This document discusses control of active power and frequency in electrical power systems. It covers primary speed controls using governor systems to balance generation with load changes. Supplementary controls from central control centers help allocate generation changes. Automatic generation control maintains scheduled interchange between interconnected systems while controlling frequency. Underfrequency load shedding is also discussed to prevent cascading outages if an islanding event causes frequency decline due to insufficient generation.

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CONTROL OF ACTIVE POWER
AND FREQUENCY
Copyright © P. Kundur
This material should not be used without the author's consent

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Active Power and Frequency Control
 The frequency of a system is dependent on active
power balance
 As frequency is a common factor throughout the
system, a change in active power demand at one
point is reflected throughout the system
 Because there are many generators supplying
power into the system, some means must be
provided to allocate change in demand to the
generators
 speed governor on each generating unit provides
primary speed control function
 supplementary control originating at a central
control center allocates generation
 In an interconnected system, with two or more
independently controlled areas, the generation
within each area has to be controlled so as to
maintain scheduled power interchange
 The control of generation and frequency is
commonly known as load frequency control (LFC)
or automatic generation control (AGC)

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Primary Speed Controls
 Isochronous speed governor
 an integral controller resulting in constant speed
 not suitable for multimachine systems; slight
differences in speed settings would cause them
to fight against each other
 can be used only when a generator is supplying
an isolated load or when only one generator in a
system is required to respond to load changes
 Governor with Speed Droop
 speed regulation or droop is provided to assure
proper load sharing
 a proportional controller with a gain of 1/R
 If precent regulation of the units are nearly equal,
change in output of each unit will be nearly
proportional to its rating
 the speed-load characteristic can be adjusted by
changing governor settings; this is achieved in
practice by operating speed-changer motor

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ωr = rotor speed Y = valve/gate position
Pm = mechanical power
Figure 11.7 Response of generating unit with isochronous governor
Figure 11.6 Schematic of an isochronous governor

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Figure 11.8 Governor with steady-state feedback
(a) Block diagram with steady-state feedback
(b) Reduced block diagram
Figure 11.9 Block diagram of a speed governor with droop

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Percent Speed Regulation or Droop
100x
100x
changeoutputpowerpercent
changefrequencyorspeedpercent
RPercent
0
FLNL










where
ωNL = steady-state speed at no load
ωFL = steady-state speed at full load
ω0 = nominal or rated speed
For example, a 5% droop or regulation means that a 5%
frequency deviation causes 100% change in valve position or
power output.
Figure 11.10 Ideal steady-state characteristics of a governor with
speed droop

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Load Sharing by Parallel Units
1
111
R
f
PPP


2
222
R
f
PPP


1
2
2
1
R
R
P
P



Figure 11.12 Response of a generating unit with a governor having
speed-droop characteristics
Figure 11.11 Load sharing by parallel units with drooping
governor characteristics

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Control of Generating Unit Power Output
 Relationship between speed and load can be adjusted
by changing "load reference set point"
 accomplished by operating speed-changer motor
 Effect of load reference control is depicted in Figure
11.14
 three characteristics representing three load
reference settings shown, each with 5% droop
 at 60 Hz, characteristic A results in zero output;
characteristic B results in 50% output;
characteristic C results in 100% output
 Power output at a given speed can be adjusted to any
desired value by controlling load reference
 When two or more units are operating in parallel:
 adjustment of droop establishes proportion of load
picked up when system has sudden changes
 adjustment of load reference determines unit output
at a given frequency

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(b) Reduced block diagram of governor
(a) Schematic diagram of governor and turbine
Figure 11.13 Governor with load reference control
Figure 11.14 Effect of speed-changer setting on governor characteristic

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Composite System Regulating
Characteristics
 System load changes with freq. With a load damping
constant of D, frequency sensitive load change:
 PD = D.  f
 When load is increased, the frequency drops due to
governor droop;
Due to frequency sensitive load, the net reduction in
frequency is not as high.
 As illustrated in Figure 11.17, the composite
regulating characteristic includes prime mover
characteristics and load damping.
An increase of system load by PL (at nominal
frequency) results in
 a generation increase of PG due to governor
action, and
 a load reduction of PD due to load characteristic

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The composite frequency response characteristic β is normally
expressed in MW/Hz. It is also sometimes referred to as the stiffness
of the system.
The composite regulating characteristic of the system is equal to 1/β
 
DR
P
DRRR
P
f
eq
L
n
L
SS






1
111 21
where
D
Rf
P
RRR
R
eqSS
L
neq
eq






1
111
1
2

Figure 11.17 Composite governor and load characteristic

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Supplementary Control of Isolated
Systems
 With primary speed control, the only way a change
in generation can occur is for a frequency deviation
to exist.
 Restoration of frequency to rated value requires
manipulation of the speed/load reference (speed
changer motor).
 This is achieved through supplementary control as
shown in Figure 11.22
 the integral action of the control ensures zero
frequency deviation and thus matches generation
and load
 the speed/load references can be selected so that
generation distribution among units minimizes
operating costs
 Supplementary control acts more slowly than
primary control.
This time-scale separation important for satisfactory
performance.

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Figure 11.22 Addition of integral control on generating units
selected for AGC

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Supplementary Control of Interconnected
Systems
 The objectives of automatic generation control are
to maintain:
 system frequency within desired limits
 area interchange power at scheduled levels
 correct time (integrated frequency)
 This is accomplished by using a control signal for
each area referred to as area control error (ACE),
made up of:
 tie line flow deviation, plus
 frequency deviation weighted by a bias factor
Figure 11.27 illustrated calculation of ACE
 Bias factor, B, set nearly equal to regulation
characteristic (I/R + D) of the area; gives good
dynamic performance
 A secondary function of AGC is to allocate
generation economically

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Figure 11.27 AGC control logic for each area

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Figure 11.28 Functional diagram of a typical AGC system

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Underfrequency Load Shedding
 Severe system disturbances can result in cascading
outages and isolation of areas, causing formation of
islands
 If an islanded area is undergenerated, it will experience
a frequency decline
 unless sufficient spinning generation reserve is
available, the frequency decline will be determined by
load characteristics (Fig. 11.30)
 Frequency decline could lead to tripping of steam
turbine generating units by protective relays
 this will aggravate the situation further
 There are two main problems associated with
underfrequency operation related to thermal units:
 vibratory stress on long low-pressure turbine blades;
operation below 58.5 Hz severely restricted (Fig. 9.40)
 performance of plant auxiliaries driven by induction
motors; below 57 Hz plant capability may be severely
reduced or units may be tripped off

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Fig. 11.30 Frequency decay due to generation deficiency (L)
Fig. 9.40 Steam turbine partial or full-load operating limitations during
abnormal frequency, representing composite worst-case limitations of five
manufacturers ©ANSI/IEEE-1987

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Underfrequency Load Shedding (cont'd)
 To prevent extended operation of separated areas at low
frequency, load shedding schemes are employed.
A typical scheme:
 10% load shed when frequency drops to 59.2 Hz
 15% additional load shed when frequency drops to 58.8 Hz
 20% additional load shed when frequency reaches 58.0 Hz
 A scheme based on frequency alone is generally acceptable
for generation deficiency up to 25%
 For greater generation deficiencies, a scheme taking into
account both frequency drop and rate-of-change of
frequency provides increased selectivity
 Ontario Hydro uses such a frequency trend relay
Fig. 11.31 Tripping logic for frequency trend relay