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

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Chapter 16  Transformer and Transformer Feeder Protection

16-21

Unit

protection

Secondary ICT'sPrimary ICT's

R=1000A

stab

Yy0

relay

Yd1

600/1

Primary CT's

Yy0, 250/1 Yy0, 600/1

Secondary CT's

FLC = 175A

FLC = 525A

10MVA

33/11kV

Z=10%

Dyn11

Figure 16.28: Transformer unit protection example

16.19.2.1 Ratio compensation

Transformer HV full load current on secondary of main CTs is:

7.0

250

175

Ratio compensation =

428.1

7.0

Select nearest value = 1.43

LV secondary current =

875.0

600

525

Ratio compensation =

14.1

875.0

16.19.2.2 Transformer unit protection settings

A current setting of 20% of the rated relay current is

recommended. This equates to 35A primary current. The

KBCH relay has a dual slope bias characteristic with fixed bias

slope settings of 20% up to rated current and 80% above that

level. The corresponding characteristic is shown in Figure

16.29.

Differential current (A)

Figure 16.29: Transformer unit protection characteristic

16.19.2.3 Restricted earth fault protection

The KBCH relay implements high-impedance Restricted Earth

Fault (REF) protection. Operation is required for a primary

earth fault current of 25% rated earth fault current (i.e. 250A).

The prime task in calculating settings is to calculate the value

of the stabilising resistor

stab

and stability factor

A stabilising resistor is required to ensure through fault stability

when one of the secondary CTs saturates while the others do

not. The requirements can be expressed as:

stabSS

RIV

And



lctfS

RRKIV 2!

where:

= stability voltage setting

= CT knee point voltage

K = relay stability factor

= relay current setting

= CT winding resistance

= CT lead resistance

stab

= stabilising resistor.

For this example:

= 97V

= 3.7

= 0.057

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Network Protection & Automation Guide

16-22

For the relay used, the various factors are related by the graph

of Figure 16.30.

123 4 5 6 7 8 9 10

0.9

0.8

0.7

0.6

0.5

0.4

0.3

0.2

0.1

Overall operation time - milliseconds

K Factor

Overall Op

Time

K Factor

Unstable

Stable

Figure 16.30: REF operating characteristic for KBCH relay

Starting with the desired operating time, the

ratio and

factor can be found.

An operating of 40ms (2 cycles at 50Hz) is usually acceptable,

and hence, from Figure 16.30,

5.0,4 K

The maximum earth fault current is limited by the earthing

resistor to 1000A (primary). The maximum phase fault

current can be estimated by assuming the source impedance

to be zero, so it is limited only by transformer impedance to

5250A, or 10A secondary after taking account of the ratio

compensation. Hence the stability voltage can be calculated



V07.19057.027.3105.0V

uu

Hence,

Calculated

28.7607.194 u

However,

Actual

= 91V and V

= 4.77

Thus from Figure 16.30, with K = 0.5, the protection is

unstable.

By adopting an iterative procedure for values of V

and K,

a final acceptable result of

6.0,55.4 K

obtained. This results in an operating time faster than 40ms.

The required earth fault setting current

is 250A. The

chosen E/F CT has an exciting current

of 1%, and hence

using the equation:



eSop

nIICTratioI u

where:

n = no of CTs in parallel (=4)

= 0.377, use

0.38

nearest settable value.

The stabilising resistance

stab

can be calculated as 60.21:.

The relay can only withstand a maximum of 3kV peak under

fault conditions. A check is required to see if this voltage is

exceeded – if it is, a non-linear resistor, known as a Metrosil,

must be connected across the relay and stabilising resistor.

The peak voltage is estimated using the formula:



KfKP

VVVV  22

where:



stablCTff

RRRIV  2

And

= fault current in secondary of CT circuit and substituting

values,

= 544V. Thus a Metrosil is not required.

16.19.3 Unit Protection for On-Load Tap Changing

Transformer

The previous example deals with a transformer having no taps.

In practice, most transformers have a range of taps to cater for

different loading conditions. While most transformers have an

off-load tap-changer, transformers used for voltage control in

a network are fitted with an on-load tap-changer. The

protection settings must then take the variation of tap-change

position into account to avoid the possibility of spurious trips at

extreme tap positions. For this example, the same transformer

as in Section 16.19.2 will be used, but with an on-load tapping

range of +5% to -15%. The tap-changer is located on the

primary winding, while the tap-step usually does not matter.

16.19.3.1 Ratio correction

In accordance with Section 16.8.4 the mid-tap position is used

to calculate the ratio correction factors. The mid tap position is

–5%, and at this tap position:

Primary voltage to give rated secondary voltage:

= 33 x 0.95 = 31.35kV and Rated Primary Current = 184A

Transformer HV full load current on secondary of main CTs is:

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Chapter 16  Transformer and Transformer Feeder Protection

16-23

737.0

250

184

Ratio compensation =

36.1

737.0

LV secondary current =

875.0

600

525

Ratio compensation =

14.1

875.0

Both of the above values can be set in the relay.

16.19.3.2 Bias slope setting

The on-load tapping range of +5% to -15% gives rise to a

maximum excursion of r10% from the -5% mid-tap position.

As the differential scheme notionally balances at this mid-tap,

this means that as an approximation, the maximum

differential current that can flow when at top or bottom tap is

10% of the load (or fault current which may flow to an external

fault). Those relays having an adjustable k1 bias slope setting

should ensure that it is at least 10% higher than the percentage

excursion.

16.20 TRANSFORMER ASSET MANAGEMENT

Due to the high capital cost of transformers, and the need for

their in-service availability to be as high as possible to avoid

constraining load flows demanded on the network, protection

is no-longer the only concern. As cities expand, consumers’

lifestyle expectations raise, and electric vehicle recharging

loads become more prevalent, these combine to increase the

demand on the network - and it is through the transformers,

between the different voltage levels on the system, that the

demand is traditionally supplied. This increases the focus on

knowing the health of transformers, real-time, to be able to

schedule condition-based maintenance. Maintenance or

reconditioning at a time of the asset-owner’s choosing is far

more preferable than a forced unplanned outage due to failure.

This section provides an overview of techniques commonly

available in modern numerical transformer protection relays,

which can extend to asset management of the protected

transformer.

16.20.1 Loss of life monitoring

Ageing of transformer insulation is a time-dependent function

of temperature, moisture, and oxygen content. The moisture

and oxygen contributions to insulation deterioration are

minimised due to the preservation systems employed in the

design of most modern transformers. Therefore, temperature

is the key parameter in insulation ageing. Frequent excesses

of overloading will shorten the life-expectancy of the

transformer, due to the elevated winding temperatures.

Insulation deterioration is not uniform, and will be more

pronounced at hot-spots within the transformer tank.

Therefore, any asset management system intended to model

the rate of deterioration and current estimated state of the

insulation must do so based on simulated real-time hot spot

temperature algorithms. These models may take ambient

temperature, top-oil temperature, load current flowing, the

status of oil pumps (pumping or not), and the status of

radiator fans (forced cooling or not) as inputs.

The MiCOM P640 provides such a loss of life monitoring

facility, according to the thermal model defined in IEEE

Standard C57.91. The protection algorithm determines the

current rate of losing life, and uses that to indicate the

remaining years or hours until critical insulation health

statuses are likely to be reached. Such criticalities will relate

typically to known percentage degradations in the tensile

strength of the insulation, degradation in the degree of

polymerisation, and other life-loss factors. The asset owner

can be alerted in advance that an outage will be required for

reconditioning or rewinding, such that investment budgeting

can be made years and months ahead of time.

16.20.2 Through-fault monitoring

Loss of life monitoring serves to track the deterioration caused

by long term, repeated overloading. However, it is not the

right technique to monitor short-term heavy fault currents

which flow through the transformer, out to an external fault on

the downstream power system (e.g. fault

in Figure 16.23).

Through faults are a major cause of transformer damage and

failure, as they stress the insulation and mechanical integrity -

such as the bracing of the windings.

A specific through-fault monitor is recommended to monitor

currents which are due to external faults passing through, and

so may range from 3.5 times up to tens of times the rated

current of the transformer. The MiCOM P640 performs an I

calculation when the through current exceeds a user-set

threshold, such that the heating effect of the square of the

maximum phase current, and the duration of the fault event

are calculated. Calculation results are added to cumulative

values, and monitored so that utilities can schedule

transformer maintenance or identify a need for system

reinforcement.

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Alstom Grid 17-1

Chapter 17

Generator and Generator Transformer

Protection

17.1 Introduction

17.2 Generator Earthing

17.3 Stator Winding Faults

17.4 Stator Winding Protection

17.5 Differential Protection of Direct Connected

Generators

17.6 Differential Protection of Generator-

Transformers

17.7 Overcurrent Protection

17.8 Stator Earth Fault Protection

17.9 Overvoltage Protection

17.10Undervoltage Protection

17.11Low Forward Power/Reverse Power Protection

17.12Unbalanced Loading

17.13Protection Against Inadvertent Energisation

17.14Under/Overfrequency/ Overfluxing Protection

17.15Rotor Faults

17.16Loss of Excitation Protection

17.17Pole Slipping Protection

17.18Stator Overheating

17.19Mechanical Faults

17.20Complete Generator Protection Schemes

17.21Embedded Generation

17.22Examples of Generator Protection Settings

17.23Reference

17.1 INTRODUCTION

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 17.1. 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.

Figure 17.1: Generator-transformer unit

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Network Protection & Automation Guide

17-2

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

supply Utility. This is shown in Figure 17.2.

Figure 17.2: 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:

x stator electrical faults

x overload

x overvoltage

x unbalanced loading

x overfluxing

x inadvertent energisation

x rotor electrical faults

x loss of excitation

x loss of synchronism

x failure of prime mover

x lubrication oil failure

x overspeeding

x rotor distortion

x difference in expansion between rotating and stationary

parts

x excessive vibration

x core lamination faults

17.2 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:

x rated current

x 200A-400A (low impedance earthing)

x 10A-20A (high impedance earthing)

The main methods of impedance-earthing a generator are

shown in Figure 17.3. L

ow 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.

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Chapter 17  Generator and Generator Transformer Protection

17-3

Typical setting

(% of earthing

resistor rating)

resistor

(b) Resistance earthing

with overvoltage relay.

(d) Distribution transformer earthing

with overcurrent relay

(a) Direct earthing

resistor

I>>

Figure 17.3: Methods of generator earthing

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 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 I

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 rated line voltage.

17.3 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.

17.3.1 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.

17.3.2 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.

17.3.3 Interturn Faults

Interturn faults are rare, but a significant fault-loop current can

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Network Protection & Automation Guide

17-4

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.

17.4 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 17.5 to 17.8 detail the various methods that are

available for stator winding protection.

17.5 DIFFERENTIAL PROTECTION OF DIRECT

CONNECTED GENERATORS

The theory of circulating current differential protection is

discussed fully in Section 10.4.

High-speed phase fault protection is provided, by use of the

connections shown in Figure 17.4. 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 17.5(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.

Figure 17.4: Stator differential protection

17.5.1 Biased Differential Protection

The relay connections for this form of protection are shown in

Figure 17.5(a) and a typical bias characteristic is shown in

Figure 17.5(b). The differential current threshold setting Is1

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 Is2 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 K2 setting would typically be set at

150%.

bias



III

diff



Figure 17.5: Typical generator biased differential protection

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Chapter 17  Generator and Generator Transformer Protection

17-5

17.5.2 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 17.4 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. The principle

of high-impedance protection application is illustrated in

Figure 17.6, together with a summary of the calculations

required to determine the value of external stabilising

resistance.

CT1

CT2

Healthy CT Saturated CT

Protected zone

Voltage across relay circuit

Stabilising resistor, R

, limits spill current to <I

(relay setting)

where R

= relay burden



st R





rfCT L

VIR R2

and

VKV

dwhere 1.0 K 1.5

Figure 17.6: Principle of high impedance differential protection

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 17.7.

Figure 17.7: Relay connections for high impedance differential

protection

To calculate the primary operating current, the following

expression is used:



esop

nIINI u

where:

= primary operating current

N = CT ratio

= relay setting

n = number of CTs in parallel with relay element

= CT magnetising current at V

is typically set to 5% of generator rated secondary current.

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.

17.5.3 CT Requirements

The CT requirements for differential protection will vary

according to the relay used. Modern numerical relays may not

require CTs 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 CTs and the

knee-point requirements of the particular relay concerned.

Relay manufacturers are able to provide detailed guidance on

this matter.

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17-6

17.6 DIFFERENTIAL PROTECTION OF

GENERATOR-TRANSFORMERS

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.

17.6.1 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 17.8).

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, CTs 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.

Figure 17.8: Overall generator-transformer differential protection

The current transformers should be rated according to Section

16.8.2. 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

Section 16.8.5. 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 5

harmonic differential current threshold). Protection against

sustained overfluxing is covered in Section 17.4.

17.6.2 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 CTs would

have to be used. Thus, the use of secondary side CTs 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 16, including methods for

stabilising the protection against magnetising inrush

conditions.

17.7 OVERCURRENT PROTECTION

Overcurrent protection of generators may take two forms.

Plain overcurrent protection may be used as the principal 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.

17.7.1 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 9.

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

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

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