the effect of a droop CG1=20 and CG2=20 shown in
Figure 5. Also, we discussed the changes in generator speeds, the aggregate movement as well as the relative
motion, power output of both machines, voltages at both load buses, and power flow through the tie line
between buses #1 and #2 for CG1=30 and CG2=10 as shown in Figure 6. The generator with a larger CG takes
on more load. The values of CGi not only determine the sharing, but also the speed of response. Since CGi(1/s)
is infinite in steady state, ωrefi-ωi has to be equal to zero for ΔPmi to be finite. In order words, the droop of this
speed governor characteristic is zero as shown Figure 7. We have discussed in detail the consequences of
having one or more than one generator having droop zero. If generator 1 has the integral speed governor, then
it takes on all the load change as shown in the Figures 5, and 6. However we emphasize the point that it is not
feasible to have integral type speed governors (or equivalently zero droop characteristics) on more than one
generator in the system; non-zero droops on all machines is preferable for load sharing among generators.
Frequency of both generators with 10% increase in Load 1 that after initial drop in speed AGC forces that
frequency to come to 50Hz slowly. Power output of both generators with 10% increase in Load 1 increase
after load change of both generator powers due to governor action. For both generators initially respond and
increase these power due to governor action. However due to AGC generator 1 slowly takes on the complete
burden of the load increase. Change of power flow 1-2 with 10% increase in Load 1 that initially some
benefit of the load increase is shared by generator 2 which increases its power thus power from generator 2
reaches load 1 via that tie line the AGC slowly corrects this deviation and brings back power flow to its old
value zero as shown Figure 8

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(a) Frequency, Hz (b) Power generation, pu.
(a) Load voltages, pu (d) Tie-line Power flow, pu
Figure 5. The variation parameters with load #1 is increased by 10%, and CG1=20 and CG2=20

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(c) Load voltages, pu (d) Tie-line Power flow, pu

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Figure 8. The variation parameters with load #1 is increased by 10%, with the AGC
6. CONCLUSION
Load generation imbalance causes decline or rise in the speeds of synchronous machines connected
in the system. If prime movers deliver a constant power, the equilibrium value of frequency is determined by
the frequency dependence of loads. Since this dependence is weak, the frequency decline or rise due to load-
generation imbalance can be quite high prime mover control is done by making prime mover power a
function of the speed. Then speed governors prevent sudden large rise or fall in speed. The steady state
scheduling of generators based on economic factors is done by changing the load reference of the prime
mover manually. Therefore there is a hierarchy of prime mover controls, operating on three different time
scales which decide the final generator output. In emergency situations wherein large load-generation
imbalance exists generator or load tripping may be required to prevent large frequency changes.
The sharing of extra load by generators is determined by the droop of speed governors. The droop is
related to the steady state proportional gain given to the speed error. Due to proportional gain feature, a
steady state error in frequency will remain when a governor causes a steady state change in prime mover
power. Therefore frequency regulation by a governor is not perfect, but permits a droop so that sharing can
be achieved conveniently. Frequency can be brought back to the nominal value and inter-area power flow can
be regulated by another slow acting control loop which controls prime mover output in a few generators in
each area by using AGC. It is important to note that an AGC is much slower acting than a speed governor

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BIOGRAPHY OF AUTHOR
Youssef A. Mobarak was born in Luxor, Egypt in 1971. He received his B.Sc. and M.Sc.
degrees in Electrical Engineering from Faculty of Energy Engineering, Aswan University,
Egypt, in 1997 and 2001 respectively and Ph.D. from Faculty of Engineering, Cairo University,
Egypt, in 2005. He joined Electrical Engineering Department, Faculty of Energy Engineering,
Aswan University as a Demonstrator, as an Assistant Lecturer, and as an Assistant Professor
during the periods of 1998–2001, 2001–2005, and 2005–2009 respectively. He joined Artificial
Complex Systems, Hiroshima University, Japan as a Researcher 2007–2008. Also, he joined
Faculty of Engineering, King Abdulaziz University, Rabigh, Saudi Arabia as Associate Professor
Position at April 2014 up to date. His research interests are power system planning, operation,
optimization, and techniques applied to power systems. Also, his research interests are wind
energy, and nanotechnology materials via addition nano-scale particles and additives for usage in
industrial field.

Effects of the Droop Speed Governor and Automatic Generation Control AGC on Generator Load Sharing of Power System

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Effects of the Droop Speed Governor and Automatic Generation Control AGC on Generator Load Sharing of Power System