NPAG2012 Chap16 469to536

Prévia do material em texto

469NRJED311332EN
Current and Voltag
469 NRJED311332EN
 Energy Automation
Network Protection & Automation Guide
Generator and 
Generator-Transformer 
Protection
470 NRJED311332EN
Generator and 
Generator-Transformer 
Protection 
16 1616 16
Contents
1. Introduction 471
2. Generator earthing 473
3. Stator winding faults 474
4. Stator winding protection 475
5. Differential protection 
of direct-connected generators
476
6. Differential protection 
of generator-transformer units
479
7. Overcurrent protection 480
8. Stator earth fault protection 483
9. Overvoltage protection 492
10. Undervoltage protection 493
11. Low forward power/reverse power protection 494
12. Unbalanced loading 495
13. Protection against inadvertent energisation 498
14. Under/Overfrequency/Overfluxing protection 498
15. Rotor faults 500
16. Loss of excitation protection 504
17. Pole slipping protection 510
18. Overheating 514
19. Mechanical faults 515
20. Complete generator protection schemes 516
21. Embedded generation 519
22. Examples of generator protection settings 523
23. References 536
16 16
471NRJED311332EN
Generator and 
Generator-Transformer 
Protection
16 16
1. Introduction
 
Figure 16.1: 
Generator-transformer unit
The core of an electric power system is the generation. With the 
exception of emerging fuel cell and solar-cell technology for power 
systems, the conversion of the fundamental energy into its electrical 
equivalent normally requires a ‘prime mover’ to develop mechanical 
power as an intermediate stage.
The nature of this machine depends upon the source of energy and 
in turn this has some bearing on the design of the generator. 
Generators based on steam, gas, water or wind turbines, and 
reciprocating combustion engines are all in use. Electrical ratings 
extend from a few hundred kVA (or even less) for reciprocating 
engine and renewable energy sets, up to steam turbine sets 
exceeding 1200MVA.
Small and medium sized sets may be directly connected to a power 
distribution system. A larger set may be associated with an 
individual transformer, through which it is coupled to the EHV 
primary transmission system. 
Switchgear may or may not be provided between the generator and 
transformer. In some cases, operational and economic advantages 
can be attained by providing a generator circuit breaker in addition 
to a high voltage circuit breaker, but special demands will be placed 
on the generator circuit breaker for interruption of generator fault 
current waveforms that do not have an early zero crossing.
A unit transformer may be tapped off the interconnection between 
generator and transformer for the supply of power to auxiliary plant, 
as shown in Figure 16.1. The unit transformer could be of the order 
of 10% of the unit rating for a large fossil-fuelled steam set with 
additional flue-gas desulphurisation plant, but it may only be of the 
order of 1% of unit rating for a hydro set. 
Generator Main transformer
HV busbars
Unit transformer
Auxiliary
supplies switchboard
Industrial or commercial plants with a requirement for steam/hot 
water now often include generating plant utilising or producing 
steam to improve overall economics, as a Combined Heat and 
Power (CHP) scheme. The plant will typically have a connection to 
the public Utility distribution system, and such generation is referred 
to as ‘embedded’ generation. The generating plant may be capable 
of export of surplus power, or simply reduce the import of power 
from the Utility. This is shown in Figure 16.2.
472 NRJED311332EN
Generator and 
Generator-Transformer 
Protection 
16 1616 16
1. Introduction 
 (cont.)
 
Figure 16.2: 
Embedded generation
A modern generating unit is a complex system comprising the 
generator stator winding, associated transformer and unit 
transformer (if present), the rotor with its field winding and excitation 
system, and the prime mover with its associated auxiliaries. Faults 
of many kinds can occur within this system for which diverse forms 
of electrical and mechanical protection are required. The amount of 
protection applied will be governed by economic considerations, 
taking into account the value of the machine, and the value of its 
output to the plant owner.
The following problems require consideration from the point of view 
of applying protection:
a. stator electrical faults
b. overload
c. overvoltage
d. unbalanced loading
e. overfluxing
f. inadvertent energisation
e. rotor electrical faults
f. loss of excitation
g. loss of synchronism
h. failure of prime mover
j. lubrication oil failure
l. overspeeding
m. rotor distortion
n. difference in expansion between rotating and stationary parts
o. excessive vibration
p. core lamination faults
Utility
PCC
Industrial 
plant
main
busbar
Plant feeders - total
demand: xMW
When plant generator is running:
 Plant may export to Utility across PCC
 Plant max demand from Utility is reduced
If
If
PCC: Point of Common Coupling
Generator
Rating: yMW
16 16
473NRJED311332EN
Generator and 
Generator-Transformer 
Protection
16 16
2. Generator Earthing
 
Figure 16.3: 
Methods of generator earthing
The neutral point of a generator is usually earthed to facilitate 
protection of the stator winding and associated system. Earthing 
also prevents damaging transient overvoltages in the event of an 
arcing earth fault or ferroresonance.
For HV generators, impedance is usually inserted in the stator 
earthing connection to limit the magnitude of earth fault current. 
There is a wide variation in the earth fault current chosen, common 
values being:
1. rated current
2. 200A-400A (low impedance earthing)
3. 10A-20A (high impedance earthing)
The main methods of impedance-earthing a generator are shown in 
Figure 16.3. Low values of earth fault current may limit the damage 
caused from a fault, but they simultaneously make detection of a 
fault towards the stator winding star point more difficult. Except for 
special applications, such as marine, LV generators are normally 
solidly earthed to comply with safety requirements. Where a 
step-up transformer is applied, the generator and the lower voltage 
winding of the transformer can be treated as an isolated system that 
is not influenced by the earthing requirements of the power system.
An earthing transformer or a series impedance can be used as the 
impedance. If an earthing transformer is used, the continuous 
rating is usually in the range 5-250kVA. The secondary winding is 
loaded with a resistor of a value which, when referred through the 
transformer turns ratio, will pass the chosen short-time earth-fault 
current. This is typically in the range of 5-20A. The resistor 
prevents the production of high transient overvoltages in the event 
of an arcing earth fault, which it does by discharging the bound 
charge in the circuit capacitance. For this reason, the resistive 
component of fault current should not be less than the residual 
capacitance current. This is the basis of the design, and in practice 
values of between 3-5 are used.
It is important that the earthing transformer never becomes 
saturated; otherwise a very undesirable condition of ferroresonance 
may occur. The normal rise of the generated voltage above the 
rated value caused by a sudden loss of load or by field forcing must 
be considered, as well as flux doubling in the transformer due to the 
point-on-wave of voltage application. It is sufficient that the 
transformer be designed to have a primary winding knee-point 
e.m.f. equal to 1.3 times the generator ratedline voltage.
Typical setting
(% of earthing
resistor rating)
10
5
(b) Resistance earthing
(c) Distribution transformer 
 earthing with overvoltage relay
(d) Distribution transformer 
 earthing with overcurrent relay
(a) Direct earthing
Loading
resistor
Loading
resistor
I>
474 NRJED311332EN
Generator and 
Generator-Transformer 
Protection 
16 1616 16
3. Stator Winding Faults
Failure of the stator windings or connection insulation can result in 
severe damage to the windings and stator core. The extent of the 
damage will depend on the magnitude and duration of the fault 
current.
3.1 Earth Faults
The most probable mode of insulation failure is phase to earth. Use 
of an earthing impedance limits the earth fault current and hence 
stator damage.
An earth fault involving the stator core results in burning of the iron 
at the point of fault and welds laminations together. Replacement of 
the faulty conductor may not be a very serious matter (dependent 
on set rating/voltage/construction) but the damage to the core 
cannot be ignored, since the welding of laminations may result in 
local overheating. The damaged area can sometimes be repaired, 
but if severe damage has occurred, a partial core rebuild will be 
necessary. A flashover is more likely to occur in the end-winding 
region, where electrical stresses are highest. The resultant forces 
on the conductors would be very large and they may result in 
extensive damage, requiring the partial or total rewinding of the 
generator. Apart from burning the core, the greatest danger arising 
from failure to quickly deal with a fault is fire. A large portion of the 
insulating material is inflammable, and in the case of an air-cooled 
machine, the forced ventilation can quickly cause an arc flame to 
spread around the winding. Fire will not occur in a hydrogen-cooled 
machine, provided the stator system remains sealed. In any case, 
the length of an outage may be considerable, resulting in major 
financial impact from loss of generation revenue and/or import of 
additional energy.
3.2 Phase-Phase Faults
Phase-phase faults clear of earth are less common; they may occur 
on the end portion of stator coils or in the slots if the winding 
involves two coil sides in the same slot. In the latter case, the fault 
will involve earth in a very short time. Phase fault current is not 
limited by the method of earthing the neutral point.
3.3 Interturn Faults
Interturn faults are rare, but a significant fault-loop current can arise 
where such a fault does occur. Conventional generator protection 
systems would be blind to an interturn fault, but the extra cost and 
complication of providing detection of a purely interturn fault is not 
usually justified. In this case, an interturn fault must develop into an 
earth fault before it can be cleared. An exception may be where a 
machine has an abnormally complicated or multiple winding 
arrangement, where the probability of an interturn fault might be 
increased.
16 16
475NRJED311332EN
Generator and 
Generator-Transformer 
Protection
16 16
4. Stator Winding Protection
To respond quickly to a phase fault with damaging heavy current, 
sensitive, high-speed differential protection is normally applied to 
generators rated in excess of 1MVA. For large generating units, 
fast fault clearance will also maintain stability of the main power 
system. The zone of differential protection can be extended to 
include an associated step-up transformer. For smaller generators, 
IDMT/instantaneous overcurrent protection is usually the only 
phase fault protection applied. Sections 5 - 8 detail the various 
methods that are available for stator winding protection.
476 NRJED311332EN
Generator and 
Generator-Transformer 
Protection 
16 1616 16
5. Differential Protection of 
 Direct Connected 
 Generators
 
 
Figure 16.4: 
Stator differential protection
Figure 16.5: 
Typical generator biased differential 
protection
The theory of circulating current differential protection is discussed 
fully in Chapter ”Unit Protection of Feeders” (Section 4).
High-speed phase fault protection is provided, by use of the 
connections shown in Figure 16.4. This depicts the derivation of 
differential current through CT secondary circuit connections. This 
protection may also offer earth fault protection for some moderate 
impedance-earthed applications. Either biased differential or high 
impedance differential techniques can be applied. A subtle 
difference with modern, biased, numerical generator protection 
relays is that they usually derive the differential currents and biasing 
currents by algorithmic calculation, after measurement of the 
individual CT secondary currents. In such relay designs, there is 
full galvanic separation of the neutral-tail and terminal CT 
secondary circuits, as indicated in Figure 16.5(a). This is not the 
case for the application of high-impedance differential protection. 
This difference can impose some special relay design requirements 
to achieve stability for biased differential protection in some 
applications.
5.1 Biased Differential Protection
The relay connections for this form of protection are shown in 
Figure 16.5(a) and a typical bias characteristic is shown in Figure 
16.5(b). The differential current threshold setting can be set as 
low as 5% of rated generator current, to provide protection for as 
much of the winding as possible. The bias slope break-point 
threshold setting would typically be set to a value above 
generator rated current, say 120%, to achieve external fault stability 
in the event of transient asymmetric CT saturation. Bias slope 
setting would typically be set at 150%.
5.2 High Impedance Differential Protection
This differs from biased differential protection by the manner in 
which relay stability is achieved for external faults and by the fact 
that the differential current must be attained through the electrical 
connections of CT secondary circuits. If the impedance of each 
relay in Figure 16.4 is high, the event of one CT becoming saturated 
by the through fault current (leading to a relatively low CT 
impedance), will allow the current from the unsaturated CT to flow 
mainly through the saturated CT rather than through the relay. This 
provides the required protection stability where a tuned relay 
element is employed. In practice, external resistance is added to 
the relay circuit to provide the necessary high impedance. 
C
A
B
Stator
(a): Relay connections for biased differential protection
Operate
Restrain
(b) Biased differential operating characteristic
16 16
477NRJED311332EN
Generator and 
Generator-Transformer 
Protection
16 16
5. Differential Protection of 
 Direct Connected 
 Generators (cont.)
The principle of high-impedance protection application is illustrated 
in Figure 16.6, together with a summary of the calculations required 
to determine the value of external stabilising resistance.
In some applications, protection may be required to limit voltages 
across the CT secondary circuits when the differential secondary 
current for an internal phase fault flows through the high impedance 
relay circuit(s), but this is not commonly a requirement for generator 
differential applications unless very high impedance relays are 
applied. 
Where necessary, shunt–connected, non-linear resistors, should 
be deployed, as shown in Figure 16.7. To calculate the primary 
operating current, the following expression is used:
where:
 = primary operating current
 = CT ratio
 = relay setting
 = number of CT’s in parallel with relay element
 = CT magnetising current at Vs
 is typically set to 5% of generator ratedsecondary current.
 
Figure 16.6: 
Principle of high impedance differential 
protection
Healthy CT Saturated CT
Protected zone
Rst
Voltage across relay circuit 
 where 
 Stabilising resistor, , 
 (relay setting)
when = relay burden
limits spill current to
Vs
Is
Rst = -RR
478 NRJED311332EN
Generator and 
Generator-Transformer 
Protection 
16 1616 16
5. Differential Protection of 
 Direct Connected 
 Generators (cont.)
It can be seen from the above that the calculations for the 
application of high impedance differential protection are more 
complex than for biased differential protection. However, the 
protection scheme is actually quite simple and it offers a high level 
of stability for through faults and external switching events.
With the advent of multi-function numerical relays and with a desire 
to dispense with external components, high impedance differential 
protection is not as popular as biased differential protection in 
modern relaying practice.
NLR
 = Stabilising resistor
 = Non-linear resistance
 (Metrosil)
NLRNLR
 
Figure 16.7: 
Relay connections for high impedance 
differential protection
5.3 CT Requirements
The CT requirements for differential protection will vary according to 
the relay used. Modern numerical relays may not require CT’s 
specifically designed for differential protection to IEC 60044-1 class PX 
(or BS 3938 class X). However, requirements in respect of CT 
knee-point voltage will still have to be checked for the specific 
relays used. High impedance differential protection may be more 
onerous in this respect than biased differential protection.
Many factors affect this, including the other protection functions fed 
by the CT’s and the knee-point requirements of the particular relay 
concerned. Relay manufacturers are able to provide detailed 
guidance on this matter.
16 16
479NRJED311332EN
Generator and 
Generator-Transformer 
Protection
16 16
6. Differential Protection of 
 Generator-Transformers
 
Figure 16.8: 
Overall generator-transforme differential 
protection
A common connection arrangement for large generators is to 
operate the generator and associated step-up transformer as a unit 
without any intervening circuit breaker. The unit transformer 
supplying the generator auxiliaries is tapped off the connection 
between generator and step-up transformer. Differential protection 
can be arranged as follows. 
6.1 Generator/Step-up Transformer Differential 
 Protection
The generator stator and step-up transformer can be protected by a 
single zone of overall differential protection (Figure 16.8). This will 
be in addition to differential protection applied to the generator only. 
The current transformers should be located in the generator neutral 
connections and in the transformer HV connections. Alternatively, 
CT’s within the HV switchyard may be employed if the distance is 
not technically prohibitive. Even where there is a generator circuit 
breaker, overall differential protection can still be provided if 
desired.
The current transformers should be rated according to Chapter 
”Differential Protection” (Section 8.2). Since a power transformer is 
included within the zone of protection, biased transformer 
differential protection, with magnetising inrush restraint should be 
applied, as discussed in Chapter ”Differential Protection” (Section 
8.5). Transient overfluxing of the generator transformer may arise 
due to overvoltage following generator load rejection. In some 
applications, this may threaten the stability of the differential 
protection. In such cases, consideration should be given to 
applying protection with transient overfluxing restraint/blocking (e.g. 
based on a 5th harmonic differential current threshold). Protection 
against sustained overfluxing is covered in Section 14.
6.2 Unit Transformer Differential Protection
The current taken by the unit transformer must be allowed for by 
arranging the generator differential protection as a three-ended 
scheme. Unit transformer current transformers are usually applied 
to balance the generator differential protection and prevent the unit 
transformer through current being seen as differential current. An 
exception might be where the unit transformer rating is extremely 
low in relation to the generator rating, e.g. for some hydro 
applications. The location of the third set of current transformers is 
normally on the primary side of the unit transformer. If located on 
secondary side of the unit transformer, they would have to be of an 
exceptionally high ratio, or exceptionally high ratio interposing CT’s 
would have to be used. Thus, the use of secondary side CT’s is not 
to be recommended. One advantage is that unit transformer faults 
would be within the zone of protection of the generator. However, 
the sensitivity of the generator protection to unit transformer phase 
faults would be considered inadequate, due to the relatively low 
rating of the transformer in relation to that of the generator. Thus, 
the unit transformer should have its own differential protection 
scheme. Protection for the unit transformer is covered in Chapter 
”Transformer and Transformer-Feeder Protection””, including 
methods for stabilising the protection against magnetising inrush 
conditions.
Generator
Main
transformer
HV
busbars
Protected zone
480 NRJED311332EN
Generator and 
Generator-Transformer 
Protection 
16 1616 16
7. Overcurrent Protection
Overcurrent protection of generators may take two forms. Plain 
overcurrent protection may be used as the principle form of 
protection for small generators, and back-up protection for larger 
ones where differential protection is used as the primary method of 
generator stator winding protection. Voltage dependent overcurrent 
protection may be applied where differential protection is not 
justified on larger generators, or where problems are met in 
applying plain overcurrent protection.
7.1 Plain Overcurrent Protection
It is usual to apply time-delayed plain overcurrent protection to 
generators. For generators rated less than 1MVA, this will form the 
principal stator winding protection for phase faults. For larger 
generators, overcurrent protection can be applied as remote 
back-up protection, to disconnect the unit from any uncleared 
external fault. Where there is only one set of differential main 
protection, for a smaller generator, the overcurrent protection will 
also provide local back-up protection for the protected plant, in the 
event that the main protection fails to operate. The general 
principles of setting overcurrent relays are given in Chapter 
”Overcurrent Protection for Phase and Earth Faults”.
In the case of a single generator feeding an isolated system, current 
transformers at the neutral end of the machine should energise the 
overcurrent protection, to allow a response to winding fault 
conditions. Relay characteristics should be selected to take into 
account the fault current decrement behaviour of the generator, 
with allowance for the performance of the excitation system and its 
field-forcing capability. Without the provision of fault current 
compounding from generator CT’s, an excitation system that is 
powered from an excitation transformer at the generator terminals 
will exhibit a pronounced fault current decrement for a terminal 
fault. With failure to consider this effect, the potential exists forthe 
initial high fault current to decay to a value below the overcurrent 
protection pick-up setting before a relay element can operate, 
unless a low current setting and/or time setting is applied. The 
protection would then fail to trip the generator. The settings chosen 
must be the best compromise between assured operation in the 
foregoing circumstances and discrimination with the system 
protection and passage of normal load current, but this can be 
impossible with plain overcurrent protection.
16 16
481NRJED311332EN
Generator and 
Generator-Transformer 
Protection
16 16
7. Overcurrent Protection 
 (cont.) 
In the more usual case of a generator that operates in parallel with 
others and which forms part of an extensive interconnected system, 
back-up phase fault protection for a generator and its transformer 
will be provided by HV overcurrent protection. This will respond to 
the higher-level backfeed from the power system to a unit fault. 
Other generators in parallel would supply this current and, being 
stabilised by the system impedance, it will not suffer a major 
decrement. This protection is usually a requirement of the power 
system operator. Settings must be chosen to prevent operation for 
external faults fed by the generator. It is common for the HV 
overcurrent protection relay to provide both time-delayed and 
instantaneous high-set elements. 
The time-delayed elements should be set to ensure that the 
protected items of plant cannot pass levels of through fault current 
in excess of their short-time withstand limits. 
The instantaneous elements should be set above the maximum 
possible fault current that the generator can supply, but less than 
the system-supplied fault current in the event of a generator 
winding fault. This back-up protection will minimise plant damage 
in the event of main protection failure for a generating plant fault 
and instantaneous tripping for an HV-side fault will aid the recovery 
of the power system and parallel generation.
7.2 Voltage-Dependent Overcurrent Protection
The plain overcurrent protection setting difficulty referred to in the 
previous section arises because allowance has to be made both for 
the decrement of the generator fault current with time and for the 
passage of full load current. To overcome the difficulty of 
discrimination, the generator terminal voltage can be measured and 
used to dynamically modify the basic relay current/time overcurrent 
characteristic for faults close to the generating plant. There are two 
basic alternatives for the application of voltage-dependent 
overcurrent protection, which are discussed in the following 
sections. The choice depends upon the power system 
characteristics and level of protection to be provided. Voltage-
dependent overcurrent relays are often found applied to generators 
used on industrial systems as an alternative to full differential 
protection.
482 NRJED311332EN
Generator and 
Generator-Transformer 
Protection 
16 1616 16
 
 
7. Overcurrent Protection 
 (cont.)
Figure 16.9: 
Voltage controlled relay characteristics
Figure 16.10: 
Voltage restrained relay characteristics
7.2.1 Voltage controlled overcurrent protection
Voltage controlled overcurrent protection has two time/current 
characteristics which are selected according to the status of a 
generator terminal voltage measuring element. The voltage 
threshold setting for the switching element is chosen according to 
the following criteria.
1. during overloads, when the system voltage is sustained near 
normal, the overcurrent protection should have a current setting 
above full load current and an operating time characteristic that 
will prevent the generating plant from passing current to a 
remote external fault for a period in excess of the plant short-
time withstand limits
2. under close-up fault conditions, the busbar voltage must fall 
below the voltage threshold so that the second protection 
characteristic will be selected. This characteristic should be set 
to allow relay operation with fault current decrement for a 
close-up fault at the generator terminals or at the HV busbars. 
The protection should also time-grade with external circuit 
protection. There may be additional infeeds to an external 
circuit fault that will assist with grading
Typical characteristics are shown in Figure 16.9.
7.2.2 Voltage restrained overcurrent protection
The alternative technique is to continuously vary the relay element 
pickup setting with generator voltage variation between upper and 
lower limits. The voltage is said to restrain the operation of the 
current element.
The effect is to provide a dynamic I.D.M.T. protection characteristic, 
according to the voltage at the machine terminals. Alternatively, the 
relay element may be regarded as an impedance type with a long 
dependent time delay. In consequence, for a given fault condition, 
the relay continues to operate more or less independently of current 
decrement in the machine. A typical characteristic is shown in 
Figure 16.10.
Current pick-up level
Voltage level
Current pick-up level
Voltage level
16 16
483NRJED311332EN
Generator and 
Generator-Transformer 
Protection
16 16
8. Stator Earth Fault Protection
Earth fault protection must be applied where impedance earthing is 
employed that limits the earth fault current to less than the pick-up 
threshold of the overcurrent and/or differential protection for a fault 
located down to the bottom 5% of the stator winding from the 
star-point. The type of protection required will depend on the 
method of earthing and connection of the generator to the power 
system.
8.1 Direct-Connected Generators
A single direct-connected generator operating on an isolated 
system will normally be directly earthed. However, if several 
direct-connected generators are operated in parallel, only one 
generator is normally earthed at a time. For the unearthed 
generators, a simple measurement of the neutral current is not 
possible, and other methods of protection must be used. The 
following sections describe the methods available.
8.1.1 Neutral overcurrent protection
With this form of protection, a current transformer in the neutral-
earth connection energises an overcurrent relay element. This 
provides unrestricted earth-fault protection and so it must be 
graded with feeder protection. The relay element will therefore 
have a time-delayed operating characteristic. Grading must be 
carried out in accordance with the principles detailed in Chapter 
”Overcurrent Protection for Phase and Earth Faults”. The setting 
should not be more than 33% of the maximum earth fault current of 
the generator, and a lower setting would be preferable, depending 
on grading considerations.
8.1.2 Sensitive earth fault protection
This method is used in the following situations:
a. direct-connected generators operating in parallel
b. generators with high-impedance neutral earthing, the earth fault 
current being limited to a few tens of amps
c. installations where the resistance of the ground fault path is very 
high, due to the nature of the ground
In these cases, conventional earth fault protection as described in 
Section 8.1.1 is of little use.
The principles of sensitive earth fault protection are described in 
Chapter ”Overcurrent Protection for Phase and Earth Fault” 
(Sections 17.1, 18 and 19). The earth fault (residual) current can be 
obtained from residual connection of line CT’s, a line-connected 
CBCT, or a CT in the generator neutral. The latter is not possible if 
directional protection is used. The polarising voltage is usually the 
neutral voltage displacement input to the relay, or the residual of the 
three phase voltages, so a suitable VT mustbe used. For Petersen 
Coil earthing, a wattmetric technique (Chapter ”Overcurrent 
Protection for Phase and Earth Faults” - Section 19) can also be 
used.
484 NRJED311332EN
Generator and 
Generator-Transformer 
Protection 
16 1616 16
8. Stator Earth Fault Protection 
 (cont.)
 
Figure 16.11: 
Comprehensive earth-fault protection 
scheme for direct-connected generators 
operating in parallel
For direct connected generators operating in parallel, directional 
sensitive earth fault protection may be necessary. This is to ensure 
that a faulted generator will be tripped before there is any possibility 
of the neutral overcurrent protection tripping a parallel healthy 
generator. When being driven by residually-connected phase CT’s, 
the protection must be stabilised against incorrect tripping with 
transient spill current in the event of asymmetric CT saturation 
when phase fault or magnetising inrush current is being passed. 
Stabilising techniques include the addition of relay circuit 
impedance and/or the application of a time delay. Where the 
required setting of the protection is very low in comparison to the 
rated current of the phase CT’s, it would be necessary to employ a 
single CBCT for the earth fault protection to ensure transient 
stability.
Since any generator in the paralleled group may be earthed, all 
generators will require to be fitted with both neutral overcurrent 
protection and sensitive directional earth fault protection.
The setting of the sensitive directional earth fault protection is 
chosen to co-ordinate with generator differential protection and/or 
neutral voltage displacement protection to ensure that 95% of the 
stator winding is protected. Figure 16.11 illustrates the complete 
scheme, including optional blocking signals where difficulties in 
co-ordinating the generator and downstream feeder earth-fault 
protection occur.
> >>
Feeder
Block*Block*
Open
* Optional interlocked
earth-fault protection
if grading problems exist
Minimum earth fault level = = 
>
>
>>
>
For cases (b) and (c) above, it is not necessary to use a directional 
facility. Care must be taken to use the correct RCA setting – for 
instance if the earthing impedance is mainly resistive, this should 
be 0°. On insulated or very high impedance earthed systems, an 
RCA of -90° would be used, as the earth fault current is 
predominately capacitive.
16 16
485NRJED311332EN
Generator and 
Generator-Transformer 
Protection
16 16
8. Stator Earth Fault Protection 
 (cont.)
 
Figure 16.12: 
Neutral voltage displacement protection
Directional sensitive earth-fault protection can also be used for 
detecting winding earth faults. In this case, the relay element is 
applied to the terminals of the generator and is set to respond to 
faults only within the machine windings. Hence earth faults on the 
external system do not result in relay operation. However, current 
flowing from the system into a winding earth fault causes relay 
operation. It will not operate on the earthed machine, so that other 
types of earth fault protection must also be applied. All generators 
must be so fitted, since any can be operated as the earthed 
machine.
8.1.3 Neutral voltage displacement protection
In a balanced network, the addition of the three phase-earth 
voltages produces a nominally zero residual voltage, since there 
would be little zero sequence voltage present. Any earth fault will 
set up a zero sequence system voltage, which will give rise to a 
non-zero residual voltage. This can be measured by a suitable 
relay element. The voltage signal must be derived from a VT that is 
suitable – i.e. it must be capable of transforming zero-sequence 
voltage, so 3-limb types and those without a primary earth 
connection are not suitable. This unbalance voltage provides a 
means of detecting earth faults. The relay element must be 
insensitive to third harmonic voltages that may be present in the 
system voltage waveforms, as these will sum residually.
As the protection is still unrestricted, the voltage setting of the relay 
must be greater than the effective setting of any downstream 
earth-fault protection. It must also be time-delayed to co-ordinate 
with such protection. Sometimes, a second high-set element with 
short time delay is used to provide fast-acting protection against 
major winding earth-faults. Figure 16.12 illustrates the possible 
connections that may be used.
3
2
1
Measured from earth impedance2
Measured from broken delta VT 3
Derived from phase neutral voltages1
486 NRJED311332EN
Generator and 
Generator-Transformer 
Protection 
16 1616 16
8. Stator Earth Fault Protection 
 (cont.)
 
Figure 16.13: 
Earth fault protection of high-resistance 
earthed generator stator winding using a 
current element
8.2 Indirectly-Connected Generators
As noted in Section.2, a directly-earthed generator-transformer unit 
cannot interchange zero-sequence current with the remainder of 
the network, and hence an earth fault protection grading problem 
does not exist. The following sections detail the protection methods 
for the various forms of impedance earthing of generators.
8.2.1 High resistance earthing – neutral overcurrent protection
A current transformer mounted on the neutral-earth conductor can 
drive an instantaneous and/or time delayed overcurrent relay 
element, as shown in Figure 16.13. It is impossible to provide 
protection for the whole of the winding, and Figure 16.13 also 
details how the percentage of winding covered can be calculated. 
For a relay element with an instantaneous setting, protection is 
typically limited to 90% of the winding. This is to ensure that the 
protection will not maloperate with zero sequence current during 
operation of a primary fuse for a VT earth fault or with any transient 
surge currents that could flow through the interwinding capacitance 
of the step-up transformer for an HV system earth fault.
a
 Generator stator winding using a current element
16 16
487NRJED311332EN
Generator and 
Generator-Transformer 
Protection
16 16
A time-delayed relay is more secure in this respect, and it may have 
a setting to cover 95% of the stator winding. Since the generating 
units under consideration are usually large, instantaneous and time 
delayed relay elements are often applied, with settings of 10% and 
5% of maximum earth fault current respectively; this is the optimum 
compromise in performance. The portion of the winding left 
unprotected for an earth fault is at the neutral end. Since the 
voltage to earth at this end of the winding is low, the probability of an 
earth fault occurring is also low. Hence additional protection is 
often not applied.
8.2.2 Distribution transformer earthing using a current 
 element
In this arrangement, shown in Figure 16.14(a), the generator is 
earthed via the primary winding of a distribution transformer. The 
secondary winding is fitted with a loading resistor to limit the earth 
fault current. 
Loading
resistor
Loading
resistor
>
(a) Protection using a current element
(b) Protection using a voltage element
 
Figure 16.14: 
Generator winding earth-fault 
protection - distribution transformer 
earthing
8. Stator Earth Fault Protection 
 (cont.)
488 NRJED311332EN
Generator and 
Generator-Transformer 
Protection 
16 1616 16
An overcurrent relay element energised from a current transformer 
connected in the resistor circuit is used to measure secondary earth 
fault current. The relay should have an effective setting equivalent 
to 5% of the maximum earth fault current at rated generator voltage, 
in order to protect 95% of the stator winding. The relay element 
response to thirdharmonic current should be limited to prevent 
incorrect operation when a sensitive setting is applied.
As discussed in Section 8.2.1 for neutral overcurrent protection, the 
protection should be time delayed when a sensitive setting is 
applied, in order to prevent maloperation under transient conditions. 
It also must grade with generator VT primary protection (for a VT 
primary earth fault). An operation time in the range 0.5s-3s is usual. 
Less sensitive instantaneous protection can also be applied to 
provide fast tripping for a heavier earth fault condition. 
8.2.3 Distribution transformer earthing using a voltage 
 element
Earth fault protection can also be provided using a voltage-
measuring element in the secondary circuit instead. The setting 
considerations would be similar to those for the current operated 
protection, but transposed to voltage. The circuit diagram is shown 
in Figure 16.14(b).
Application of both voltage and current operated elements to a 
generator with distribution transformer earthing provides some 
advantages. The current operated function will continue to operate 
in the event of a short-circuited loading resistor and the voltage 
protection still functions in the event of an open-circuited resistor. 
However, neither scheme will operate in the event of a flashover on 
the primary terminals of the transformer or of the neutral cable 
between the generator and the transformer during an earth fault. A 
CT could be added in the neutral connection close to the generator, 
to energise a high-set overcurrent element to detect such a fault, 
but the fault current would probably be high enough to operate the 
phase differential protection.
8.2.4 Neutral voltage displacement protection
This can be applied in the same manner as for direct-connected 
generators (Section 8.1.3). The only difference is that the are no 
grading problems as the protection is inherently restricted. 
A sensitive setting can therefore be used, enabling cover of up to 
95% of the stator winding to be achieved.
8. Stator Earth Fault Protection 
 (cont.)
16 16
489NRJED311332EN
Generator and 
Generator-Transformer 
Protection
16 16
Figure 16.15: 
Low impedance biased REF protection of a 
generator
8.3 Restricted Earth Fault Protection
This technique can be used on small generators not fitted with 
differential protection to provide fast acting earth fault protection 
within a defined zone that encompasses the generator. It is 
cheaper than full differential protection but only provides protection 
against earth faults. The principle is that used for transformer REF 
protection, as detailed in Chapter ”Transformer and Transformer-
Feeder Protection” (Section 7). However, in contrast to transformer 
REF protection, both biased low-impedance and high-impedance 
techniques can be used.
8.3.1 Low-impedance biased REF protection
This is shown in Figure 16.15. The main advantage is that the 
neutral CT can also be used in a modern relay to provide 
conventional earth-fault protection and no external resistors are 
used. Relay bias is required, as described in Chapter ”Unit 
Protection of Feeders” (Section 4.2), but the formula for calculating 
the bias is slightly different and also shown in Figure 16.15.
Neutral CT ratio
200/1
Phase B
Phase C
Phase A
Phase CT ratio 1000/1
(highest of ) + ( x scaling factor)
2
where scaling factor = = = 0.2
neutral CT ratio
phase CT ratio
200
1000
 + (scaling factor x ) 
The initial bias slope is commonly set to 0% to provide maximum 
sensitivity, and applied up to the rated current of the generator. It 
may be increased to counter the effects of CT mismatch. The bias 
slope above generator rated current is typically set to 150% of rated 
value. The initial current setting is typically 5% of the minimum 
earth fault current for a fault at the machine terminals.
 
8. Stator Earth Fault Protection 
 (cont.)
490 NRJED311332EN
Generator and 
Generator-Transformer 
Protection 
16 1616 16
8.3.2 High Impedance REF protection
The principle of high impedance differential protection is given in 
Chapter ”Unit Protection of Feeders” and also described further in 
Section 5.2. The same technique can be used for earth-fault 
protection of a generator, using three residually connected phase 
CT’s balanced against a similar single CT in the neutral connection. 
Settings of the order of 5% of maximum earth fault current at the 
generator terminals are typical. The usual requirements in respect 
of stabilising resistor and non-linear resistor to guard against 
excessive voltage across the relay must be taken, where 
necessary.
8.4 Earth Fault Protection for the Entire Stator 
 Winding
All of the methods for earth fault protection detailed so far leave part 
of the winding unprotected. In most cases, this is of no 
consequence as the probability of a fault occurring in the 5% of the 
winding nearest the neutral connection is very low, due to the 
reduced phase to earth voltage. However, a fault can occur 
anywhere along the stator windings in the event of insulation failure 
due to localised heating from a core fault. In cases where 
protection for the entire winding is required, perhaps for alarm only, 
there are various methods available.
8.4.1 Measurement of third harmonic voltage
One method is to measure the internally generated third harmonic 
voltage that appears across the earthing impedance due to the flow 
of third harmonic currents through the shunt capacitance of the 
stator windings etc. When a fault occurs in the part of the stator 
winding nearest the neutral end, the third harmonic voltage drops to 
near zero, and hence a relay element that responds to third 
harmonic voltage can be used to detect the condition. As the fault 
location moves progressively away from the neutral end, the drop in 
third harmonic voltage from healthy conditions becomes less, so 
that at around 20-30% of the winding distance, it no longer 
becomes possible to discriminate between a healthy and a faulty 
winding. 
Hence, a conventional earth-fault scheme should be used in 
conjunction with a third harmonic scheme, to provide overlapping 
cover of the entire stator winding. The measurement of third 
harmonic voltage can be taken either from a star-point VT or the 
generator line VT. In the latter case, the VT must be capable of 
carrying residual flux, and this prevents the use of 3-limb types. If 
the third harmonic voltage is measured at the generator star point, 
an undervoltage characteristic is used. An overvoltage 
characteristic is used if the measurement is taken from the 
generator line VT. 
8. Stator Earth Fault Protection 
 (cont.)
16 16
491NRJED311332EN
Generator and 
Generator-Transformer 
Protection
16 16
For effective application of this form of protection, there should be 
at least 1% third harmonic voltage across the generator neutral 
earthing impedance under all operating conditions.
A problem encountered is that the level of third harmonic voltage 
generated is related to the output of the generator. The voltage is 
low when generator output is low. In order to avoid maloperation 
when operating at low power output, the relay element can be 
inhibited using an overcurrent or power element (kW, kvar or kVA) 
and internal programmable logic.
8.4.2 Use of low-frequency voltage injection
Another method for protecting the entire stator winding of a 
generator is to deploy signal injection equipment to inject a low 
frequency voltage between the stator star point and earth. An earth 
fault at any winding location will result in the flow of a measurable 
injection current to cause protectionoperation. This form of 
protection can provide earth fault protection when the generator is 
at standstill, prior to run-up. It is also an appropriate method to 
apply to variable speed synchronous machines. Such machines 
may be employed for variable speed motoring in pumped-storage 
generation schemes or for starting a large gas turbine prime mover.
8. Stator Earth Fault Protection 
 (cont.)
492 NRJED311332EN
Generator and 
Generator-Transformer 
Protection 
16 1616 16
Overvoltages on a generator may occur due to transient surges on 
the network, or prolonged power frequency overvoltages may arise 
from a variety of conditions. Surge arrestors may be required to 
protect against transient overvoltages, but relay protection may be 
used to protect against power frequency overvoltages.
A sustained overvoltage condition should not occur for a machine 
with a healthy voltage regulator, but it may be caused by the 
following contingencies:
a. defective operation of the automatic voltage regulator when the 
machine is in isolated operation
b. operation under manual control with the voltage regulator out of 
service. A sudden variation of the load, in particular the reactive 
power component, will give rise to a substantial change in 
voltage because of the large voltage regulation inherent in a 
typical alternator
c. sudden loss of load (due to tripping of outgoing feeders, leaving 
the set isolated or feeding a very small load) may cause a 
sudden rise in terminal voltage due to the trapped field flux and/
or overspeed
Sudden loss of load should only cause a transient overvoltage while 
the voltage regulator and governor act to correct the situation. A 
maladjusted voltage regulator may trip to manual, maintaining 
excitation at the value prior to load loss while the generator supplies 
little or no load. The terminal voltage will increase substantially, and 
in severe cases it would be limited only by the saturation 
characteristic of the generator. A rise in speed simply compounds 
the problem. If load that is sensitive to overvoltages remains 
connected, the consequences in terms of equipment damage and 
lost revenue can be severe. Prolonged overvoltages may also 
occur on isolated networks, or ones with weak interconnections, 
due to the fault conditions listed earlier.
For these reasons, it is prudent to provide power frequency 
overvoltage protection, in the form of a time-delayed element, either 
IDMT or definite time. The time delay should be long enough to 
prevent operation during normal regulator action, and therefore 
should take account of the type of AVR fitted and its transient 
response. Sometimes a high-set element is provided as well, with a 
very short definite-time delay or instantaneous setting to provide a 
rapid trip in extreme circumstances. The usefulness of this is 
questionable for generators fitted with an excitation system other 
than a static type, because the excitation will decay in accordance 
with the open-circuit time constant of the field winding. This decay 
can last several seconds. The relay element is arranged to trip both 
the main circuit breaker (if not already open) and the excitation; 
tripping the main circuit breaker alone is not sufficient.
9. Overvoltage Protection
16 16
493NRJED311332EN
Generator and 
Generator-Transformer 
Protection
16 16
10. Undervoltage Protection
Undervoltage protection is rarely fitted to generators. It is 
sometimes used as an interlock element for another protection 
function or scheme, such as field failure protection or inadvertent 
energisation protection, where the abnormality to be detected leads 
directly or indirectly to an undervoltage condition.
A transmission system undervoltage condition may arise when 
there is insufficient reactive power generation to maintain the 
system voltage profile and the condition must be addressed to 
avoid the possible phenomenon of system voltage collapse.
However, it should be addressed by the deployment of ’system 
protection’ schemes. The generation should not be tripped. The 
greatest case for undervoltage protection being required would be 
for a generator supplying an isolated power system or to meet 
Utility demands for connection of embedded generation (see 
Section 21).
In the case of generators feeding an isolated system, undervoltage 
may occur for several reasons, typically overloading or failure of the 
AVR. In some cases, the performance of generator auxiliary plant 
fed via a unit transformer from the generator terminals could be 
adversely affected by prolonged undervoltage.
Where undervoltage protection is required, it should comprise an 
undervoltage element and an associated time delay. Settings must 
be chosen to avoid maloperation during the inevitable voltage dips 
during power system fault clearance or associated with motor 
starting. Transient reductions in voltage down to 80% or less may 
be encountered during motor starting. 
494 NRJED311332EN
Generator and 
Generator-Transformer 
Protection 
16 1616 16
11. Low Forward Power / 
 Reverse Power Protection
Table 16.1: 
Generator reverse power problems
Low forward power or reverse power protection may be required for 
some generators to protect the prime mover. Parts of the prime 
mover may not be designed to experience reverse torque or they 
may become damaged through continued rotation after the prime 
mover has suffered some form of failure.
11.1 Low Forward Power Protection
Low forward power protection is often used as an interlocking 
function to enable opening of the main circuit breaker for non-
urgent trips – e.g. for a stator earth fault on a high-impedance 
earthed generator, or when a normal shutdown of a set is taking 
place. This is to minimise the risk of plant overspeeding when the 
electrical load is removed from a high-speed cylindrical rotor 
generator. The rotor of this type of generator is highly stressed 
mechanically and cannot tolerate much overspeed. While the 
governor should control overspeed conditions, it is not good 
practice to open the main circuit breaker simultaneously with 
tripping of the prime mover for non-urgent trips. For a steam 
turbine, for example, there is a risk of overspeeding due to energy 
storage in the trapped steam, after steam valve tripping, or in the 
event that the steam valve(s) do not fully close for some reason. 
For urgent trip conditions, such as stator differential protection 
operation, the risk involved in simultaneous prime mover and 
generator breaker tripping must be accepted.
11.2 Reverse Power Protection
Reverse power protection is applied to prevent damage to 
mechanical plant items in the event of failure of the prime mover. 
Table 16.1 gives details of the potential problems for various prime 
mover types and the typical settings for reverse power protection. 
For applications where a protection sensitivity of better than 3% is 
required, a metering class CT should be employed to avoid 
incorrect protection behaviour due to CT phase angle errors when 
the generator supplies a significant level of reactive power at close 
to zero power factor.
The reverse power protection should be provided with a definite 
time delay on operation to prevent spurious operation with transient 
power swings that may arise following synchronisation or in the 
event of a power transmission system disturbance.
Prime 
Mover 
Motoring 
Power (% 
of rated)
Possible 
Damage 
Protection 
Setting
Diesel 
Engine 5 - 25
Fire/
explosion 
due to 
unburnt 
fuel
50% of 
motoring 
power
Mechanical 
damage to 
gearbox/
shafts
Gas 
Turbine
10-15 
(split shaft)
gearbox 
damage> 50% 
(single 
shaft)
Hydro
0.2-2 
(blades out 
of water) blade and 
runner 
cavitation>2 
(blades in 
water)
Steam 
Turbine 0.5 - 6
turbine 
blade 
damage
gearbox 
damage on 
geared sets
16 16
495NRJED311332EN
Generator and 
Generator-Transformer 
Protection
16 16
12. Unbalanced Loading
A three-phase balanced load produces a reaction field that, to a first 
approximation, is constant and rotates synchronously with the rotor 
field system. Any unbalanced condition can be resolved into 
positive, negative and zero sequence components. The positive 
sequence component is similar to the normal balanced load. The 
zero sequence component produces no main armature reaction.
12.1 Effect of Negative Sequence Current
The negative sequence component is similar to the positive 
sequence system, except that the resulting reaction field rotates in 
the opposite direction to the d.c. field system. Hence, a flux is 
produced which cuts the rotor at twice the rotational velocity, 
thereby inducing double frequency currents in the field system and 
in the rotor body. The resulting eddy-currents are very large and 
cause severe heating of the rotor.
So severe is this effect that a single-phase load equal to the normal 
three-phase rated current can quickly heat the rotor slot wedges to 
the softening point. They may then be extruded under centrifugal 
force until they stand above the rotor surface, when it is possible 
that they may strike the stator core.
A generator is assigned a continuous negative sequence rating. 
For turbo-generators this rating is low; standard values of 10% and 
15% of the generator continuous rating have been adopted. The 
lower rating applies when the more intensive cooling techniques 
are applied, for example hydrogen-cooling with gas ducts in the 
rotor to facilitate direct cooling of the winding.
Short time heating is of interest during system fault conditions and it 
is usual in determining the generator negative sequence withstand 
capability to assume that the heat dissipation during such periods is 
negligible. Using this approximation it is possible to express the 
heating by the law:
I t K22 =
where:
 = negative sequence component (per unit of MCR)
 = time (seconds)
 = constant proportional to the thermal capacity of the generator 
 rotor
For heating over a period of more than a few seconds, it is 
necessary to allow for the heat dissipated. From a combination of 
the continuous and short time ratings, the overall heating 
characteristic can be deduced to be:
M
I
I eR
I t KR
= =
−
−( )
2
2
1
1 2
2
where:
 = negative phase sequence continuous rating in per unit of MCR
The heating characteristics of various designs of generator are 
shown in Figure 16.16.
496 NRJED311332EN
Generator and 
Generator-Transformer 
Protection 
16 1616 16
Figure 16.16: 
Typical negative phase sequence current 
withstand of cylindrical rotor generators
12. Unbalanced Loading 
 (cont.)
 
12.2 Negative Phase Sequence Protection
This protection is applied to prevent overheating due to negative 
sequence currents. Small salient-pole generators have a 
proportionately larger negative sequence capacity and may not 
require protection. Modern numerical relays derive the negative 
sequence current level by calculation, with no need for special 
circuits to extract the negative sequence component. A true 
thermal replica approach is often followed, to allow for:
a. standing levels of negative sequence current below the 
continuous withstand capability. This has the effect of 
shortening the time to reach the critical temperature after an 
increase in negative sequence current above the continuous 
withstand capability
b. cooling effects when negative sequence current levels are 
below the continuous withstand capability
The advantage of this approach is that cooling effects are modelled 
more accurately, but the disadvantage is that the tripping 
characteristic may not follow the withstand characteristic specified 
by the manufacturer accurately.
Ti
m
e 
(s
ec
)
0.01
0.01
Negative sequence current (p.u.)
0.1
1
10
100
1000
10000
0.1 1 10
Indirectly cooled (air)
Indirectly cooled (H2)
350MW direct cooled
660MW direct cooled
1000MW direct cooled
Using I t model
Using true thermal
model
2
2
16 16
497NRJED311332EN
Generator and 
Generator-Transformer 
Protection
16 16
12. Unbalanced Loading 
 (cont.)
The typical relay element characteristic takes the form of 
t K
I
I
Iset
e
set=− −











22
2
2
2
1log
...Equation 16.1
where:
set cmr
=
×
= time to trip
 
2
×
 = negative sequence withstand coefficient (Figure 16.16)
 = generator maximum continuous withstand
 = generator rated primary current
 = CT primary current
 = relay rated current
Figure 16.16 also shows the thermal replica time characteristic 
described by Equation 16.1, from which it will be seen that a 
significant gain in capability is achieved at low levels of negative 
sequence current. Such a protection element will also respond to 
phase-earth and phase-phase faults where sufficient negative 
sequence current arises. Grading with downstream power system 
protection relays is therefore required. A definite minimum time 
setting must be applied to the negative sequence relay element to 
ensure correct grading. A maximum trip time setting may also be 
used to ensure correct tripping when the negative sequence current 
level is only slightly in excess of the continuous withstand capability 
and hence the trip time from the thermal model may depart 
significantly from the rotor withstand limits.
498 NRJED311332EN
Generator and 
Generator-Transformer 
Protection 
16 1616 16
13. Protection Against 
 Inadvertent Energisation
Accidental energisation of a generator when it is not running may 
cause severe damage to it. With the generator at standstill, closing 
the circuit breaker results in the generator acting as an induction 
motor; the field winding (if closed) and the rotor solid iron/damper 
circuits acting as rotor circuits. Very high currents are induced in 
these rotor components, and also occur in the stator, with resultant 
rapid overheating and damage. Protection against this condition is 
therefore desirable.
A combination of stator undervoltage and overcurrent can be used 
to detect this condition. An instantaneous overcurrent element is 
used, and gated with a three-phase undervoltage element (fed from 
a VT on the generator side of the circuit breaker) to provide the 
protection. The overcurrent element can have a low setting, as 
operation is blocked when the generator is operating normally. The 
voltage setting should be low enough to ensure that operation 
cannot occur for transient faults. A setting of about 50% of rated 
voltage is typical. VT failure can cause maloperation of the 
protection, so the element should be inhibited under these 
conditions.
14. Under/Overfrequency / 
 Overfluxing Protection
These conditions are grouped together because these problems 
often occur due to a departure from synchronous speed.
14.1 Overfluxing
Overfluxing occurs when the ratio of voltage to frequency is too 
high. The iron saturates owing to the high flux density and results in 
stray flux occurring in components not designed to carry it. 
Overheating can then occur, resulting in damage. The problem 
affects both direct-and indirectly-connected generators. Either 
excessive voltage, or low frequency, or a combination of both can 
result in overfluxing, a voltage to frequency ratio in excess of 
1.05p.u. normally being indicative of this condition. Excessive flux 
can arise transiently, which is not a problemfor the generator. For 
example, a generator can be subjected to a transiently high power 
frequency voltage, at nominal frequency, immediately after full load 
rejection. 
16 16
499NRJED311332EN
Generator and 
Generator-Transformer 
Protection
16 16
14. Under/Overfrequency / 
 Overfluxing Protection 
 (cont.)
Since the condition would not be sustained, it only presents a 
problem for the stability of the transformer differential protection 
schemes applied at the power station (see Chapter ”Transformer 
and Transformer-Feeder Protection”, for transformer protection). 
Sustained overfluxing can arise during run up, if excitation is 
applied too early with the AVR in service, or if the generator is run 
down, with the excitation still applied. Other overfluxing instances 
have occurred from loss of the AVR voltage feedback signal, due to 
a reference VT problem. Such sustained conditions must be 
detected by a dedicated overfluxing protection function that will 
raise an alarm and possibly force an immediate reduction in 
excitation.
Most AVRs’ have an overfluxing protection facility included. This 
may only be operative when the generator is on open circuit, and 
hence fail to detect overfluxing conditions due to abnormally low 
system frequency. However, this facility is not engineered to 
protection relay standards, and should not be solely relied upon to 
provide overfluxing protection. A separate relay element is 
therefore desirable and provided in most modern relays.
It is usual to provide a definite time-delayed alarm setting and an 
instantaneous or inverse time-delayed trip setting, to match the 
withstand characteristics of the protected generator and 
transformer. It is very important that the VT reference for 
overfluxing protection is not the same as that used for the AVR.
14.2 Under/Overfrequency
The governor fitted to the prime mover normally provides protection 
against overfrequency. Underfrequency may occur as a result of 
overload of generators operating on an isolated system, or a 
serious fault on the power system that results in a deficit of 
generation compared to load. This may occur if a grid system 
suffers a major fault on transmission lines linking two parts of the 
system, and the system then splits into two. It is likely that one part 
will have an excess of generation over load, and the other will have 
a corresponding deficit. Frequency will fall fairly rapidly in the latter 
part, and the normal response is load shedding, either by load 
shedding relays or operator action. However, prime movers may 
have to be protected against excessively low frequency by tripping 
of the generators concerned.
With some prime movers, operation in narrow frequency bands that 
lie close to normal running speed (either above or below) may only 
be permitted for short periods, together with a cumulative lifetime 
duration of operation in such frequency bands. This typically occurs 
due to the presence of rotor torsional frequencies in such frequency 
bands. In such cases, monitoring of the period of time spent in 
these frequency bands is required. A special relay is fitted in such 
cases, arranged to provide alarm and trip facilities if either an 
individual or cumulative period exceeds a set time.
500 NRJED311332EN
Generator and 
Generator-Transformer 
Protection 
16 1616 16
15. Rotor Faults
The field circuit of a generator, comprising the field winding of the 
generator and the armature of the exciter, together with any 
associated field circuit breaker if it exists, is an isolated d.c. circuit 
which is not normally earthed. If an earth fault occurs, there will be 
no steady-state fault current and the need for action will not be 
evident.
Danger arises if a second earth fault occurs at a separate point in 
the field system, to cause the high field current to be diverted, in 
part at least, from the intervening turns. Serious damage to the 
conductors and possibly the rotor can occur very rapidly under 
these conditions.
More damage may be caused mechanically. If a large portion of the 
winding is short-circuited, the flux may adopt a pattern such as that 
shown in Figure 16.17. The attracting force at the surface of the 
rotor is given by:
F B A=
2
8π
where:
 = area
 = flux density
It will be seen from Figure 16.17 that the flux is concentrated on one 
pole but widely dispersed over the other and intervening surfaces. 
The attracting force is in consequence large on one pole but very 
weak on the opposite one, while flux on the quadrature axis will 
produce a balancing force on this axis. The result is an unbalanced 
force that in a large machine may be of the order of 50-100 tons. 
A violent vibration is set up that may damage bearing surfaces or 
even displace the rotor by an amount sufficient to cause it to foul the 
stator.
15.1 Rotor Earth-Fault Protection
Two methods are available to detect this type of fault. The first 
method is suitable for generators that incorporate brushes in the 
main generator field winding. The second method requires at least 
a slip-ring connection to the field circuit:
a. potentiometer method
b. a.c. injection method
Short CircuitField Winding
Figure 16.17: 
Flux distribution on rotor with partial 
winding short circuit
 
16 16
501NRJED311332EN
Generator and 
Generator-Transformer 
Protection
16 16
Figure 16.18: 
Earth fault protection of field circuit by 
potentiometer method
Figure 16.19: 
Earth fault protection of field circuit by 
a.c. injection
15. Rotor Faults 
 (cont.)
 
 
15.1.1 Potentiometer method
This is a scheme that was fitted to older generators, and it is 
illustrated in Figure 16.18. An earth fault on the field winding would 
produce a voltage across the relay, the maximum voltage occurring 
for faults at the ends of the winding.
A ‘blind spot’ would exist at the centre of the field winding. To avoid 
a fault at this location remaining undetected, the tapping point on 
the potentiometer could be varied by a pushbutton or switch. The 
relay setting is typically about 5% of the exciter voltage.
Field
winding > Exciter
15.1.2 Injection methods
Two methods are in common use. The first is based on low 
frequency signal injection, with series filtering, as shown in Figure 
16.19(a). It comprises an injection source that is connected 
between earth and one side of the field circuit, through capacitive 
coupling and the measurement circuit. The field circuit is subjected 
to an alternating potential at substantially the same level 
throughout. An earth fault anywhere in the field system will give rise 
to a current that is detected as an equivalent voltage across the 
adjustable resistor by the relay. The capacitive coupling blocks the 
normal d.c. field voltage, preventing the discharge of a large direct 
current through the protection scheme. The combination of series 
capacitor and reactor forms a low-pass tuned circuit, the intention 
being to filter higher frequency rotor currents that may occur for a 
variety of reasons.
Other schemes are based on power frequency signal injection. An 
impedance relay element is used, a field winding earth fault 
reducing the impedance seen by the relay. These suffer the draw 
back of being susceptible to static excitation system harmonic 
currents when there is significant field winding and excitation 
system shunt capacitance.
Greater immunity for such systems is offered by capacitively 
coupling the protection scheme to both ends of the field winding, 
where brush or slip ring access is possible (Figure 16.19(b)).
The low–frequency injection scheme is also advantageous in that 
the current flow through the field winding shunt capacitance will be 
lower than for a power frequencyscheme. Such current would flow 
through the machine bearings to cause erosion of the bearing 
surface. For power frequency schemes, a solution is to insulate the 
bearings and provide an earthing brush for the shaft. 
 L.F. injection
supply
Injection
supply
Exciter
Generator
field
winding
Exciter
Generator
field
winding
>
(a) Low frequency a.c. voltage injection - current measurement
 
<
(b) Power frequency a.c. voltage injection -
 impedance measurement
~
~
502 NRJED311332EN
Generator and 
Generator-Transformer 
Protection 
16 1616 16
15. Rotor Faults 
 (cont.)
15.2 Rotor Earth Fault Protection for Brushless 
 Generators
A brushless generator has an excitation system consisting of:
1. a main exciter with rotating armature and stationary field 
windings
2. a rotating rectifier assembly, carried on the main shaft line out
3. a controlled rectifier producing the d.c. field voltage for the main 
exciter field from an a.c. source (often a small ‘pilot’ exciter)
Hence, no brushes are required in the generator field circuit. All 
control is carried out in the field circuit of the main exciter. Detection 
of a rotor circuit earth fault is still necessary, but this must be based 
on a dedicated rotor-mounted system that has a telemetry link to 
provide an alarm/data.
15.3 Rotor Shorted Turn Protection
As detailed in Section 15 a shorted section of field winding will 
result in an unsymmetrical rotor flux pattern and in potentially 
damaging rotor vibration. Detection of such an electrical fault is 
possible using a probe consisting of a coil placed in the airgap. The 
flux pattern of the positive and negative poles is measured and any 
significant difference in flux pattern between the poles is indicative 
of a shorted turn or turns. Automated waveform comparison 
techniques can be used to provide a protection scheme, or the 
waveform can be inspected visually at regular intervals. An 
immediate shutdown is not normally required unless the effects of 
the fault are severe. The fault can be kept under observation until a 
suitable shutdown for repair can be arranged. Repair will take 
some time, since it means unthreading the rotor and dismantling 
the winding.
Since short-circuited turns on the rotor may cause damaging 
vibration and the detection of field faults for all degrees of 
abnormality is difficult, the provision of a vibration a detection 
scheme is desirable – this forms part of the mechanical protection 
of the generator.
16 16
503NRJED311332EN
Generator and 
Generator-Transformer 
Protection
16 16
15. Rotor Faults 
 (cont.)
15.4 Protection against Diode Failure
A short-circuited diode will produce an a.c. ripple in the exciter field 
circuit. This can be detected by a relay monitoring the current in the 
exciter field circuit, however such systems have proved to be 
unreliable. The relay would need to be time delayed to prevent an 
alarm being issued with normal field forcing during a power system 
fault. A delay of 5-10 seconds may be necessary.
Fuses to disconnect the faulty diode after failure may be fitted. The 
fuses are of the indicating type, and an inspection window can be 
fitted over the diode wheel to enable diode health to be monitored 
manually.
A diode that fails open-circuit occurs less often. If there is more 
than one diode in parallel for each arm of the diode bridge, the only 
impact is to restrict the maximum continuous excitation possible. If 
only a single diode per bridge arm is fitted, some ripple will be 
present on the main field supply but the inductance of the circuit will 
smooth this to a degree and again the main effect is to restrict the 
maximum continuous excitation. The set can be kept running until 
a convenient shutdown can be arranged.
15.5 Field Suppression
The need to rapidly suppress the field of a machine in which a fault 
has developed should be obvious, because as long as the 
excitation is maintained, the machine will feed its own fault even 
though isolated from the power system. Any delay in the decay of 
rotor flux will extend the fault damage. Braking the rotor is no 
solution, because of its large kinetic energy.
The field winding current cannot be interrupted instantaneously as it 
flows in a highly inductive circuit. Consequently, the flux energy 
must be dissipated to prevent an excessive inductive voltage rise in 
the field circuit. For machines of moderate size, it is satisfactory to 
open the field circuit with an air-break circuit breaker without arc 
blow-out coils. Such a breaker permits only a moderate arc voltage, 
which is nevertheless high enough to suppress the field current 
fairly rapidly. The inductive energy is dissipated partly in the arc 
and partly in eddy-currents in the rotor core and damper windings.
With generators above about 5MVA rating, it is better to provide a 
more definite means of absorbing the energy without incurring 
damage. Connecting a ‘field discharge resistor’ in parallel with the 
rotor winding before opening the field circuit breaker will achieve 
this objective. The resistor, which may have a resistance value of 
approximately five times the rotor winding resistance, is connected 
by an auxiliary contact on the field circuit breaker. The breaker duty 
is thereby reduced to that of opening a circuit with a low ratio. 
After the breaker has opened, the field current flows through the 
discharge resistance and dies down harmlessly. The use of a fairly 
high value of discharge resistance reduces the field time constant 
to an acceptably low value, though it may still be more than one 
second. Alternatively, generators fitted with static excitation 
systems may temporarily invert the applied field voltage to reduce 
excitation current rapidly to zero before the excitation system is 
tripped.
504 NRJED311332EN
Generator and 
Generator-Transformer 
Protection 
16 1616 16
16. Loss of Excitation Protection
Loss of excitation may occur for a variety of reasons. If the 
generator was initially operating at only 20%-30% of rated power, it 
may settle to run super-synchronously as an induction generator, at 
a low level of slip. In doing so, it will draw reactive current from the 
power system for rotor excitation. This form of response is 
particularly true of salient pole generators. In these circumstances, 
the generator may be able to run for several minutes without 
requiring to be tripped. There may be sufficient time for remedial 
action to restore the excitation, but the reactive power demand of 
the machine during the failure may severely depress the power 
system voltage to an unacceptable level. For operation at high 
initial power output, the rotor speed may rise to approximately 
105% of rated speed, where there would be low power output and 
where a high reactive current of up to 2.0p.u. may be drawn from 
the supply. Rapid automatic disconnection is then required to 
protect the stator windings from excessive current and to protect 
the rotor from damage caused by induced slip frequency currents.
16.1 Protection against Loss of Excitation
The protection used varies according to the size of generator being 
protected.
16.1.1 Small generators 
On the smaller machines, protection against asynchronous running 
has tended to be optional, but it may now be available by default, 
where the functionality is available within a modern numerical 
generator protection package. If fitted, it is arranged either to 
provide an alarm or to trip the generator. If the generator field 
current can be measured, a relay element can be arranged to 
operate when this drops below a preset value. However, depending 
on the generator design and size relative to the system, it may well 
be that the machine would