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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 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.
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 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 (50
I
E, 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
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.
1
The references listed on Page 22 provide more
background on this subject. These documents
also contain Bibliographies for further study.
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).
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, V
FG
in Fig. 1. Assuming an
impedance grounded generator where (Z
0, SOURCE
and Z
N
)>>Z
WINDING
, 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
I
1
in
Fig. 1, lower fault voltage is offset by lower
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
2
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 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 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
I
1
is proportional to percent
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.
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
3
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