Basler BE1-851 User guide

Generator Protection
Application Guide

About the Original Author
George Rockefeller is a private consultant. He has a BS in EE from Lehigh University; MS from New
Jersey Institute of Technology and a MBA from Fairleigh Dickinson University. Mr. Rockefeller is a
Fellow of IEEE and Past Chairman of IEEE Power Systems Relaying Committee. He holds nine U.S.
Patents and is co-author of Applied Protective Relaying (1st Edition). Mr. Rockefeller worked for
Westinghouse Electric Corporation for twenty-one years in application and system design of protective
relaying systems. He worked for Consolidated Edison Company for ten years as a System Engineer.
He has served as a private consultant since 1982.
Updates and additions performed by various Basler Electric Company employees.
This Guide contains a summary of information for the protection of various types of electrical
equipment. Neither Basler Electric Company nor anyone acting on its behalf makes any warranty or
representation, express or implied, as to the accuracy or completeness of the information contained
herein, nor assumes any responsibility or liability for the use or consequences of use of any of this
information.
First printing April 1994
Revision C.0 June 2001

Generator Protection
Application Guide
Introduction
This guide was developed to assist in the
selection of relays to protect a generator. The
purpose of each relay is described and related to
one or more power system configurations. A
large number of relays is available to protect for
a wide variety of conditions. These relays protect
the generator or prime mover from damage. They
also protect the external power system or the
processes it supplies. The basic principles
offered here apply equally to individual relays
and to multifunction numeric packages.
The engineer must balance the expense of
applying a particular relay against the con-
sequences of losing a generator. The total loss
of a generator may not be catastrophic if it
represents a small percentage of the investment
in an installation. However, the impact on service
reliability and upset to loads supplied must be
considered. Damage to and loss of product in
continuous processes can represent the domi-
nating concern rather than the generator unit.
Accordingly, there is no standard solution based
on the MW rating. However, it is rather expected
that a 500kW, 480V, standby reciprocating
engine will have less protection than a 400MW
base load steam turbine unit. One possible
common dividing point is that the extra CTs
needed for current differential protection are less
commonly seen on generators less than 2MVA,
generators rated less than 600V, and generators
that are never paralleled to other generation.
This guide simplifies the process of selecting
relays by describing how to protect against each
type of fault or abnormal condition. Then,
suggestions are made for what is considered to
be minimum protection as a baseline. After
establishing the baseline, additional relays, as
described in the section on Extended
Protection, may be added.
The subjects covered in this guide are as
follows:
• Ground Fault (50/51-G/N, 27/59, 59N, 27-3N,
87N)
• Phase Fault (51, 51V, 87G)
• Backup Remote Fault Detection (51V, 21)
• Reverse Power (32)
• Loss of Field (40)
• Thermal (49)
• Fuse Loss (60)
• Overexcitation and Over/Undervoltage
(24, 27/59)
• Inadvertent Energization (50IE, 67)
• Negative Sequence (46, 47)
• Off-Frequency Operation (81O/U)
• Sync Check (25) and Auto Synchronizing (25A)
• Out of Step (78)
• Selective and Sequential Tripping
• Integrated Application Examples
• Application of Multifunction Numerical Relays
• Typical Settings
• Basler Electric Products for Protection
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The references listed on Page 22 provide more
background on this subject. These documents
also contain Bibliographies for further study.
Ground Fault Protection
The following information and examples cover
three impedance levels of grounding: low,
medium, and high. A low impedance grounded
generator refers to a generator that has zero or
minimal impedance applied at the Wye neutral
point so that, during a ground fault at the genera-
tor HV terminals, ground current from the genera-
tor is approximately equal to 3 phase fault
current. A medium impedance grounded genera-
tor refers to a generator that has substantial im-
pedance applied at the wye neutral point so that,
during a ground fault, a reduced but readily de-
tectable level of ground current, typically on the
order of 100-500A, flows. A high impedance
grounded generator refers to a generator with a
large grounding impedance so that, during a
ground fault, a nearly undetectable level of fault
current flows, necessitating ground fault monitor-
ing with voltage based (e.g., 3rd harmonic volt-
age monitoring and fundamental frequency neu-
tral voltage shift monitoring) relays. The location
of the grounding, generator neutral(s) or trans-
former, also influences the protection approach.
The location of the ground fault within the gen-
erator winding, as well as the grounding imped-
ance, determines the level of fault current.
Assuming that the generated voltage along each
segment of the winding is uniform, the prefault
line-ground voltage level is proportional to the
percent of winding between the fault location and
the generator neutral, VFG in Fig. 1. Assuming an
impedance grounded generator where (Z0, SOURCE
and ZN)>>ZWINDING, the current level is directly
proportional to the distance of the point from the
generator neutral [Fig. 1(a)], so a fault 10% from
neutral produces 10% of the current that flows
for a fault on the generator terminals. While the
current level drops towards zero as the neutral is
approached, the insulation stress also drops,
tending to reduce the probability of a fault near
the neutral. If a generator grounding impedance
is low relative to the generator winding imped-
ance or the system ground impedance is low, the
fault current decay will be non-linear. For I1in
Fig. 1, lower fault voltage is offset by lower
generator winding resistance. An example is
shown in Fig. 1(b).
The generator differential relay (87G) may be
sensitive enough to detect winding ground faults
with low-impedance grounding per Fig. 2. This
would be the case if a solid generator-terminal
fault produces approximately 100% of rated
current. The minimum pickup setting of the
differential relays (e.g., Basler BE1-CDS220 or
BE1-87G, Table 2) should be adjusted to sense
faults on as much of the winding as possible.
However, settings below 10% of full load current
(e.g., 0.4A for 4A full load current) carry in-
creased risk of misoperation due to transient CT
saturation during external faults or during step-up
transformer energization. Lower pickup settings
are recommended only with high-quality CTs
(e.g., C400) and a good CT match (e.g., identical
accuracy class and equal burden).
FIGURE 1. EFFECTS OF FAULT LOCATION WITHIN
GENERATOR ON CURRENT LEVEL.
If 87G relaying is provided per Fig. 2, relay 51N
(e.g., Basler relays per Table 2) backs up the
87G, as well as external relays. If an 87G is not
provided or is not sufficiently sensitive for ground

winding from the neutral, the 51N current will be
0.5A, with a 1000/5 CT.
Fig. 3 shows multiple generators with the trans-
former providing the system grounding. This
arrangement applies if the generators will not be
operated with the transformer out of service. The
scheme will lack ground fault protection before
generator breakers are closed. The transformer
could serve as a step-up as well as a grounding
transformer function. An overcurrent relay 51N or
a differential relay 87G provides the protection
for each generator. The transformer should
produce a ground current of at least 50% of
generator rated current to provide about 95% or
more winding coverage.
faults, then the 51N provides the primary protec-
tion for the generator. The advantage of the 87G
is that it does not need to be delayed to coordi-
nate with external protection; however, delay is
required for the 51N. One must be aware of the
effects of transient DC offset induced saturation
on CTs during transformer or load energization
with respect to the high speed operation of 87G
relays. Transient DC offset may induce CT
saturation for many cycles (likely not more than
10), which may cause false operation of an 87G
relay. This may be addressed by not block load-
ing the generator, avoiding sudden energization
of large transformers, providing substantiallly
overrated CTs, adding a very small time delay to
the 87G trip circuit, or setting the relay fairly
insensitively.
FIGURE 2. GROUND-FAULT RELAYING -
GENERATOR LOW-IMPEDANCE GROUNDING.
The neutral CT should be selected to produce a
secondary current of at least 5A for a solid
generator terminal fault, providing sufficient
current for a fault near the generator neutral. For
example, if a terminal fault produces 1000A in
the generator neutral, the neutral CT ratio should
not exceed 1000/5. For a fault 10% from the
neutral and assuming I1is proportional to percent
FIGURE 3. SYSTEM GROUNDED EXTERNALLY WITH
MULTIPLE GENERATORS.
Fig. 4 shows a unit-connected arrangement
(generator and step-up transformer directly
connected with no low-side breaker), using high-
resistance grounding. The grounding resistor and
voltage relays are connected to the secondary of
a distribution transformer. The resistance is
normally selected so that the reflected primary
resistance is approximately equal to one-third of
the single phase line-ground capacitive reactance
of the generator, bus, and step-up transformer.
This will limit fault current to 5-10A primary.
Sufficient resistor damping prevents ratcheting up
of the sound-phase voltages in the presence of an
intermittent ground. The low current level mini-
mizes the possibility of sufficient iron damage to
require re-stacking. Because of the low current
level, the 87G relay will not operate for single-
phase ground faults.
FIGURE 4. UNIT-CONNECTED CASE WITH HIGH-
RESISTANCE GROUNDING.
Protection in Fig. 4 consists of a 59N overvoltage
relay and a 27-3N third-harmonic undervoltage
relay (e.g., Basler relays per Table 2). As shown
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4
in Fig. 5, a ground fault at the generator high
voltage bushings elevates the sound phase line to
ground voltages to a nominal 173% of normal line
to neutral voltages. Also, the neutral to ground
voltage will rise to the normal phase-ground
voltage levels. The closer the ground fault is to
the generator neutral, the less the neutral to
ground voltage will be. One method to sense this
neutral shift is with the 59N relay (Fig. 4) monitor-
ing the generator neutral. The 59N will sense and
protect the generator for ground faults over about
95% of the generator winding. The selected 59N
(Basler relays per Table 2) relay should be
selected so as to not respond to third harmonic
voltage produced during normal operation. The
59N will not operate for faults near the generator
neutral because of the reduced neutral shift during
this type of fault.
FIGURE 5. NEUTRAL SHIFT DURING GROUND FAULT
ON HIGH IMPEDANCE GROUNDED SYSTEM.
Faults near the generator neutral may be sensed
with the 27-3N. When high impedance grounding
is in use, a detectable level of third harmonic
voltage will usually exist at the generator neutral,
typically 1-5% of generator line to neutral funda-
mental voltage. The level of third harmonic is
dependent on generator design and may be very
low in some generators (a 2/3 pitch machine will
experience a notably reduced third harmonic
voltage). The level of harmonic voltage will likely
decrease at lower excitation levels and lower load
levels. During ground faults near the generator
neutral, the third harmonic voltage in the generator
neutral is shorted to ground, causing the 27-3N to
drop out (Fig. 6). It is important that the 27-3N
have high rejection of fundamental frequency
voltage.
FIGURE 6. GROUND FAULT NEAR GENERATOR
NEUTRAL REDUCES THIRD-HARMONIC VOLTAGE IN
GENERATOR NEUTRAL, DROPPING OUT 27-3N.
The 27-3N performs a valuable monitoring
function aside from its fault detection function; if
the grounding system is shorted or an open
occurs, the 27-3N drops out.
The 59P phase overvoltage relay in Fig. 4
supervises the 27-3N relay, so that the 86
lockout relay can be reset when the generator is
out of service; otherwise, the field could not be
applied. Once the field is applied and the 59P
operates, the 27-3N protection is enabled. The
59P relay should be set for about 90% of rated
voltage. An “a” contact of the unit breaker can be
used instead of the 59P relay to supervise 27-3N
tripping. Blocking the 27-3N until some level of
forward power exists also has been done.
However, use of the 59P relay allows the 27-3N
to provide protection prior to synchronization
(i.e., putting the unit on line), once the field has
been applied.
In order to provide 100% stator winding cover-
age, the undervoltage (27-3N) and overvoltage
(59N) settings should overlap. For example, if a
generator-terminal fault produces 240V, 60 Hz
across the neutral voltage relay (59N), a 1V
pickup setting (a fairly sensitive setting) would
allow all but the last (1/240)*100 = 0.416% of the
winding to be covered by the overvoltage
function. If 20V third harmonic is developed
across the relay prior to a fault, a 1V third-
harmonic drop-out setting would provide dropout
for a fault up to (1/20)*100= 5% from the neutral.
Setting the 59N pickup too low or the 27N
dropout too low may result in operation of the
ground detection system during normal operating
conditions. The third harmonic dropout level may
be hardest to properly set, since its level is
dependent on machine design and generator
excitation and load levels. It may be advisable to

measure third harmonic voltages at the generator
neutral during unloaded and loaded conditions
prior to selecting a setting for the 27-3N dropout.
In some generators, the third harmonic at the
neutral may become almost unmeasurably low
during low excitation and low load levels, requir-
ing blocking the 27-3N tripping mode with a
supervising 32 underpower element when the
generator is running unloaded.
There is also some level of third harmonic
voltage present at the generator high voltage
terminals. A somewhat predictable ratio of
(V3RD-GEN.HV.TERM)/(V3RD-GEN.NEUTRAL) will exist under
all load conditions, though this ratio may change
if loading can induce changes in third harmonic
voltages. A ground fault at the generator neutral
will change this ratio, and this ratio change is
another means to detect a generator ground
fault. Two difficulties with this method are:
problems with developing means to accurately
sense low third harmonic voltages at the genera-
tor high voltage terminals in the presence of
large fundamental frequency voltages, and
problems with dealing with the changes in third
harmonic ratio under some operating conditions.
If the 59N relay is only used for alarming, the
distribution transformer voltage ratio should be
selected to limit the secondary voltage to the
maximum continuous rating of the relay. If the
relay is used for tripping, the secondary voltage
could be as high as the relay’s ten-second
voltage rating. Tripping is recommended to min-
imize iron damage for a winding fault as well as
minimizing the possibility of a multi-phase fault.
Where wye-wye voltage transformers (VTs) are
connected to the machine terminals, the sec-
ondary VT neutral should not be grounded in
order to avoid operation of 59N for a secondary
ground fault. Instead, one of the phase leads
should be grounded (i.e., "corner ground"),
leaving the neutral to float. This connection
eliminates any voltage across the 59N relay for a
secondary phase-ground fault. If the VT second-
ary neutral is grounded, a phase-ground VT sec-
ondary fault pulls little current, so the secondary
fuse sees little current and does not operate. The
fault appears to be a high impedance phase to
ground fault as seen by the generator neutral
shift sensing relay (59N), leading to a generator
trip. Alternatively, assume that the VT corner
(e.g., phase A) has been grounded. If phase B or
C fault to ground, the fault will appear as a
phase-phase fault, which will pull high secondary
currents and will clear the secondary fuse rapidly
and prevent 59N operation. A neutral to ground
fault will tend to operate the 59N, but this is a
low likelihood event. An isolation VT is required if
the generator VTs would otherwise be galvani-
cally connected to a set of neutral-grounded
VTs. Three wye VTs should be applied where an
iso-phase bus (phase conductors separately
enclosed) is used to protect against phase-phase
faults on the generator terminals.
The 59N relay in Fig. 4 is subject to operation for
a ground fault on the wye side of any power
transformer connected to the generator. This
voltage is developed even though the generator
connects to a delta winding because of the
transformer inter-winding capacitance. This
coupling is so small that its effect can ordinarily
be ignored; however, this is not the case with the
59N application because of the very high ground-
ing resistance. The 59N overvoltage element
time delay allows the relay to override external-
fault clearing.
The Basler BE1-GPS100, BE1-951, BE1-1051,
and BE1-59N relays contain the required neutral
overvoltage (59N), undervoltage (27-3N), and
phase overvoltage (59P) units.
Fig. 4 shows a 51GN relay as a second means
of detecting a stator ground fault. The use of a
51GN in addition to the 59N and 27-3N is readily
justified, since the most likely fault is a stator
ground fault. An undetected stator ground fault
would be catastrophic, eventually resulting in a
multiphase fault with high current flow, which per-
sists until the field flux decays (e.g., for 1 to 4s).
The CT shown in Fig. 4 could be replaced with a
CT in the secondary of the distribution trans-
former, allowing use of a CT with a lower voltage
rating. However, the 51GN relay would then be
inoperative if the distribution transformer primary
becomes shorted. The CT ratio for the second-
ary-connected configuration should provide for a
relay current about equal to the generator neutral
current (i.e., 5:5 CT). In either position, the relay
pickup should be above the harmonic current
flow during normal operation. (Typically harmonic
current will be less than 1A but the relay may be
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set lower if the relay filters harmonic currents
and responds only to fundamental currents.)
Assuming a maximum fault current of 8A primary
in the neutral and a relay set to pick up at 1A
primary, 88% of the stator winding is covered.
As with the 59N relay, the 51GN delay will allow
it to override clearing of a high-side ground fault.
An instantaneous overcurrent element can also
be employed, set at about three times the time-
overcurrent element pickup, although it may not
coordinate with primary vt fuses that are con-
nected to the generator terminals.
Multiple generators, per Fig. 7, can be high-
resistance grounded, but the 59N relays will not
be selective. A ground fault anywhere on the
generation bus or on the individual generators will
be seen by all 59N relays, and the tendency will
be for all generators to trip. The 51N relay, when
connected to a flux summation CT, will provide
selective tripping if at least three generators are
in service. In this case, the faulted generator
51N relay will then see more current than the
other 51N relays. The proper 51N will operate
before the others because of the inverse charac-
teristic of the relays. Use of the flux summation
CT is limited to those cases where the CT
window can accommodate the three cables.
Fault currents are relatively low, so care must be
exercised in selecting appropriate nominal relay
current level (e.g., 5A vs. 1A) and CT ratio. For
example, with a 30A fault level and a 50 to 5A
CT, a 1A nominal 51N with a pickup of 0.1A
might be used. With two generators, each
contributing 10A to a terminal fault in a third
generator, the faulted-generator 51N relay sees
2*10/(50/5) = 2A. Then the relay protects down
to (0.1/2)*100 = 5% from the neutral.
When feeder cables are connected to the gen-
erator bus, the additional capacitance dictates a
much lower level of grounding resistance than
achieved with a unit-connected case. A lower re-
sistance is required to minimize transient over-
voltages during an arcing fault.
FIGURE 7. 59N RELAY OPERATION WITH MULTIPLE
UNITS WILL NOT BE SELECTIVE; 51N RELAYS PRO-
VIDE SELECTIVE PROTECTION IF AT LEAST THREE
GENERATORS ARE IN SERVICE.
Ground differential (Fig. 8) is a good method to
sense ground faults on low and medium imped-
ance grounded units. It would more commonly be
seen on generators that have the CTs required
for phase differential relaying. In Fig. 8, the
protective function is labeled 87N, but the Basler
BE1-CDS220 or the BE1-67N is applied. The
BE1-CDS220 approach is more applicable to low
and medium impedance grounded generators
with ground faults as low as 50% of phase fault
current. The BE1-67N approach is more appli-
cable to medium impedance generators with low
ground fault current levels. The BE1-CDS220 is
limited in sensitivity to ground faults in excess of
10% of the phase CT tap setting, but the use of
the auxiliary CT in the BE1-67N approach allows
for amplification of the ground current in the
phase CTs, yielding increased sensitivity.
Whichever approach is used, an effort should be
made to select relay settings to trip for faults as
low as 10% of maximum ground fault current
levels. During external phase faults, considerable
87N operating current can occur when there is
dissimilar saturation of the phase CTs due to
high AC current or due to transient DC offset
effects, while the generator neutral current still
will be zero, assuming balanced conductor
impedances to the fault. One method to compen-
sate for transient CT saturation is to have
sufficient delay in the relay to ride through
external high-current two-phase-ground faults.

Fig. 10 shows an example of generator current
decay for a 3 phase fault and a phase-phase
fault. For a 3 phase fault, the fault current
decays below the pickup level of the 51 relay in
approximately one second. If the time delay of
the 51 can be selectively set to operate before
the current drops to pickup, the relay will provide
3 phase fault protection. The current does not
decay as fast for a phase-phase or a phase-
ground fault and, thereby, allows the 51 relay
more time to trip before current drops below
pickup. Fig. 10 assumes no voltage regulator
boosting, although the excitation system re-
sponse time is unlikely to provide significant
fault current boosting in the first second of the
fault. It also assumes no voltage regulator
dropout due to loss of excitation power during the
fault. If the generator is loaded prior to the fault,
prefault load current and the associated higher
excitation levels will provide the fault with a
higher level of current than indicated by the Fig.
10 curves. An estimate of the net fault current of
a pre-loaded generator is a superposition of load
current and fault current without pre-loading. For
example, assuming a pre-fault 1pu rated load at
30 degree lag, at one second the 3 phase fault
value would be 2.4 times rated, rather than 1.75
times rated (1@30°+1.75@90°=2.4@69°). Under
these circumstances, the 51 relay has more time
to operate before current decays below pickup.
FIGURE 10. GENERATOR FAULT CURRENT DECAY
EXAMPLE FOR 3 PHASE AND PHASE-PHASE FAULTS
AT GENERATOR TERMINALS - WITH NO REGULATOR
BOOSTING OR DROPOUT DURING FAULT AND NO
PREFAULT LOAD.
FIGURE 8. MEDIUM-LEVEL GROUNDING WITH 87N
GROUND DIFFERENTIAL PROTECTION.
Phase-Fault Protection
Fig. 9 shows a simple means of detecting
phase faults, but clearing is delayed, since the
51 relay must be delayed to coordinate with
external devices. Since the 51 relay operates for
external faults, it is not generator zone selective.
It will operate for abnormal external operating
conditions such as remote faults that are not
properly cleared by remote breakers. The 51
pickup should be set at about 175% of rated
current to override swings due to a slow-clearing
external fault, the starting of a large motor, or the
re-acceleration current of a group of motors.
Energization of a transformer may also subject
the generator to higher than rated current flow.
FIGURE 9. PHASE-OVERCURRENT PROTECTION (51)
MUST BE DELAYED TO COORDINATE WITH
EXTERNAL RELAYS.
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Figure 9 shows the CTs on the neutral side of
the generator. This location allows the relay to
sense internal generator faults but does not
sense fault current coming into the generator
from the external system. Placing the CT on the
system side of the generator introduces a
problem of the relay not seeing a generator
internal fault when the main breaker is open and
when running the generator isolated from other
generation or the utility. If an external source
contributes more current than does the genera-
tor, using CTs on the generator terminals, rather
than neutral-side CTs, will increase 51 relay
sensitivity to internal faults due to higher current
contribution from the external source; however,
the generator is unprotected should a fault occur
with the breaker open or prior to synchronizing.
Voltage-restrained or voltage-controlled time-
overcurrent relays (51VR, 51VC) may be used as
shown in Fig. 11 to remove any concerns about
ability to operate before the generator current
drops too low. The voltage feature allows the
relays to be set below rated current. The Basler
BE1-951, BE1-1051, BE1-GPS100, and
BE1-51/27R voltage restrained approach causes
the pickup to decrease with decreasing voltage.
For example, the relay might be set for about
175% of generator rated current with rated
voltage applied; at 25% voltage the relay picks
up at 25% of the relay setting (1.75*0.25=0.44
times rated). The Basler BE1-951, BE1-GPS,
and BE1-51/27C voltage controlled approach
inhibits operation until the voltage drops below a
preset voltage. It should be set to function below
about 80% of rated voltage with a current pickup
of about 50% of generator rated. Since the
voltage-controlled type has a fixed pickup, it can
be more readily coordinated with external relays
than can the voltage-restrained type. The
voltage-controlled type is recommended since it
is easier to coordinate. However, the voltage-
restrained type will be less susceptible to
operation on swings or motor starting conditions
that depress the voltage below the voltage-
controlled undervoltage unit dropout point.
FIGURE 11. VOLTAGE-RESTRAINED OR VOLTAGE-
CONTROLLED TIME-OVERCURRENT PHASE FAULT
PROTECTION.
Fig. 12 eliminates concerns about the decay rate
of the generator current by using an instanta-
neous overcurrent relay (50) on a flux summation
CT, where the CT window can accommodate
cable from both sides of the generator. The relay
does not respond to generator load current nor to
external fault conditions. The instantaneous
overcurrent relay (50) acts as a phase differential
relay (87) and provides high-speed sensitive pro-
tection. This approach allows for high sensitivity.
For instance, it would be feasible to sense fault
currents as low as 1-5% of generator full load
current. It is common to use 50/5 CTs and to
use 1A nominal relaying. A low CT ratio intro-
duces critical saturation concerns (e.g., a 5,000A
primary fault may try to drive a 500A secondary
on a 50/5 CT). The CT burden must be low to
prevent saturation of the CT during internal faults
that may tend to highly overdrive the CT second-
ary. The 51 relay shown in Fig. 12 is applied for

back-up of external faults and as back-up for the
50 relay.
FIGURE 12. FLUX SUMMATION RELAY (50) PROVIDES
SENSITIVE, HIGH-SPEED, SELECTIVE DIFFERENTIAL
PROTECTION (87).
The 87G relay in Fig. 13 is connected to respond
to phase differential currents from two sets of
CTs. In some applications it may include a unit
differential that includes the step-up transformer.
In contrast to a 51 or 51V relay that monitors
only one CT, the 87G relay responds to both the
generator and external contributions to a genera-
tor fault. Because of the differential connection,
the relay is immune, except for transient CT
saturation effects, to operation due to generator
load flow or external faults and, therefore, can
provide sensitive, high speed protection. While
the CTs must be of the same ratio, they do not
need to be matched in performance, but the
minimum pickup of the Basler BE1-CDS220 or
BE1-87G must be raised as the degree of
performance mismatch increases. (See the BE1-
CDS220 and BE1-87G instruction manuals for
specifics on settings.) A minimum pickup of 0.1
times tap (CDS220) or 0.4A (87G) is representa-
tive of a recommended setting for a moderate
mismatch in CT quality and burden. Fig. 13 also
shows 51V relays to back up the 87G and
external relays and breakers.
FIGURE 13. 87G PROVIDES SENSITIVE, HIGH-SPEED
COVERAGE; 51V PROVIDES BACK-UP FOR 87G AND
FOR EXTERNAL RELAYS. 87G MAY WRAP STEP UP
TRANSFORMER (UNIT DIFFERENTIAL).
Another means to detect external faults is with
impedance relaying. Impedance relaying divides
current by voltage on a complex number plane
(Z = V/Iusing phasor math) (Figs. 14, 15). Such
relaying is inherently faster than time-overcurrent
relaying. In the most common format of imped-
ance relaying, the tripping zone is the area
covered by a "mho" circle on the R-X plane that
has a diameter from the origin (the CT, VT
location) to some remote set point on the R-X
plane. If a fault impedance falls within the zone,
the relay trips. Multiple zones may be used, with
delays on all zones as appropriate for coordinat-
ing with line relays. Impedance relaying is highly
directional. In Fig. 14, however, because the CT
is on the neutral rather than at the VT, the relay
will see faults both in the generator and in the
remote system.
FIGURE 14. IMPEDANCE RELAY, LOOKING FOR
GENERATOR AND REMOTE LINE FAULTS.
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FIGURE 15. IMPEDANCE RELAY, LOOKING FOR
REMOTE LINE FAULTS.
Reverse Power Protection
The reverse-power relay (32) in Fig. 16 senses
real power flow into the generator, which will
occur if the generator loses its prime-mover
input. Since the generator is not faulted, CTs on
either side of the generator would provide the
same measured current.
FIGURE 16. ANTI-MOTORING (32), LOSS-OF-FIELD
(40), PROTECTION.
In a steam-turbine, the low pressure blades will
overheat with the lack of steam flow. Diesel and
gas-turbine units draw large amounts of motoring
power, with possible mechanical problems. In the
case of diesels, the hazard of a fire and/or
explosion may occur due to unburnt fuel. There-
fore, anti-motoring protection is recommended
whenever the unit may be connected to a source
of motoring power. Where a non-electrical type of
protection is in use, as may be the case with a
steam turbine unit, the 32 relay provides a
means of supervising this condition to prevent
opening the generator breaker before the prime
mover has shut down. Time delay should be set
for about 5-30 seconds, providing enough time
for the controls to pick up load upon synchroniz-
ing when the generator is initially slower than the
system.
Since motoring can occur during a large
reactive-power flow, the real power component
needs to be measured at low power factors. The
BE1-32R measures real power down to 0.1 pf.
The BE1-951, BE1-1051, and BE1-GPS measure
real power down to below 0.01 pf, depending on
current magnitude.
Fig. 17 shows the use of two reverse-power
relays: 32-1 and 32-2. The 32-1 relay supervises
the generator tripping of devices that can wait
until the unit begins to motor. Overspeeding on
large steam-turbine units can be prevented by
delaying main and field breaker tripping until
motoring occurs for non-electrical and selected
electrical conditions (e.g., loss-of-field and
overtemperature). Relay 32-1 should be delayed
maybe 3 seconds, while relay 32-2 should be
delayed by maybe 20 seconds. Time delay
would be based on generator response during
generator power swings. Relay 32-2 trips directly
for cases of motoring that were not initiated by
lockout relay 86NE — e.g., governor control
malfunction.
FIGURE 17. REVERSE-POWER RELAY 32-1 PREVENTS
LOAD REJECTION BEFORE PRIME MOVER
SHUTDOWN FOR SELECTED TRIPS; RELAY 32-2
OPERATES IF MOTORING IS NOT ACCOMPANIED BY
AN 86NE OPERATION.
Loss-of-Field Protection
Loss of excitation can, to some extent, be
sensed within the excitation system itself by

monitoring for loss of field voltage or current. For
generators that are paralleled to a power system,
the preferred method is to monitor for loss of
field at the generator terminals. When a genera-
tor loses excitation power, it appears to the
system as an inductive load, and the machine
begins to absorb a large amount of VARs. Loss
of field may be detected by monitoring for VAR
flow or apparent impedance at the generator
terminals.
The power diagram (P-Q plane) of Fig. 18 shows
the Basler BE1-GPS100 and BE1-40Q character-
istic with a representative setting, a representa-
tive generator thermal capability curve, and an
example of the trajectory following a loss of
excitation. The first quadrant of the diagram
applies for lagging power factor operation
(generator supplies VARs). The trajectory starts
at point A and moves into the leading power
factor zone (4th quadrant) and can readily
exceed the thermal capability of the unit. A trip
delay of about 0.2-0.3 seconds is recommended
to prevent unwanted operation due to other
transient conditions. A second high speed trip
zone might be included for severe
underexcitation conditions.
FIGURE 18. FOR LOSS OF FIELD THE POWER
TRAJECTORY MOVES FROM POINT A INTO THE
FOURTH QUADRANT.
When impedance relaying is used to sense loss
of excitation, the trip zone typically is marked by
a mho circle centered about the X axis, offset
from the R axis by X'd/2. Two zones sometimes
are used: a high speed zone and a time delayed
zone.
FIG. 19. LOSS OF EXCITATION USING IMPEDANCE
RELAY.
With complete loss of excitation, the unit will
eventually operate as an induction generator with
a positive slip. Because the unit is running above
synchronous speed, excessive currents can flow
in the rotor, resulting in overheating of elements
not designed for such conditions. This heating
cannot be detected by thermal relay 49, which is
used to detect stator overloads.
Rotor thermal capability can also be exceeded for
a partial reduction in excitation due to an operator
error or regulator malfunction. If a unit is initially
generating reactive power and then draws reactive
power upon loss of excitation, the reactive swings
can significantly depress the voltage. In addition,
the voltage will oscillate and adversely impact
sensitive loads. If the unit is large compared to
the external reactive sources, system instability
can result.
Thermal Protection
Fig. 20 shows the Basler MPS200, BE3-49R, or
BE1-49 relay connected to a resistance-tempera-
ture detector, embedded in a stator slot. Relay
models are available for either copper or platinum
RTDs. The relay provides a constant-current
source to produce a voltage across the RTD and
includes the means to measure that voltage
(proportional to temperature) using separate leads.
The relays have trip and alarm set points, and the
MPS200 can provide readout of present tempera-
ture.
11

12
FIGURE 20. STATOR TEMPERATURE PROTECTION.
Loss of VT Detection
Two methods in common use to detect loss of
VTs are voltage balance between two VTs and
voltage-current comparison logic. Fig. 21 shows
the use of two sets of VTs on the generator
terminals, with the 60FL (Basler BE1-60) com-
paring the output of the two VTs. One set
supplies the voltage regulator, the other, the
relays. If the potential decreases or is lost from
VT No. 1, the BE1-60 disables the voltage
regulator; if source No. 2 fails, the BE1-60
blocks relay tripping of the 21, 27, 59N, and 47.
In some applications 25, 32, and 40 elements
are also blocked. Overexcitation relay (24),
phase overvoltage (59), and frequency relaying
(81), do not need to be blocked, since loss of
potential leads toward non-operation of these
functions.
FIGURE 21. VARIOUS VOLTAGE PROTECTION
ELEMENTS. VOLTAGE-BALANCE RELAY (60)
DETECTS POTENTIAL SUPPLY FAILURE.
A second means of detecting fuse loss is by
comparing voltage and current (Fig. 22). In a
single phase or two phase fuse loss, voltage
imbalance exists without the corresponding
current imbalance that would exist during a fault.
In a three phase fuse loss, complete voltage
loss occurs without the corresponding three
phase current flow that would occur during a
fault. To prevent a 60FL from being declared
during loss of station power, it may be necessary
to allow a 3 phase 60F to be declared only when
some low level of load current exists.
FIGURE 22. LOSS OF FUSE DETECTION, ALTERNATE
METHOD.
Overexcitation and Over/Under Voltage
Protection
Overexcitation can occur due to higher than
rated voltage, or rated or lower voltage at less
than rated frequency. For a given flux level, the
voltage output of a machine will be proportional
to frequency. Since maximum flux level is
designed for normal frequency and voltage, when
a machine is at reduced speed, maximum
voltage is proportionately reduced. A volts/hertz
relay (24) responds to excitation level as it
affects thermal stress to the generator (and to
any transformer tied to that generator). IEEE
C50.13 specifies that a generator should continu-
ously withstand 105% of rated excitation at full
load.
With the unit off line, and with voltage-regulator
control at reduced frequency, the generator can
be overexcited if the regulator does not include
an overexcitation limiter. Overexcitation can also
occur, particularly with the unit off line, if the
regulator is out of service or defective. If voltage-
balance supervision (60) is not provided and a
fuse blows on the regulator ac potential input, the
regulator would cause overexcitation. Loss of ac
potential may also fool the operator into develop-
ing excessive excitation. The 24 relay can only

protect for overexcitation resulting from an
erroneous voltage indication if the 24 relay is
connected to an ac potential source different
than that used for the regulator.
Fig. 23 shows the relation among the Basler
BE1-GPS100, BE1-951, BE1051, and BE1-24
relay inverse squared characteristics and an
example of a generator and transformer with-
stand capability. The generator and transformer
manufacturers should supply the specific
capabilities of these units.
FIGURE 23. COMBINED GENERATOR/TRANSFORMER
OVEREXCITATION PROTECTION USING BOTH THE
INVERSE SQUARED TRIPPING. EQUIPMENT
WITHSTAND CURVES ARE EXAMPLES ONLY.
Phase over (59) and under (27) voltage relaying
also acts as a backup for excitation system
problems. Undervoltage relaying also acts as
fault detection relaying, because faults tend to
depress voltage.
Off-Frequency Operation
Diesel engines can be safely operated off normal
frequency, and minimal protection is required.
Turbine controls generally provide protection for
off frequency conditions, but relaying should be
provided to protect the turbine and generator
during control system failure. Frequency relays
are frequently applied with steam-turbine units,
particularly to minimize turbine blade fatiguing.
IEEE C37.106, Ref. 3 specifically addresses
abnormal frequency operation and shows typical
frequency operating limits specified by various
generator manufacturers. The simplest relay
application would be a single underfrequency
stage, but a multiple stage and multiple set point
arrangement may be advantageous. Each set
point may be set to recognize either over-
frequency or underfrequency. Multiple frequency
set points are available in the BE1-81O/U, BE1-
GPS100, BE1-951, and BE1-1051.
Another common need for frequency relaying is
the detection of generation that has become
isolated from the larger utility system grid. When
a generator is connected to the utility, generator
frequency is held tightly to system frequency.
Upon islanding, the generator frequency varies
considerably as the governor works to adjust
generator power output to local load. If the
generator frequency varies from nominal,
islanding is declared and either the generator is
tripped or the point of common coupling with the
utility is opened.
Inadvertent Energization Protection
Inadvertent energization can result from a
breaker interrupter flashover or a breaker close
initiation while the unit is at standstill or at low
speed. The rapid acceleration can do extensive
damage, particularly if the generator is not
promptly de-energized. While relays applied for
other purposes may eventually respond, they are
not generally considered dependable for respond-
ing to such an energization.
Figs. 24 and 25 show two methods of detecting
the energization of a machine at standstill or at a
speed significantly lower than rated. This could
be caused by single-phase energization due to
breaker-interrupter flashover or 3 phase
energization due to breaker closure. The unit,
without excitation, will accelerate as an
induction motor with excessive current flow in
the rotor. Both Fig. 24 and 25 schemes will
function properly with the VT fuses at the
generator terminal removed. With the generator
off line, safety requirements may dictate the
removal of these VT fuses. In the case of Fig.
13

14
24, the overcurrent protection is enabled by
undervoltage units and works as long as 60FL
logic does not block the trip path. In Fig. 25 the
potential is taken from bus VTs, rather than unit
VTs, so the scheme will function even if the VT
fuses were removed during unit maintenance.
In Fig. 24 the terminal voltage will be zero prior
to energization, so the 27 and 81U relay contacts
will be closed to energize the timer (62). The
instantaneous overcurrent relay (50) trip circuit is
established after timer 62 operates. Upon
inadvertent generator energization, the under-
voltage and underfrequency relay contacts may
open up due to the sudden application of nominal
voltage and frequency, but the delayed dropout
of 62 allows relay 50 to initiate tripping. The use
of a 60FL function or two 27 relays on separate
VT circuits avoids tripping for a VT fuse failure.
Alternatively, a fuse loss detection or voltage-
balance relay (60FL) could be used in conjunc-
tion with a single 27 relay to block tripping.
FIGURE 24. INADVERTENT ENERGIZATION
PROTECTION USING INSTANTANEOUS
OVERCURRENT RELAY (50).
In Fig. 24 the 5 sec pickup delay on timer 62
prevents tripping for external disturbances that
allow dropout of the 27 relays. The 27 relays
should be set at 85% voltage (below the operat-
ing level under emergency conditions). The Fig.
25 scheme could be employed where protection
independent of the plant is desired. In this case
the 67 relays would be placed in the switchyard
rather than in the control room. While directional
overcurrent relay (67) should be delayed to ride
through synchronizing surges, it can still provide
fast tripping for generator faults, since the 67
relays need not be coordinated with external
protection. Fig. 25 shows the operating range for
phase A current (Ia) with respect to phase B to C
voltage (VBC). This range is fixed by the 60
degree characteristic angle and the ±45 degree
limits set on the operating zone.
FIGURE 25. BE1-67 DIRECTIONAL OVERCURRENT
RELAYS DETECT INADVERTENT ENERGIZATION.
Negative Sequence Protection
Negative sequence stator currents, caused by
fault or load unbalance, induce double-
frequency currents into the rotor that may
eventually overheat elements not designed to be
subjected to such currents. Series unbalances,
such as untransposed transmission lines,
produce some negative-sequence current (I2)
flow. The most serious series unbalance is an
open phase, such as an open breaker pole. ANSI
C50.13-1977 specifies a continuous I2withstand
of 5 to 10% of rated current, depending upon the
size and design of the generator. These values
can be exceeded with an open phase on a
heavily-loaded generator. The Basler
BE1-GPS100, BE1-951, BE1-1051, or BE1-46N
relay protects against this condition, providing
negative sequence inverse-time protection
shaped to match the short-time withstand
capability of the generator should a protracted

fault occur. This is an unlikely event, because
other fault sensing relaying tends to clear faults
faster, even if primary protection fails.
Fig. 26 shows the 46 relay connection. CTs on
either side of the generator can be used, since
the relay protects for events external to the
generator. The Basler BE1-46N alarm unit will
alert the operator to the existence of a dangerous
condition.
FIGURE 26. NEGATIVE-SEQUENCE CURRENT RELAY
(46) PROTECTS AGAINST ROTOR OVERHEATING
DUE TO A SERIES UNBALANCE OR PROTRACTED
EXTERNAL FAULT. NEGATIVE SEQUENCE VOLTAGE
RELAY (47) (LESS COMMONLY APPLIED) ALSO
RESPONDS.
Negative sequence voltage (47) protection, while
not as commonly used, is an available means to
sense system imbalance as well as, in some
situations, a misconnection of the generator to a
system to which it is being paralleled.
Out of Step Protection
When a generator pulls out of synchronism with
the system, current will rise relatively slowly
compared to the instantaneous change in current
associated with a fault. The out-of-step relay
uses impedance techniques to sense this
condition. The relay will see an apparent load
impedance swing as impedance moves from
Zone 1 to Zone 2 (Fig. 27). The time it takes for
the load impedance to traverse from Zone 1 to
Zone 2 is used to decide if an out of step
FIGURE 27. OUT OF STEP RELAYING (78)
condition is occurring. A moving impedance is
identified as a swing rather than a fault, so
appropriate fault detection relaying may be
blocked.
Selective Tripping and Sequential Tripping
It is a practice at some generators to selectively
trip the prime mover, the field, and the generator
breaker, depending on the type of fault that is
detected. For instance, if the generator is
protected by a 51V and an 87G, and only the
51V trips, it may be assumed that the fault is
external to the generator and, hence, the 51V
only trips the generator breaker and rapidly pulls
back the excitation governor and prime mover
set points. However, if there is no 87G, the 51V
trips the entire unit. Associated with this concept
is sequential tripping used for orderly shutdown.
To prevent overspeeding a generator during
shutdown, it is sometimes the practice first to
trip the prime mover and trip the main breaker
and field only after a reverse power relay verifies
the prime mover has stopped providing torque to
the generator.
Synchronism Check and Auto Synchronizing
Before connecting a generator to the power
system, it is important that the generator and
system frequency, voltage magnitude, and
phase angle be in alignment, referred to as
synchronism checking (25). Typical parameters
are shown in Fig. 28. Typical applications call for
no more than 6RPM error, 2% voltage magnitude
difference, and no more than 10° phase angle
error before closing the breaker. The Basler
BE1-951, BE1-GPS, and BE1-25 all can perform
the sync check function.
Auto synchronizing (25A) refers to a system to
automatically bring a generator into synchronism
with the power system. It involves sending
voltage and speed raise and lower commands to
the voltage regulator and prime mover governor.
When the system is in synchronism, the
autosync relay is sometimes designed to send a
close command in advance of the zero phase
angle error point to compensate for breaker close
delays. The 25 relay, which usually is set to
supervise the 25A and manual sync function,
usually is set less tight than the 25A so as to
coordinate with the actions of the 25A.
15

FIGURE 28. SYNCHRONIZING PARAMETERS: SLIP,
ADVANCE ANGLE, AND BREAKER CLOSING TIME.
Integrated Application Examples
Figs. 29 through 33 show examples of
protection packages.
Fig. 29 represents bare-minimum protection, with
only overcurrent protection. Generators with such
minimum protection are uncommon in an era of
microprocessor-based multifunction relays. Such
protection likely would be seen only on very
small (<50kVA) generators used for standby
power that is never paralleled with the utility grid
or other generators. It may appear to be a
disadvantage to use CTs on the neutral side as
shown, since the relays may operate faster with
CTs on the terminal side. The increase in speed
would be the result of a larger current contribu-
tion from external sources. However, if the CTs
are located on the terminal side of the generator,
there will be no protection prior to putting the
machine on line. This is not recommended,
because a generator with an internal fault
could be destroyed when the field is applied.
FIGURE 29. EXAMPLE OF BARE-MINIMUM
PROTECTION (LOW-IMPEDANCE GROUNDING).
Fig. 30 shows the suggested minimum protection
with low-resistance grounding. It includes
differential protection, which provides fast,
selective response, but differential protection
becomes less common as generator size
decreases below 2MVA, on 480V units and
below, and on generators that are never paral-
leled with other generation. The differential relay
responds to fault contributions from both the
generator and the external system. While the
differential relay is fast, the slow decay of the
generator field will cause the generator to
continue feeding current into a fault. However,
fast relay operation will interrupt the external-
source contribution, which may be greater than
the generator contribution. Fast disconnection
from the external source allows prompt restora-
tion of normal voltage to loads and may reduce
damage and cost of repairs.
FIGURE 30. SUGGESTED MINIMUM PROTECTION
EXAMPLE (LOW-IMPEDANCE GROUNDING).
The differential relay (87G) may protect for
ground faults, depending upon the grounding
impedance. The 51N relay in Fig. 30 provides
back-up protection for the 87G or will be the
primary protection if the differential relay (87G) is
16

not sufficiently sensitive to the ground current
level.
The 51V voltage-controlled or voltage-restrained
time overcurrent relay in Fig. 30 is shown on the
CT on the high voltage/system side of the
generator. This allows the relay to see system
contributions to a generator fault. It provides
back-up for the differential relay (87G) and for
external relays and breakers. Since it is monitor-
ing CTs on the system side of the generator, it
will not provide any back-up coverage prior to
having the unit on line. If there is no external
source, no 87G, or if it is desired that the 51V
provide generator protection while the breaker is
open, connect the 51V to the neutral-side CTs.
Fig. 30 shows three relays sharing the same CTs
with a differential relay. This is practical with
solid state and numeric relays, because their low
burden will not significantly degrade the quality of
differential relay protection. The common CT is
not a likely point of failure of all connected
relaying. A CT wiring error or CT short is unlikely
to disable both the 87G and 51V relays. Rather,
a shorted CT or defective connection will unbal-
ance the differential circuit and cause the 87G to
trip. Independent CTs could be used to provide
improved back-up protection, although this
seems to be a minimal advantage here. How-
ever, a separate CT is used for the 51N relay
that provides protection for the most likely type
of fault.
The reverse power relay (32) in Fig. 30 protects
the prime mover against forces from a motored
generator and could provide important protection
for the external system if the motoring power
significantly reduces voltage or overloads equip-
ment. Likewise, the loss-of-field relay (40) has
dual protection benefits—against rotor overheat-
ing and against depressed system voltage due to
excessive generator reactive absorption. Ther-
mal relay (49) protects against stator overheating
due to protracted heavy reactive power demands
and loss of generator cooling. Even if the
excitation system is equipped with a maximum
excitation limiter, a failure of the voltage regula-
tor or a faulty manual control could cause
excessive reactive power output. Frequency
relaying (81O/U) protects the generator from off
nominal frequency operation and senses genera-
tor islanding. The under and overvoltage function
(27/59) detects excitation system problems and
some protracted fault conditions.
Fig. 31 shows minimum basic protection for a
medium impedance grounded generator. It differs
from Fig. 30 only in the use of a ground differen-
tial relay (87N, part of CDS220 or BE1-67N). This
protection provides faster clearing of ground
faults where the grounding impedance is too high
to sense ground faults with the phase differential
relay (87G). The relay compares ground current
seen at the generator high voltage terminals to
ground current at the generator neutral. The 51N
relay provides backup for the ground differential
(87N) and for external faults, using the current
polarizing mode. The polarizing winding mea-
sures the neutral current.
FIGURE 31. SUGGESTED MINIMUM PROTECTION
EXAMPLE (MEDIUM-IMPEDANCE GROUNDED).
Fig. 32 shows minimum basic protection for a
high impedance grounded generator. It differs
from Fig. 30 only in the ground relay protection
and the method of grounding. The voltage units
59N/27-3N provide the only ground protection,
since the ground fault current is too small for
phase differential relay (87G) operation. The 59N
relay will not be selective if other generators are
in parallel, since all the 59N relays will see a
ground fault and nominally operate at the same
time. If three Phase-Ground Y-Y VTs were
applied in Fig. 32, the 27 and 59 could provide
additional ground fault protection, and an addi-
tional generator terminal 59N ground shift relay
could be applied.
17

18
FIGURE 32. SUGGESTED MINIMUM PROTECTION
EXAMPLE (HIGH-RESISTANCE GROUNDING).
The Basler BE1-951, BE1-1051, BE1-GPS100,
and BE1-59N include a third harmonic under-
voltage function (27-3N), that provides supervi-
sion of the grounding system, protects for faults
near the generator neutral, and detects a shorted
or open connection in the generator ground
connection or in the distribution transformer
secondary circuit.
FIGURE 33. EXTENDED PROTECTION EXAMPLE (HIGH-RESISTANCE GROUNDING).
Fig. 33 shows the application of additional relays
for extended protection: overexcitation relay (24),
negative sequence overcurrent and overvoltage
relay (46 and 47), ground-overcurrent relay
(51GN), voltage-balance relay (60), field-ground
relay (64F), frequency relay (81) and the 27/50/
62 relay combination for inadvertent energization
protection. Relay 51GN provides a second
means of detecting stator ground faults or faults
in the generator connections or faults in the delta
transformer windings. Differential relay 87T and
sudden-pressure relay 63 protect the unit step-up
transformer. Relay 51N provides backup for ex-
ternal ground faults and for faults in the high-
voltage transformer windings and leads. This
relay may also respond to an open phase con-
dition or a breaker-interrupter flashover that ener-
gizes the generator. The 51N relay will be very
slow for the flashover case, since it must be set
to coordinate with external relays and is a last-
resort backup for external faults.
Figure 33 shows wye-connected VTs, appropri-
ate with an isolated-phase bus.