ALSTOM T&D. Network Protection And Automation Guide (NPAG)

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Chapter 17  Generator and Generator Transformer Protection

17-7

performance of the excitation system and its field-forcing

capability. Without the provision of fault current compounding

from generator CTs, 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

for the 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.

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.

17.7.2 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.

17.7.2.1 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.

x 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

x 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 17.9.

Figure 17.9: Voltage controlled relay characteristics

17.7.2.2 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

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Network Protection & Automation Guide

17-8

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 17.10.

Figure 17.10: Voltage restrained relay characteristics

17.8 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.

17.8.1 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.

17.8.1.1 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 9. 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.

17.8.1.2 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 17.8.1.1 is of little use.

The principles of sensitive earth fault protection are described

in Sections 9.17.1, 9.18 and 9.19. The earth fault (residual)

current can be obtained from residual connection of line CTs, 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 must be used. For Petersen Coil earthing, a

wattmetric technique (Section 9.19) can also be used.

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 CTs, 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 CTs, 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

17.11 illustrates the complete scheme, including optional

blocking signals where difficulties in co-ordinating the

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Chapter 17  Generator and Generator Transformer Protection

17-9

generator and downstream feeder earth-fault protection occur.

Minimum earth fault level = I

rsd

Feeder

Block*

rsd

Open

* Optional interlocked

earth-fault protection

if grading problems exist

ph-n

Figure 17.11: Comprehensive earth-fault protection scheme for

direct-connected generators operating in parallel

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.

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.

17.8.1.3 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 17.12 illustrates the possible connections that

may be used.

Figure 17.12: Neutral voltage displacement protection

17.8.2 Indirectly-Connected Generators

As noted in Section 17.2, 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.

17.8.2.1 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 17.13. It is impossible to

provide protection for the whole of the winding, and Figure

17.13 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

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Network Protection & Automation Guide

17-10

flow through the interwinding capacitance of the step-up

transformer for an HV system earth fault.

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.

%100min)a1(

IsR

mina

u

Figure 17.13: Earth fault protection of high-resistance earthed

generator stator winding using a current element

17.8.2.2 Distribution Transformer Earthing Using a

Current Element

In this arrangement, shown in Figure 17.14(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. 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 third harmonic current should be

limited to prevent incorrect operation when a sensitive setting

is applied.

Figure 17.14: Generator winding earth-fault protection - distribution

transformer earthing

As discussed in Section 17.8.2.1, 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.

17.8.2.3 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 17.14(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

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Chapter 17  Generator and Generator Transformer Protection

17-11

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.

17.8.2.4 Neutral Voltage Displacement Protection

This can be applied in the same manner as for direct-

connected generators (Section 17.8.1.3). 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.

17.8.3 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

Section 16.7. However, in contrast to transformer REF

protection, both biased low-impedance and high-impedance

techniques can be used.

17.8.3.1 Low-Impedance Biased REF Protection

This is shown in Figure 17.15. 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 Section

10.4.2, but the formula for calculating the bias is slightly

different and also shown in Figure 17.15.











 u

DI FF N

highest of I I × scaling fact or

neut ral CT ratio 200

where scaling f act or = = = 0.2

phase CT ratio 1000

I scaling f act or I

BIAS

ABC

,I ,I

III

Figure 17.15: Low impedance biased REF protection of a generator

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.

17.8.3.2 High Impedance REF Protection

The principle of high impedance differential protection is given

in Chapter 10 and also described further in Section 17.5.2.

The same technique can be used for earth-fault protection of a

generator, using three residually connected phase CTs

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.

17.8.4 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.

17.8.4.1 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

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Network Protection & Automation Guide

17-12

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. 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

elements (kW, kVAr or kVA) and internal programmable logic.

17.8.4.2 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 protection operation.

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.

17.9 OVERVOLTAGE PROTECTION

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:

x defective operation of the automatic voltage regulator

when the machine is in

isolated operation

x 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 i

n voltage because of the

large voltage regulation inherent in a typical alternator

x sudden loss of load (due to tripping of outgoing feeders,

leaving the set isolated or feeding a very small load)

may cause a su

dden 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.

17.10 UNDERVOLTAGE PROTECTION

Undervoltage protection was historically 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 the

public Utility demands for connection of embedded generation

(see Section 17.21).

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

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Chapter 17  Generator and Generator Transformer Protection

17-13

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.

17.11 LOW FORWARD POWER/REVERSE

POWER PROTECTION

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.

17.11.1 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.

17.11.2 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 17.1 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.

Table 17.1: Generator reverse power problems

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.

17.12 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.

17.12.1 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.

Prime Mover

Motoring Power

(% of rated)

Possible Damage

Protection

Setting

Fire/explosion due to

unburnt fuel

Diesel Engine 5-25

Mechanical damage to

gearbox/shafts

10-15

(split shaft)

Gas Turbine

>50%

(single shaft)

Gearbox damage

0.2-2

(blades out of water)

Hydro

(blades in water)

Blade and runner cavitation

Turbine blade damage

Steam Turbine 0.5-6

Gearbox damage on geared

sets

50% of motoring

power

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Network Protection & Automation Guide

17-14

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:

KtI

where:

= negative sequence component (per unit of MCR)

t = time (seconds)

K = 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





where:

negative phase sequence continuous rating in per unit of

MCR

The heating characteristics of various designs of generator are

shown in Figure 17.16.

Figure 17.16: Typical negative phase sequence current withstand of

cylindrical rotor generators

17.12.2 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:

x 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 increa

se in negative sequence current above

the continuous withstand capability

x 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.

The typical relay element characteristic takes the form of

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Chapter 17  Generator and Generator Transformer Protection

17-15



1log

set

Equation 17.1

where:

t = time to trip

flc

cmrset

II u

= negative sequence withstand coefficient (Figure 17.16)

2cmr

= generator maximum continuous

withstand

flc

= generator rated primary current

= CT primary current

= Relay rated current

Figure 17.16 also shows the thermal replica time characteristic

described by Equation 17.1, 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.

17.13 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.

17.14 UNDER/OVERFREQUENCY/

OVERFLUXING PROTECTION

These conditions are grouped together because these problems

often occur due to a departure from synchronous speed.

17.14.1 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 problem for the generator. For example, a generator can

be subjected to a transiently high power frequency voltage, at

nominal frequency, immediately after full load rejection. 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

16 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

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Network Protection & Automation Guide

17-16

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.

17.14.2 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.

17.15 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 17.17. The attracting force at

the surface of the rotor is given by:

where:

A = area

B = flux density

It will be seen from Figure 17.17 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

Short CircuitField Winding

Figure 17.17: Flux distribution on rotor with partial winding short

circuit

17.15.1 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:

x Potentiometer method

x A.C. injection method

17.15.1.1 Potentiometer Method

This is a scheme that was fitted to older generators, and it is

illustrated in Figure 17.18. 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

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ALSTOM T&amp;D. Network Protection And Automation Guide (NPAG)

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