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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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