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Coordination of generator protection with generator excitation control and

generator capability

Conference Paper · June 2008

DOI: 10.1109/ICPS.2008.4606278 · Source: IEEE Xplore

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 Copyright © [2007] IEEE. Reprinted from IEEE Power Engineering Society General Meeting, 2007, Paper No. 1-4244-1298-6/07

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COORDINATION OF GENERATOR
PROTECTION WITH GENERATOR
EXCITATION CONTROL AND
GENERATOR CAPABILITY
Working Group J-5 of the Rotating Machinery Subcommittee,
Power System Relay Committee

Chairperson: Charles J. Mozina Vice Chairperson: Michael Reichard

Members: Z. Bukhala S. Conrad, T. Crawley, J. Gardell, R. Hamilton, I. Hasenwinkle, D. Herbst, L.

Henriksen, G. Johnson, P. Kerrigan, S. Khan, G. Kobet, P. Kumar, S. Patel, B. Nelson, D. Sevcik, M.
Thompson, J. Uchiyama, S. Usman, P. Waudby, M. Yalla

 The need to improve coordination between generator

Abstract-- This paper was written by a Working Group of the protection and control has come to light after recent
IEEE Power System Relay Committee to provide guidance to the misoperation of generator protection during major system
industry to better coordinate generator protection with generator disturbances. Two significant disturbances are the 1996
control. The paper discusses specific calculation methods that can western area disturbances and 2003 east coast blackout.
be used to insure generator protection and excitation system
control are fully coordinated. It also specifically addresses the
coordination of relays with generator full load capability and Because of these disturbances, NERC (North American
machine steady state stability limits. Because of recent blackouts, Electric Reliability Council) is asking users to verify
NERC (North American Electric Reliability Council) is coordination of generator protection and control [1-3]. This
developing standards [1-3] for the coordination of generator paper provides practical guidance for providing this
protection and control. This paper provides practical guidance on coordination in the following specific protection areas:
providing this coordination.
· Generator Capability Curve Coordination
Index Terms-- Automatic Voltage Regulator (AVR), NERC · Underexcited setting coordination with generator loss-of-
(North American Electric Reliability Council), Over Excitation field (40) protection
Limiter (OEL), Under Excitation Limiter (UEL), Steady State ·Overexcited setting coordination with generator
Stability Limit (SSSL), MW-Mvar (P-Q) Diagram, Resistance- impedance (21) backup protection
Reactance (R-X) Diagram
· AVR Coordination - Underexcited Operation
· Coordination of the Under Excitation Limiter (UEL) with
I. INTRODUCTION loss-of-field protection and Steady State Stability Limits
· AVR Coordination – Overexcitation Operation
The need to coordinate generator protection with generator · Coordination of AVR V/Hz limiter with overexcitation
control and load capability has been well known to generator (V/Hz) protection
protection engineers. The techniques, method and practices to
provide this coordination are well established but scattered in
various textbooks, papers and in relay manufacturer’s II. GENERAL DISCUSSION OF GENERATOR
literature. In many cases these techniques, methods and CAPABILITY AND EXCITATION CONTROL
practices are not well known to the practicing generator
protection engineers. The purpose of this paper is to provide a A. Excitation Control Basics
single document that can be used to address coordination of
generator protection with generator control. The paper uses The excitation system of a generator provides the energy for
example calculations as its means of communicating these the magnetic field (satisfying magnetizing reactance) that
methods. This paper also discusses steady state stability and its keeps the generator in synchronism with the power system. In
impact on setting generator protection. addition to maintaining the synchronism of the generator, the
excitation system also affects the amount of reactive power
that the generator may absorb or produce. Increasing the

1
 2

excitation current will increase the reactive power output. θs = Voltage Angle at System
Decreasing the excitation will have the opposite effect, and in
extreme cases, may result in loss of synchronism of the Pmax = Eg Es
generator with the power system. If the generator is operating Max. Power X
Transfer
isolated from the power system, and there are no other reactive Max.
power sources controlling terminal voltage, increasing the Power All Lines
All lines in
service
Transfer in Service
level of excitation current will increase the generator terminal
voltage and vice versa.
Line
Line 11
tripped
Tripped
The most commonly used voltage control mode for
generators of significant size that are connected to a power
Pe Pe Line 2
system is the AVR (Automatic Voltage Regulator) mode. In Line 2
Tripped
tripped

this mode the excitation system helps to maintain power

system voltage within acceptable limits by supplying or
absorbing reactive power as required. In disturbances where
short circuits depress the system voltage, electrical power 0
0 20 40 60 80 100 120 140 160 180 200
cannot fully be delivered to the transmission system. Fast 0 90og - s 1800
response of the excitation system help to increase the 0g - 0s
synchronizing torque to allow the generator to remain in
synchronism with the system. After the short circuit has been Fig. 1 Power Angle Analysis - Steady State Instability
cleared, the resulting oscillations of the generator rotor speed
with respect to the system frequency will cause the terminal From the power transfer equation above it can be seen that the
voltage to fluctuate above and below the AVR set point. maximum power (Pmax) that can be transmitted is when θ g-θ s
0 0
Excitation controls are called upon to prevent the AVR from = 90 i.e. sin 90 = 1. When the voltage phase angle between
0
imposing unacceptable conditions upon the generator. These local and remote generation increases beyond 90 the power
controls are the maximum and minimum excitation limiters. that can be transmitted is reduced and the system becomes
The overexcitation limiter (OEL) prevents the AVR from unstable and usually splits apart into islands. If enough lines
trying to supply more excitation current than the excitation are tripped between the load center and remote generation
system can supply or the generator field can withstand. The supplying the load center the reactance (X) between these two
OEL must limit excitation current before the generator field sources increases to a point where the maximum power
overload protection operates. The under excitation limiter (Pmax), which can be transferred, is insufficient to maintain
(UEL) prevents the AVR from reducing excitation to such a synchronism. The power angle curve in Fig. 1 illustrates this
low level that the generator is in danger of losing synchronism, reduction as line 1 trips the height of the power angle curve
exceeding machine under-excited capability, or tripping due to and maximum power transfer is reduced because the reactance
exceeding the loss of excitation protection setting. The UEL (X) has increased. When line 2 trips the height of the power
must prevent reduction of field current to a level where the angle curve is reduced further to the point where the power
generator loss-of-field protection may operate. being transferred cannot be maintained and the unit goes
unstable. During unstable conditions generators may slip poles
B. Generator Steady State Stability Basics and lose synchronism. Voltage collapse and steady state
instability can occur together as transmission lines tripping
Steady state instability occurs when there are too few increase the reactance between the load center and remote
transmission lines to transport power from the generating generation. A graphical method can be used to estimate the
source to the load center. Loss of transmission lines into the steady state stability limit for a specific generator. This method
load center can result in steady state instability. Fig.1 is discussed in Section IV of this paper.
illustrates how steady state instability occurs for a simplified
system with no losses. The ability to transfer real (MW) power C. Generator Watt/var Capability
is described by the power transfer equation below and is
plotted graphically in Fig. 1. A typical cylindrical rotor generator capability curve is
shown in Fig. 2. The capability curve establishes the steady
Pe = Eg Es Sin ( θg- θs ) state (continuous) generator operating limits. The generator
X capability curve is normally published at generator rated
voltage. Salient pole generators have a slightly different
Where: Eg = Voltage at Generation characteristic in the underexcited region. The curve also shows
Es = Voltage at System how the AVR control limits steady state operation to within
Pe = Electrical Real Power Transfer generator capabilities. The generator capability (Fig.2) is a
X = Steady State Reactance Between Generator and composite of three different curves: the stator winding limit,
System the rotor heating limit and the stator end iron limit. The stator
θg = Voltage Angle at Generation

2
 3

winding limit is a long-term condition relative to the generator voltage bus minimum and maximum voltage during peak and
winding current carrying capability. light load conditions. The high and low voltage limits for the
Reactive Power Rotor MW
auxiliary bus, generator terminal and system buses are
Winding G System
into System interrelated by the tap position selected for the generator step
Limited Mvar Normal Overexcited
+ up transformer and the unit auxiliary transformer.
Mvar Operation
Consequently, as power system operating change, it is
Overexcited Stator
Overexcitation Winding necessary to check tap setting to ascertain that adequate
Limiter (OEL )
Limited reactive power is available to meet power system need under
emergency conditions.
+ MW
0 Real Power
into System
D. P-Q to R-X Conversion
Under
Excitation

Underexcited
Limiter Both Figures 2 and 3 illustrate the capability of a generator on
(UEL)
- Underexcited a MW-Mvar (P-Q) diagram. This information is commonly
Mvar Operation
MW available from all generator manufactures. Protection functions
G System
Steady State for the generator, such as loss-of-field (40) and system backup
Reactive Power Stator End Stability Limit Mvar
into Generator Iron Limited distance (21) relaying measure impedance, thus these relay
characteristics are typically displayed on a Resistance-
Reactance (R-X) diagram. To coordinate the generator
Fig 2. Typical Generator Capability Curve and Operating Limits capability with these impedance relays, it is necessary to either
for a cylindrical rotor generator convert the capability curve and excitation limiters (UEL and
OEL) to an R-X plot or to convert impedance relay settings to
The rotor winding limit is relative to the rotor’s current
a MW-Mvar plot. Figure 3 illustrates this conversion [4]. The
carrying capability. It is also associated with longer time
CT and VT ratios (Rc/Rv) convert primary ohms to secondary
conditions. The stator end iron limit is a relatively short time
quantities that are set within the relay and kV is the rated
condition, caused by a reduction in the field current to the
voltage of the generator.
point where a significant portion of the excitation is being
supplied from the system to the generator. Significant
underexcitation of the generator causes the rotor retaining ring
to become saturated. The eddy currents produced by the flux
cause localized heating. Hydrogen cooled generators have
multiple capability curves to reflect the effect of operating at
different H2 pressures.

The generator excitation control limiters are intended to limit

operation of the generator to within its continuous capabilities.
Fig 2 illustrates how these limiter setpoints can be plotted on a
typical generator capability curve. Generally, the setting of the
UEL control will also coordinated with the steady-state
stability limit of the generator which is a function of the
generator impedance, system impedance and generator
terminal voltage. This section of the paper discusses steady
state stator stability in general terms. The next sections of this MVA = kV2 ( Rc )
Z Rv
paper will outline a conservative graphical method for
estimating the steady state stability limit for a generator as well
as a specific example.

The overexcitation control (OEL) limits generator operating in

the overexcited region to within the generator capabilities
curve. Some users set the OEL just over the machine
capability curve to allow full machine capability and to
account for equipment tolerances, while others set it just under
the capability curve as shown in Fig 2.

Engineers should be aware that more restrictive limits of

generator capability could be imposed by the power plant
auxiliary bus voltage limits (typically +/- 5%), the generator
Fig. 3 Transformation from MW- Mvar to R-X and
terminal voltage limits (+/-5%), and the system generator high
R-X to MW-Mvar Plot

3
 4

S y s te m Im p e d a n c e s :
P o w e r S y s te m M in .= s tr o n g e s t lin e o u t o f s e rv ic e
M a x .= a ll lin e s in s e r v ic e
Z M in S 1 = 0 .0 0 1 0 5 + j0 .0 1 6 4 6 3 p u o n 1 0 0 M V A b a s e
Im p e d a n c e o f th e lo n g e s t tra n s m is s io n lin e
Z L L 1 = 0 .0 1 0 9 5 + j0 .1 1 5 4 6 p u o n 1 0 0 M V A b a s e Z m a x s 1 = 0 .0 0 0 5 1 1 + j0 .0 1 0 0 3 3 p u o n 1 0 0 M V A b a s e

145kV U n it T r a n s fo r m e r
19 kV
Im p e d a n c e o f s h o r te s t tr a n s m is s io n lin e
Z S L 1 = 0 .0 0 5 4 6 + j0 .0 5 7 7 3 p u o n 1 0 0 M V A b a s e
X T = 0 .1 1 1 1 p u o n 4 2 5 M V A b a s e

2 0 ,0 0 0 V
VT 120V A u x . T ra n s fo rm e r
CT 1 8 0 0 0 /5 A

492 M V A B ase
X d = 1 .1 8 8 8 p u
X ' d = 0 .2 0 5 7 7 p u
X " d = 0 .1 7 8 4 7 p u 1 8 0 0 0 /5 A
X 2 = 0 .1 7 6 7 6 p u CT

14400 1 .2 5 O h m s
2 4 0 /1 2 0 V

Fig.4 One line diagram with generator and power system data for example generator

III. BASIC MACHINE AND SYSTEM DATA FOR 400 Mvar

60 PSIG
EXAMPLE CALCULATION
45 PSIG

A 492 Mva, 20kV direct cooled cylindrical rotor steam 300 0.77 LAG

turbine rated at 14202A, 0.77PF has been selected as the

sample generator to demonstrate the calculation methods 492 MVA 20 kV
to provide coordination of generator AVR control, machine 200 3600 RPM 0.77 PF 0 .90 LAG
Hydrogen - Water
capability and steady state stability limit with relay Cooled
protection. Fig. 4 shows the basic one line diagram as well
as machine and system impedance data that are required for 100 O. 98 LAG

the example calculations. The unit transformer in this

example is 425MVA, Y-grounded/delta whose tap are set at
145/19kV. Fig 5 shows the generator capability curve for 0
400 500
the example machine. Key symbols used in calculation are 100 200 300

MW
defined in Appendix I.
100 0.95 LEAD
IV. AVR COORDINATION- UNDEREXCITED
OPERATION
200
Excitation systems seldom operate at the extremes of
their capabilities until the system voltage attempts to rise or
fall outside its normal operating range. During voltage
300
transients, excitation controls allow short-term operation of
Fig 5 Generator Capability Curve for Example Generator
the excitation system and generator beyond the rated steady
state limits. The excitation system controls and protective
relays must coordinate with regard to both pickup
relay (see Section V) plus the characteristics of the under
magnitudes as well as time delays.
excitation limiter itself. These characteristics vary with each
generator and system configuration. The automatic voltage
The setting of the under excitation limiter takes into
regulator uses the generator terminal voltage and phase
consideration the generator capability curve and the setting
current to calculate the existing operating conditions. By
of the loss-of-field
comparing the actual point of operation to the desired limit,

4
 5

the regulator determines when it is appropriate to adjust the A. Steady State Stability Limit (SSSL) - Graphical Method
generator field current in order to remain within the desired
operating conditions. Alternatively, discrete relays have The steady state stability limit (See Section II) reflects the
also been applied to motor operated rheostat excitation ability of the generator to adjust for gradual load changes.
systems. These relays operate similarly to the above The steady state stability limit is a function of the generator
automatic regulator function, measuring generator voltage voltage and the impedances of the generator, step-up
and current to determine the actual operating condition, and transformer and system. This method assumes field
then initiating a control signal when the limit setting is excitation remains constant (no AVR) and is conservative.
exceeded. It should be noted that the limit settings can NERC explicitly requires that generators operate under
change with voltage. Some limiters change as the square of AVR control, which improves the stability limit. When
the voltage (90% voltage results in 81% of the setting), making the calculations, all impedances should be
while others are proportional with the voltage (90% voltage converted to the same MVA base, usually the generator
results in 90% of the setting). Still other limiters may not base. The steady state stability limit is a circle defined by
change with voltage at all. To assure proper operation for the equations shown in Fig. 6 below [4]:
all conditions, the specific voltage variation characteristic
should be identified when setting the limiter. Manual
Generator GSU System
regulators do not have under excitation limiters as an active Reactance
component. The process for establishing the
underexcitation limit and checking the coordination is as
follows:
G XS
Where
XT
1. Obtain the generator capability curve. Xd Xe=XT + XS
V

2. Obtain the step-up transformer impedance (X T),

Per Unit
generator synchronous (Xd) and transient reactance Mvar
(Xd’).

3. Determine the equivalent system impedance typically

with the strongest source out-of-service.
V2 1_ + 1
V2 1 1 2 Xe Xd
4. Calculate the steady state stability limit and plot on the 2 Xe Xd
generator capability curve.

5. Calculate the loss-of-field relay setting and plot on the

Per Unit MW
generator capability curve. This setting should be
adjusted, depending upon the steady state stability
curve and the generator capability curve (see Section
V). MW - Mvar PER UNIT PLOT

6. Determine the most limiting condition(s), considering

X
the generator capability curve, the steady state stability
curve and the loss-of-field relay characteristic.
Xe
7. Determine the under excitation limiter setting.
Xd - Xe R
8. Verify that the impedance loci do not swing into the 2
relay impedance characteristic, causing a false trip for Xd + Xe
a stable system transient. This generally requires 2
transient stability studies.

9. Determine the time delay, based upon the excitation

system time constants and the characteristics of the
system swings. Verify the coordination between the under R-X DIAGRAM PLOT
excitation limiter setting and the loss-of-field relay
settings. Fig. 6 Graphical Method for Steady State Stability

5
 6

Where Xd = generator synchronous reactance 19 2

Xs = equivalent system reactance X min SG  2 * 0.07338 0.06621 pu
Xe = the sum system and step-up transformer 20
reactance (Xs +XT )
V = generator terminal voltage 4. To calculate the steady state stability limit on a P-Q
diagram use the equations in Fig 6. Xe=XTG + Xmin SG1 =
The graphical method shown in Fig. 6 is widely used in 0.11607pu+0.06621pu =0.18238 pu. The generator
the industry to display the steady state stability limit on P- synchronous impedance, Xd, is 1.18878 pu (see Fig.4).
Q and R-X diagrams. The generator cannot be operated
beyond the steady state stability limit. It should be noted Center = V2 1 - 1 = 1 1 - 1
that the weaker the transmission system, the smaller the 2 Xe Xd 2 0.1824 1.18878
circle radius. Often times, the system reactance model will
consist of the normal system without the single strongest = 2.31pu of 492 MVA or 1142 MVA
line from the external system. This provides a setting still
valid for any line out of- service. In most cases, the steady Radius = V2 1 + 1 = 1 1 + 1
state stability limit is outside the generator capability 2 Xe Xd 2 0.1824 1.18878
curve, and does not restrict generator operation.
= 3.162pu of 492 MVA or 1556 MVA
B. Steady State Stability Limit (SSSL) Calculation
Example and UEL Setting.
Using the equations for the center and the radius in Fig. 6.
the center is at 1142 on the positive Mvar axis, and the
1. Generator and system data are shown in Fig. 4 and the
radius is 1556MVA. The intercept point on the negative
generator capability curve in Fig. 5.
Mvar axis is at –414Mvar (1556-1142). The P-Q plot is
shown below in Fig. 7. Fig. 7 also shows the UEL and
2. The step-up transformer reactance is given as 0.1111 pu
generator capability (GCC) on the P-Q plot.
on a 425 MVA base. The generator synchronous reactance
is 1.18878 pu on a 492 MVA base. The generator transient
reactance is 0.20577 pu. The transformer impedance on the
generator base is 0.11607 pu as calculated below:

2
MVAG kVTlow
X TG  * * XT
MVAT kVS2
492 19 2
X TG  * * 0.111 0.11607
425 20 2

3. The system impedance (with the strongest source out of

service) is XminS1 = j0.016463 pu on a 100 MVA base. The
system voltage base is 138kV, which is different than the
transformer’s 145kV high side tap. Therefore to account for
the difference in the voltages, the impedance has to be
adjusted as the square of the voltages (1382/1452) as shown
below:

MVAG kV S2
X min ST 1  * 2 * X minS 1
MVAS kVThigh
492 1382
X min ST 1  * * 0.016463 0.07338 pu
100 1452 Fig.7 Generator Capability (GCC), Underexcitation Limiter (UEL) and
Steady State Stability Limit (SSSL) for Example Generator – P-Q Plot

The impedance then must be converted from the

5. From Fig. 2, generally the stator end iron limit on the
transformer voltage base to the generator voltage base.
generator capability curve is the most limiting condition,
2
compared to the steady state stability limit or the loss-of-
kVTlow
X min SG  * X min ST 1 field relay characteristic.
kV G2
6
 7

6. The under excitation limiter (UEL) should be set to relay approach is widely used within the industry to provide
operate prior to reaching the stator end iron limit. high-speed detection. There are two basic designs of this
Assuming that the plant operates between H2 pressures type of protection.
of 45psig and 60psig, use a margin of 10% of the
leading Mvar limit (machine end turn limit or steady The first method (Scheme 1 –Fig.8) consists of two
state stability limit, whichever is most limiting) at offset Mho units. An impedance circle diameter equal to the
various MW points. The example limiter has three set generator synchronous reactance and offset downward by ½
points, one on the negative var axis, one on the positive of the generator transient reactance is used for the Zone 2
Watt axis, and one defined with both a Watt and var distance element. The operation of this element is delayed
point. All points are expressed as per unit on the approximately 30-45 cycles to prevent misoperation during
generator MVA base. They should be selected to allow a stable transient swing. A second relay zone, set at an
the greatest range of generator operation as possible. impedance diameter of 1.0 per unit (on the generator base),
The points (vars pu, Watts pu) will be (0.45, 0), (0.27, with the same offset of ½ of the generator transient
0.81) and (0, 1.12). They are plotted on Fig. 7 in Mvar reactance is used also. This Zone 1 element has a few
and Mw values using the 492 MVA base. cycles of delay and more quickly detects severe
underexcitation conditions. When synchronous reactance is
7. The under excitation limiter time delay should be less than or equal to 1.0 per unit (e.g. hydro generators)
minimal. Some limiters do not have an intentional only the Zone 2 is used and is set with the diameter equal to
delay, but utilize a damping setting or circuit to 1.0 per unit.
stabilize the limiter output. In addition, there may be a
setting to proportionally increase the limiter output, The second relaying method (Scheme 2 – Fig.10) consists
dependant upon the severity of the underexcitation of an undervoltage unit, an impedance unit and a directional
condition (increased output for a more severe unit. In this case the generator synchronous and transient
condition). The limiter manufacturer should be reactances are used to determine the settings. As with the
consulted for these parameters. first scheme, two elements are used, one without significant
delay (typically 0.25 second for the most severe condition)
V. GENERATOR LOSS OF FIELD COORDINATION and the other delayed to prevent misoperation. For both
schemes the relay settings are based on ct and vt secondary
To limit system voltage the generators may have to quantities, thus the impedances need to be calculated on the
operate underexcited and absorb Vars from the power ct and vt secondary basis.
system. It is important that the generator be able to do so
within its capabilities as defined by the generator capability A. Loss of Field Calculation Example
curve. The generator under excitation limiter (UEL) must
be set to maintain operation within the capability curve as Scheme1: In this example, two mho characteristics are
show in Fig. 2. The loss of field relay must be set to allow used. Standard settings for this two zone loss-of-field
the generator to operate within its underexcited capability. scheme are shown below in Fig.8.

Partial or total loss of field on a synchronous generator is

detrimental to both the generator and the power system to Heavy Load Light Load
- Xd’
which it is connected. The condition must be quickly 2
-R +R
detected and the generator isolated from the system to avoid
generator damage. A loss of field condition, which is not Impedance Locus
detected, can have a devastating impact on the power 1.0 pu During Loss of Field
Zone 1
system by causing both a loss of reactive power support as Xd
well as creating a substantial reactive power drain. This
reactive drain, when the field is lost on a large generator, Zone 2
can cause a substantial system voltage dip.
When the generator loses its field, it operates as an
induction generator, causing the rotor temperature to
rapidly increase due to the slip induced eddy currents in the
rotor iron. The high reactive current drawn by the generator
from the power system can overload the stator windings.
These hazards are in addition to the previously mentioned
stator end-iron damage limit. -X
Fig. 8 Loss-of-Field R-X Diagram -- Scheme 1
The most widely applied method for detecting a generator
loss of field condition on major generators is the use of
distance relays to sense the variation of impedance as
viewed from the generator terminals. A two-zone distance
7
 8

The zone 2 element is set at a diameter of Xd or 1.18878

10. 0 jX
pu and the Zone1 diameter would be set at 1.0 pu on the
generator base. Both units are offset by X’d/2.The
generator data is shown in Fig.4.The formula to convert the 5. 0

generator impedances (which are in pu) to relay secondary R

ohm is shown below: 0. 0
-20. 0 -15. 0 -10. 0 -5. 0 0. 0 5. 0 10. 0 15. 0 20. 0 25. 0 30. 0

kV 2 * X PU RC
X sec  * -5. 0

MVA RV
Where: Xsec = Relay Secondary Ohms -10. 0

kV = Generator Rated Voltage

SSSL GCC UE L
Xpu = pu Reactance -15. 0

MVA = Generator Rated MVA ZONE 1

Rc = CT ratio -20. 0

Rv = VT ratio
Zone 1 ZONE 2
-25. 0
Diameter of the circle is set at 1.0 pu or 17.56 Ω
UEL
'
Offset of the circle X d /2 is 0.20577/2 pu or -1.8067 Ω -30. 0 GCC
Time delay: A short time delay of approximately 3 to 5 ZONE2
cycles is suggested to prevent misoperation during -35. 0
ZONE1
switching transients.
SSSL
-40. 0

Zone-2
Diameter of the mho circle is set at X d = 1.1888 pu or Fig 9 Loss-of- Field, Scheme 1, R-X Plot
20.88 Ω.Offset of the mho circle is set the same as for
Zone 1 or -1.8067 Ω Scheme2: This scheme also uses both Zone 1 and Zone 2
elements. Standard settings for this two zone loss-of-field
Time delay: A minimum time delay of 30 to 45 cycles is scheme are shown below in Fig.10:
typically used to prevent relay misoperation during stable
power swing conditions. In cases where only one mho +X
element is used, the methodology for Zone 2 above is
Heavy Load Light Load
typically employed.
XTG +Xmin SG1
-R
Zone 2 - Xd’ Directional +R
Fig. 9 shows the loss of field relay characteristics along
2 Element
with generator capability curve (GCC), the under excitation
limiter (UEL), and the steady state stability limit (SSSL)
plotted on the R-X plane. The GCC, UEL curves are Zone 1
Impedance Locus
converted from P-Q plane to R-X plane using the 1.1Xd During Loss of Field
calculation method described in Fig.3.

-X

Fig. 10 Loss -of-Field R-X Diagram -- Scheme 2

Scheme 2 uses a combination of two impedance elements, a

directional unit and an undervoltage unit applied at the
generator terminals. The Zone 2 element is set to coordinate
with the Steady State Stability Limit. The top of the Zone 2
circle (positive offset) is set at the system impedance in
front of the generator. Typically, this will be the generator
8
 9

transformer reactance XTG + XminSG1 . XminSG1 is the weak Zone 2 Delay: Set the Zone 2 delay long enough that
source (with the strongest line out of service) system corrective action may take place to restore excitation before
impedance on the generator base. The transformer and the unit goes unstable. Settings of 1 second to 1 minute are
system impedance must be put on the same base as the appropriate. Since two zones are used, the delay will be set
generator. The negative reach is set to at least 110% of Xd to 10 sec.
to encompass the SSSL with margin. The negative reach of
Zone 1 element is then set to match. The negative offset of Phase Undervoltage Element: An under-excitation
Zone 1 element is set to X’d/2 to establish the top of the condition accompanied by low system voltage caused by
circle. the system's inability to supply sufficient Vars will cause
the unit to go unstable more quickly. For this condition, an
Since the Zone 2 element has a positive offset it is undervoltage unit is used to bypass the Zone 2 time delay
supervised by a directional element (DE) to prevent pickup for low system voltage. The drop out of the undervoltage
for system or unit transformer faults. The directional unit is typically set at 0.8 pu which will cause accelerated
element is typically set at an angle of between 10 and 20 Zone 2 tripping with a time delay of 0.25 sec.
degrees. This unit is usually set at 13 o. The Zone 2 time
delay is typically set at 10 sec. to 1 minute. A loss of field Zone-1
condition is generally accompanied by low generator
terminal voltage. For this condition an undervoltage relay is Zone 1 Diameter: Set to same negative reach as Zone 2 of
used to reduce the Zone 2 time delay. The drop out of the X’d/2.
undervoltage unit is typically set at 0.80-0.87 pu which will
cause accelerated Zone 2 tripping with a time to 0.3-0.2 Diameter of the circle in pu:
X'
sec. Transient stability studies can be used to refine the
Z1Diameter 1.25 * X d  d
voltage supervision and time delay settings. 2
0.20577
Zone-2 Z1Diameter 1.25 *1.1888 
2
Diameter is typically set to 1.1 times X d plus the weak Z1Diameter 1.3831 or 24.3 Ω
system source and step-up transformer impedances .The
Zone 1 offset: Set to one half of the generator transient
110% multiplier on X d provides a margin to pickup
reactance.
before reaching the steady state stability limit. In this
X'
application, there is a large separation between the SSSL Z1Offset  d
and the GCC. In order to provide better protection for 2
under-excited operation of the unit, the margin can be set to 0.20577
125%, which moves the characteristic to approximately half Z1Offset 
way between the SSSL and the GCC curves.
2
Z 2 Offset 0.102885 or –1.806 Ω
Diameter of the circle in pu:
Z 2Diameter 1.25 * X d X TG X minSG Fig. 11 shows the loss of field relay characteristic for
Z 2 Diameter 1.25 * 1.1888 0.1161 0.0662 Scheme 2 with the generator capability curve (GCC), the
under excitation limiter (UEL) and steady state stability
Z 2 Diameter 1.6683 or 29.3 Ω limit (SSSL).

Zone 2 Offset: Set the Zone 2 offset to the system source

impedance (Reactance) as seen from the terminals of the
unit.

Z 2Offset X TG X min SG
Z 2 Offset 0.1161 0.0662
Z 2 Offset 0.1823 or 3.2 Ω

Zone 2 Directional Supervision: Since the Zone 2 element

has a positive offset; it is supervised by a directional
element (DE) to prevent pickup of the element for system
or unit transformer faults. Set the directional element to 13
degrees.

9
 10

when the generator is subjected to low system voltage.

10.0
jX
Note that the impedance is reduced by the square of the
DIR ELEMENT
voltage. System voltage under emergency conditions
5.0

can reduce to planned levels of 90 to 95 percent of

R nominal ratings [5]. Utility transmission planners
0.0
-20.0 -15.0 -10.0 -5.0 0.0 5.0 10.0 15.0 20.0 25.0 30.0
should be consulted for worst case emergency voltage
ZONE -5.0
levels at power plants.

ZONE1
-10.0
Distance relays with a mho characteristic and one or two
zones are commonly used for phase fault backup. If only
-15.0
GC UEL
one zone is used its setting is based on the Zone 2 criteria
outlined below. Setting generator backup protection with
-20.0
SSSL adequate margin over load and stable power swings is an art
as well as a science. The suggested criteria below provide
-25.0
reasonable settings that can be verified for security using
UEL
GCC
transient stability computer studies.
-30.0 ZONE2
DIR The Zone 1 relay element is set to the smaller of two
ZONE1
-35.0 conditions:
SSSL

-40.0 1. 120% of the unit transformer impedance.

2. Set to respond to faults 80% of the Zone 1 setting of
the shortest transmission line exiting the power plant
Fig 11 Loss-of- Field, Scheme 2, R-X Plot (neglecting in-feeds) plus step-up transformer
impedance. Some users apply Zone 1 as a backup to
generator bus work and GSU protection with typical
VI. GENERATOR PHASE BACKUP (21) settings of 50-80% of the GSU impedance.
COORDINATION
A time delay of approximately 0.5 seconds gives the
The primary purpose of the phase distance (21) relay is to primary protection (generator differential, transformer
protect the generator from supplying prolonged fault differential and overall differential) enough time to operate
current to fault on the power system to which the generator before the generator backup function. Stability studies may
is connected. A mho characteristic is commonly used to be required to insure that Zone 1 unit does not trip for
detect system phase faults and to separate the generator stable power swings.
after a set time delay. The relay’s impedance reach and time
delay settings must be coordinated with transmission system The Zone 2 relay element is typically set at the smaller of
primary and backup protection to allow selectivity. the three following criteria:
Typically, the phase distance relay’s reach begins at the
voltage input to the relay and extends the length of the 1. 120% of the longest line with in-feeds.
longest line out of the transmission substation. Some factors 2. 50 to 67% of the generator load impedance (Zload ) at
involving the settings are as follows: the rated power factor angle (RPFA) of the generator.
This provides a 150 to 200% margin over generator
1. In-feeds: Apparent impedance due to in-feeds will full load. This is typically the limiting criteria.
require larger reaches; however, settings to cover long 3. 80 to 90 % of generator load impedance at the
lines may overreach adjacent short lines. maximum torque angle of the Zone 2 impedance relay
2. Transmission System Protection: If the transmission setting (typically 850).
lines exiting the power plant have proper primary and 4. Time delay to coordinate with transmission system
backup protection as well as local breaker failure the backup protection and local breaker failure.
need to set the 21 relay to respond to faults at the end
of the longest lines is mitigated. A. Zone 1 Setting Example
3. Load Impedance: Settings should be checked to
2
ensure the maximum load impedance (Zmax/Load =kV / Set zone 1 using the smaller of the two criteria:
MVA at rated power factor angle (RPFA) does not
encroach into the reach. A typical margin of 150-200 Criteria 1
% at rated power factor is recommended to avoid
tripping during power swing conditions. Due to recent 120% of the unit transformer (XTG )
blackouts caused by voltage collapse the 21 distance
setting should be checked for proper operating margins Converting XGT to secondary ohms

10
 11

IS
kV 2 * X TG RC
X TG sec  G *
MVAG RV ZmaxSG1

20 2 * 0.11607 18,000 5 1 P.U.

X TG sec  * ~ IG ZLLG1
492 20,000 120
X TG sec 2.038 X'd+XTG

Z1reach 1.20 * 2.038 2.45 Fig. 12 Equivalent Circuit for Apparent Impedance with In-
Feeds
Criteria 2
1
ZTotal = ZLLG1 =
Set at 80% of the Zone 1 setting of the shortest line plus 1 1
step-up transformer impedance. The impedance of the 
Z max SG 1 X 'd X TG
shortest line exiting the power plant is XSL1 = j 0.05773 pu
on a 100MVA base. The zone 1 line setting is 80% of the
line length. First put the impedance on the generator base. 0.04566 + j0.50024 pu

MVAG kVS2 kVTlow

2 1
X SLG  * * * X SL 1 ITotal = = 0.18097 – j1.98253 pu
2
MVAS kVThigh kVG
2 Z Total

492 1382 192

X SLG  * * * 0.05773 Current Divider Rule:
100 1452 20 2
X SLG 0.23219 pu X ' d X TG
IS = | I Total x | =
X 'd X TG Z MaxSG1
Converting the line impedance to secondary relay ohms. 1.76895 pu

kV 2 * X SLG1 RC Z MaxSG1
X L1 sec  G * I G = | I Total x | =
MVAG RV X ' d X TG Z MaxSG1
20 2 * 0.23219 18,000 5 0.22207 pu
X L1 sec  *
492 20,000 120 Based on the criteria 1 for the Zone 2 element
X L1sec 4.077 setting:

I S I G 
Z2 _ LINE = ( X TG + 1.2 
Assuming the zone 1 line setting is 80% of the lines then:
 I Z LL1G ) x Z B _ relay =

 G 
Z1reach X TG sec 0.8 * (0.8 * X L1sec ) 90.2 Ω  85
, maximum torque angle Zone 2 (MTA2) =
Z1reach 2.041 0.8 * (0.8 * 4.077) 4.6095 85

Set the zone 1 at the smaller setting of 2.45 at a MTA of Criteria 2
0
85 .
To satisfy criteria 2, the reach of the 21-2 element should
B. Zone 2 Setting Example not exceed 50% to 66.7% (200% to 150% of the generator
capability curve) load impedance at rated power factor.
Criteria 1 Otherwise the distance element could trip on load or stable
power swings. This calculated is shown below:
The apparent impedance reach ( Z 2 _ LINE ) to the end of
the longest line exiting the plant will require an in-feed kV G2 CTRatio
calculation because both the generator and the utility Zmax load = = 17.56  39.64(0.77pf)
transmission system will contribute fault current. The MVAG VTRatio
saturated value of transient reactance X’d is used in this
calculation since this is for a time delayed backup element. The Z2 reach setting at MTA based on Zmax loading based on
Z max load above is:
11
 12

30.0
Z max_ load
Z2 _ MTA = 0.67x = 16.685
; jX
COS (MTA2 RPFA) LONGEST LINE (WITH IN FEED), 75.5 OHMS

where RFPA is the rated power factor angle.

25.0

Criteria 3

The reach of the 21-2 element should not exceed 80% to

GCC GCC
90% (125% to 111% of the generator capability curve) load 20.0

impedance at maximum torque angle. Otherwise the ZONE2

distance element could limit the generator capability curve. ZONE1
ZONE2

This can be calculated as: SYSTEM

15.0

kV G2 CTRatio
ZGCC _ MTA = = 23.14  85
MVAGCC _ MTA VTRatio 50% to 67% OF GCC @
RPFA

10.0

Z2 _ MTA2 = 0.9 x Z GCC _ MTA = 20.8 85

SHORTEST LINE
(NO INFEED)

Since criteria 2 gives the smallest reach setting, the 21-2

MTA
setting should be set at 16.6 at the MTA of 850 to provide 5.0

a secure setting. This is much less than the 90.2  reach RPFA

required to respond to faults at the end of the longest line.

ZONE1
For this case, upgrading of the backup protection on the
transmission system should be investigated to provide -10.0 -5.0
0.0
0.0 5.0 10.0 15.0 20.0

proper primary and backup protection as well as local TRANSFORMER R

HIGH SIDE
breaker failure. For this case, upgrading of the backup
protection on the transmission system should be
investigated to provide proper primary and backup -5.0

protection as well as local breaker failure. In this case the

desired generator remote backup cannot be provided
without compromising loadability. Fig. 13 shows the Fig.13 21 Distance Setting Examples Plotted on an R-X Diagram
distance elements and generator capability curve plotted on
an R-X diagram.
VII. AVR COORDINATION- OVEREXCITED
OPERATION

Excitation system protection/control as well as protection

external to the excitation system needs to be coordinated so
as not to limit the generator overexcitation capability.
During major system disturbances, the excitation control/
protection must allow the generator to operate within its
short time capabilities.

12
 13

Another important factor that must be incorporated into the

250 design of the excitation protection/control system is the
Percent of at R ated F ield Cu rrent

need to accommodate field forcing during faults to aid in

0 C50.13 maintaining transient stability. This dictates that very high
200 0 I*t Trip rotor field current (typically in the range of 140-280% of
rating) must be permitted to flow for a short period of time
I*t Control
without causing the exciter control to reduce field voltage
Limit
150 0 because of the high field current.
Generator Step-up
0 Transformer
0 Generator
100 Field CT VT
Gen.

50 AVR 51*
Excitation
DC CB or * FUSES USED ON
Transformer SMALLER GENERATORS
Contactor
0
0 20 40 60 80 100 120 R
Static
Time In Seconds OC
Exciter

Fig. 14 C50.13 Cylindrical-Rotor Field Short Time Capability [7] OC = DC OVERCURRENT RELAY

and Typical Limiter Control and Trip Coordination [13]

Fig. 15 Typical Transformer Supplied Excitation System
System var support provided by the generator is extremely
important to maintain power system voltage stability. IEEE Field forcing times are typically at least 1 second but may
C50.13 [7] defines the short-time field thermal capability be as long as 10 seconds for compound or brushless
for cylindrical-rotor generators. In this standard the short excitation systems. [13]. Fig. 15 illustrates a typical
time thermal capability is given in terms of permissible transformer supplied static excitation system with the
field current as a function of time. A plot (curve drawn excitation transformer connected to the generator terminals.
from data in C50.13) of this short time capability is shown Excitation systems have controls and limiters that are
in Fig.14. designed to protect the field from thermal damage due to
prolonged exposure to high current or overexcitation due to
Present-day exciters fall into two broad categories: those higher than allowable flux (V/Hz) levels. Typically key
using AC generators (alternators) as a power source and protection/control elements within the excitation system
those that use transformers. Because the protection that affect overexcitation generator operation include:
requirements of the excitation system are closely related to  Overexcitation Limiter (OEL) – Protects the
their design, the field protection equipment is normally generator field circuitry from excessive current
provided as part of the excitation system. Data for the versus time heating. Its setting should be
specific generator field capability need to be used in coordinated with the generator capability in the
determining excitation capability and coordination. It is overexcitation region as described in Section II of
important that the control as well as any tripping protection this paper so that full var capability of the
that maybe embedded within the exciter allow the generator generator is available. The setting should also
to provide full overexcitation system support during system allow the exciter to respond to fault conditions
voltage transient as well as for steady state conditions. As where field current is boosted (field forcing) to a
discussed in Section II of this paper, the selection of the high level for a short period of time. In many cases
step-up transformer tap setting play a key role in this coordination is provided by not enabling OEL
determining whether the generator can provide it’s full var control until the field forcing time is exceeded.
support to the system without being limited by the generator The OEL setting should also allow utilization of
terminal voltage. Generally, in the US generator step-up the short time field current capability as defined by
transformers are not equipped with LTC load tap changing. C50.13 (Fig. 14 for cylindrical rotor generators).
Consequently, as power system operating conditions change Typically, the OEL takes over control to limit field
over time, it is necessary to periodically check that current from the steady state AVR control for
optimum transformer tap settings have been selected [12]. close in faults where the induced field current
Such checks are typically done by system planning remains high or during sustained system low
engineers who determine optimum tap settings from load voltage conditions requiring field current above
flow studies. rated levels. In new excitation systems the OEL

13
 14

limiter control has the ability to modify its setting excitation systems have begun to provide these protection
based on either hydrogen pressure (if the generator functions within the excitation system control.
is hydrogen cooled) or inlet air temperature
measurements. A. Testing of Excitation Systems

 V/Hz Limiter – Limits the generator V/Hz ratio by
limiting the generator voltage to a programmed Operating the generator at its maximum excitation level to
setting. Steady state limit are +/- 5% of rated ensure that controllers operate to keep the generator within
generator stator terminal voltage at rated safe limits before protection operates can be periodically
frequency. The setting should permit short time tested. Such test may be done not only by bring the
excursions during transient conditions. The V/Hz generator slowly up to its steady state limit, but also by
limiter is a limit function to the AVR setpoint and bringing it rapidly up to the limit so that coordination for
is not a variable as is the above described OEL in short time operation above the steady state limit can be
Fig.14. checked. Conducting these tests on a large generator can

 Field Overcurrent Protection – DC overcurrent result in system voltage problems. These tests must be
protection is provided in exciters as show in Fig. carefully coordinated so that system voltage is maintained
15. Some exciters have a protective inverse time within acceptable levels. Reference 13 provides a detail
module that calculates the I*t to provide an inverse description of testing the exciter OEL, UEL and V/Hz
time curve. It needs to be coordinated with the limiter.
OEL setting as well as the short time capability of
the field (Fig. 14). It also should allow field B. V/Hz (24) Protection
forcing to take place during fault conditions. In
some cases this protection may trip the exciter if One of the major functions of V/Hz protection is to serve as
OEL initiated runback is unsuccessful. a backup in case of the failure of the V/Hz limiter within
the excitation control. V/Hz protection is set based on the
Excitation Transformer Protection – This protection is short time capability of the generator and transformers
typically provided by either overcurrent relays on larger connected to the generator terminals. The flux in the stator
generator or fuses on small machines connected on the core of a generator or core of a transformer is directly
primary of the excitation transformer (Fig.15). Typically proportional to voltage and inversely proportional to
the kVA size of the excitation transformer and its protection frequency. Overexcitation of a generator or any
is provided as part of the excitation system package. The transformer connected to the generator terminals will occur
time overcurrent protection should be coordinated with the whenever the ratio of voltage to frequency (V/Hz) applied
field short time overload capability and field forcing. The to the terminals exceeds 1.05 pu (generator base) for a
short time field capability is specified in terms of DC generator; and 1.05 pu (transformer base) for a transformer
current as a multiple of field rated current (Fig. 14). The at full load. The transformer no load level is 1.10 pu. For
kW component at various field overload levels can be transformers the point of measurement is the output
2
determined by I Rf where Rf is the field resistance and I is terminals. IEEE/ANSI C50.12 and C50.13 [7] provide
the field current at various multiples of field rated current. voltage ranges for generators. Typically the allowable range
The AC time overcurrent required providing that KW can for continuous operation is between 0.95 and 1.05 pu V/Hz.
then be determined at the AC voltage rating of the The manufacturer should be consulted for V/Hz short time
excitation transformer. Doing so, however, neglects the loss capability of a specific generator. The primary concern
in the bridge circuitry, which can be significant for high from an excitation standpoint is the possibility of excessive
ceiling static exciter. The power factor that results can be V/Hz overexciting the generator. When the V/Hz ratios are
far from unity with most of the load being vars due to the exceeded, saturation of the iron core of generators and
fact that the bridge circuit is firing with a more delayed transformers will occur resulting in the breakdown of core
angle. The resulting short time current on the AC excitation inter-lamination insulation due to excessive voltage and
transformer is a combination of the field current eddy current heating.
requirements and losses in the bridge circuitry. The
excitation system manufacture should be able to provide the During system disturbances, overexcitation is caused by
relationship of AC current to DC current at various the sudden loss of load due to transmission line tripping
excitation and over excitation levels. which can island the generator from the power grid with
little load and the shunt capacitance of the unloaded
Relay engineers need to be aware of the control and transmission lines. Under these conditions the V/Hz level
tripping protection that resides within the exciter and its may exceed 1.25 pu where the voltage regulator is slow in
impact on limiting generator overexcitation operation. responding. With the AVR control in service, the
Traditionally, tripping for excitation system problems such overexcitation would generally be reduced to safe limits
at V/Hz (24), overvoltage (59) and loss of field (40) were (less than 1.05pu) in a few seconds. The limiter will limit
done by relays external to the excitation system. This was the V/Hz generator output to a set maximum within the
done to separate protection and control. New digital generator capability curve. Even with a V/Hz limiter in the

14
 15

excitation control, it is common and recommended practice reactance of the transformer. This is typically done at the
[6] to provide separate V/Hz relaying to protect the full load rating of the transformer at an 80% power factor.
generator and any transformers connected to the generator A sample calculation is shown in ANSI/IEEE C37.106
terminals. The setting of these relays is based on the short [11]. The values in Table 1 and in Fig.16 have been so
time V/Hz capability of the generator as shown in Fig.14. compensated. Many new digital transformer relays have
In modern application where digital relays are used, the V/Hz protective functions within the relay package. The
V/Hz protection of the transformer resides in the newer practice is to provide the V/Hz step-up transformer
transformer protection relay and is set to protect the protection within the transformer package, and measures
transformer. Both generator and transformer protection V/Hz at the step up transformer high voltage terminals.
must be coordinated with the AVR V/Hz limiter control.
The exciter’s V/Hz limiting should be set at the upper limit The setting calculation example uses two relay elements to
of the normal operating range and below the continuous provide protection; one inverse time element and a definite
operating limit for the generator and unit connected time element. The combined protection curve is also shown
transformer. Similarly, a V/Hz relay(s) should be set with in Fig.16. The type of curve and time dial should be
enough delay to allow AVR control action to take place selected such that the relay characteristic operates before
before tripping the unit. This relay(s) however, must still the generator and transformer capability limits are reached.
protect the generator from damage. This typically is not a
problem because the AVR control can adjust generator
Table 1 Overexcitation Capability
terminal voltage within seconds.
Main Transformer Capability
C. Overexcitation Relay Settings
Time (min) V/Hz (%)
There are two basic types of V/Hz protection scheme used 40 106.4
within the industry. The first and most common is the dual 30 106.9
definite time setpoint method. Typical conservative 20 107.4
protection applications recommend a maximum trip level at 10 108.4
1.18 pu V/Hz with a 2-6 second time delay for the first
6 109.3
setpoint. The second setpoint is set at 1.10 pu V/Hz with a
time delay of 45-60 seconds. 2 112.1
1 114.3
The second method uses an inverse-time characteristic 0.5 118
curve as well as definite time setpoints to better match the 0.3 123.5
inverse times V/Hz capability of the generator. This scheme
can be precisely applied when a V/Hz vs. time curve for a
specific generator is available. The minimum pickup is Generator Capability
typically 1.10 pu V/Hz. The inverse-time function is set Time (min) V/Hz (%)
with a greater time delay than the exciter in order to permit 33 110
the exciter to operate to reduce voltage before protection 25 111
action takes place. 20 111.5
15 112.5
D. V/HZ Overexcitation Protection Setting Example 10 113.5
5 115.5
The overexcitation capability limits for the example 2 118
generator and the connecting transformer are shown in 1 120
Table 1 and in Fig 14. The main transformer’s V/Hz 0.5 122
capability has already been adjusted in the table by 19/20 = 0.2 125
0.95 multiplying factor to put its V/Hz capability on the
generator’s voltage base so the generator’s V/Hz capability
and the transformer’s V/Hz capability points may be plotted
together.

The overexcitation transformer limits are define in

ANSI/IEEE C57.12 [10] and are measured at the output of
the transformer at a power factor of 80%. The output of the
generator step-up transformer is at the high voltage
terminals of the transformer. If the V/Hz protective relay
that is used to protect the generator step up transformer is
located at the generator terminals the setting must be
compensated for the voltage drop across the leakage
15
 16

disturbances is a key goal that requires coordination of

generator protection with generator control. It is the hope
Transformer of the Power System Relay Committee Working Group that
authored this paper that it will assist the industry in
130 Generator reaching this goal.
Inverse Time Curve
REFERENCES
125 Definite Time
[1] “NERC PRC-001-0 – System Protection Coordination”,
Series5 Adopted by NERC Board of Trustees, Feb 8, 2005.
[2] “NERC PRC-024-1 Generator Performance During
Percent age V/Hz

120 Frequency and Voltage Excursions,” Pending NERC

Review and Approval.
[3] “NERC PRC-019-1 Coordination of Generator Voltage
115 Controls with Unit Capabilities and Protection, Pending
Definite Time
NERC Review and Approval.
Pickup
[4] “Protective Relaying Theory and Applications” edited
110 by Walter A. Elmore, ABB Power T&D Company Inc.
Coral Springs, FL, 1994.
[5] “Final Report on the August 14, 2003 Blackout in the
105 Inverse Time United States and Canada: Causes and
Pickup Recommendations”, U.S. – Canada Power System Outage
Task Force, April 5, 2004.
[6] IEEE Guide for AC Generator Protection, ANSI/IEEE
100 C37.102-1995.
0.01 0.1 1 10 100 [7] “American National Standard for Cylindrical Rotor
Synchronous Generators”, ANSI/IEEE C-50.13-2005.
Operating Time in Minutes [8] IEEE Committee Report “A Survey of Generator Back-
Up Protection Practices” IEEE Transactions on Power
Delivery, Vol.5 April 1990.
Fig. 16 V/Hz Characteristic Plot [9] IEEE Committee Report “Performance of Generator
Protection During Major System Disturbances” IEEE
VIII CONCLUSIONS Transactions on Power Delivery. IEEE Transactions on
Power Delivery, Vol19, Oct. 2004.
Recent misoperations of generation protection during [10] “IEEE Standard, Test Code for Distribution, Power
major system disturbances have highlighted the need for and Regulating Transformers”, ANSI/IEEE C57.12 –Latest
better coordination of generator protection with generator Revision.
capability, generator excitation control (AVR) and [11] “IEEE Guide for Abnormal Frequency Protection of
transmission system protection. The techniques, methods Power Generating Plants,” IEEE Standard C37-106-2003
and practices to provide this coordination are well [12] M.M. Abibi, L.H.Fink,”Restoration from Cascading
established but scattered in various textbooks, papers and Failures” IEEE PES Power & Energy Magazine, Vol.4
relay manufactures literature. This paper provides a single Number 5, Sept./Oct. 2006.
document that can be used by relay engineers to address [13] A.Murdoch, R.W. Delmerico, S.Venkataraman, R.A.
these coordination issues. Lawson, J.E, Curran, W.R. Pearson, “Excitation System
Protective Limiters and Their Effect on Volt/var Control –
This paper provides practical guidance on proper Design, Computer Modeling, and Field Testing” IEEE
coordination of generator protection and generator AVR Transactions on Power Delivery, IEEE Transactions on
control to enhance security and system stability. The paper Energy Conversion, Volume: 15, Issue: 4, Dec. 2000
uses example calculations as a means of communicating Pages: 440 – 450
these methods. The paper also addresses the coordination
of generator protection with generator full load capability
APPENDIX I
and machine steady state stability. Setting of protective
relays is an art as well as a science. The calculations shown
Definition of key symbols uses in calculations.
in this paper are intended to illustrate typical settings and
factors that must be considered in developing generator
Steady State Stability Calculations (Section IV):
settings. The Working Group recognizes that other
methodologies that affect the same results could also be
used. Keeping generators on-line during major system X TG = GSU reactance on the generator base.

16
 17

X minST 1 = System reactance with the strongest line Zmax load = Rated load generator impedance in secondary
(line that contributes the most fault current) out of service. ohms at generator rated power factor.
See Fig. 4. Reactance is on the GSU transformer base. Z2 _ MTA = Zone 2 21 setting in secondary ohm at 850 to
X minSG = System reactance with the strongest line out of maintain a margin of 150% at rated power factor angle.
service on the generator base. Z2 _ MTA2 = Impedance of Generator Capability curve at
Loss of Field Relay Coordination (Section V): Max. Torque Angle (MTA) of the Zone 2 relay in
secondary ohms with a margin of 90%.
Z1Diameter = Loss of Field (LOF) impedance circle diameter
setting of Zone 1.
Z 2Diameter = LOF impedance circle diameter setting of
Zone 2.
Z1Offset = Offset of Zone 1 LOF impedance setting.
Z 2Offset = Offset of Zone 2 LOF impedance setting.

Generator Phase Backup (21) Coordination (Section VI):

Zone1 Calculation:

X TG sec = GSU reactance in secondary ohms.

Z1reach = Diameter of Zone 1 impedance setting.
X SLG = Line reactance of the shortest line existing the
power plant on generator base.
X L1 sec = Line reactance of the shortest line existing the
power plant in secondary ohms.
Z1reach = Zone 1 21relay setting.

Zone 2 Calculations:

ZTotal = Total short circuit impedance of a fault at the end

of the longest transmission line exiting the power plant.
ZLLG1 = Impedance of longest line exiting the power plant
on the generator base.
ZmaxSG1 = System impedance on generator base all lines in
service.
ITotal = Total fault current for a fault at the end of the
longest line exiting the power plant.
I S = System contribution for a fault at the end of the
longest line existing the power plant.
I G = Generator contribution for a fault at the end of the
longest line existing the power plant.
Z2 _ LINE = Zone 2 relay setting to see the end of the longest
line existing the power plant in secondary ohms with 120%
margin.
Z B _ relay = Generator base ohms
= Rated Gen. Sec. Voltage/Rated Gen Sec. Current
= 69.28V/ 3.95A = 17.56 Ώ.

17

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