39010139 ABB Transformers Protection Course

7/30/2019 39010139 ABB Transformers Protection Course

1/56

A

BBPowerTechnology

1_1

14Q07-1-

ProtectionsTransformers

Protection


2/56

AB

B

PowerTechnology

1_

11

4Q07-2-

PRINCIPLES

LINES PROTECTION

TRANSFORMERS PROTECTION

INTRODUCTION

SELECTING A PROTECTIVE SYSTEM Differential protection

Sudden pressure relay

Overcurrent protection

Transformer tank protection

Typical protective scheme for power transformers

STATION BUS PROTECTION

AGENDA


3/56

AB

B

PowerTechnology

1_

11

4Q07-3-

PRINCIPLES

LINES PROTECTION


INTRODUCTION

SELECTING A PROTECTIVE SYSTEM Differential protection






AGENDA


4/56

AB

B

PowerTechnology

1_

11

4Q07-4-

EXTERNAL

External Short

Circuits

Overloads Overvoltages

INTERNAL

Short circuits

between turns

between windings Ground faults

Overtemperature

Overpressure

Miss of oil

Introduction. Possible faults in a transformer


5/56

AB

B

PowerTechnology

1_

11

4Q07-5-

INTERNAL

BUCHHOLZ (SPR)

THERMOMETER

THERMOSTAT

THERMAL IMAGE

OIL LEVEL

PRESSURE RELIEF

VALVE

BUCHHOLZ-TAP

CHANGER

ELECTRICAL

SURGE ARRESTERS

OVERCURRENT RELAYS

PHASE

NEUTRAL

DIFFERENTIAL RELAY

THERMAL RELAY

TANK RELAY

FUSES

Introduction. Transformers protections


6/56

AB

B

PowerTechnology

1_

11

4Q07-6-

Magnetizing inrush When a transformer is first energized, a transient magnetizing or

exciting inrush current may flow. This inrush current, which appears as

an internal fault to the differentially connected relays, may reachinstantaneous peaks of 8 to 30 times those for full load.

The factors controlling the duration and magnitude of the magnetizing

inrush are:

Size and location of the transformer bank

Size of the power system

Resistance in the power system from the source to the transformer bank

Type of iron used in the transformer core and its saturation density

Prior history, or residual flux level, of the bank

How the bank is energized


7/56

AB

B

PowerTechnology

1_

11

4Q07-7-

Initial inrush When the excitation of a transformer bank is removed, the magnetizing

current goes to O.

The flux, following the hysteresis loop, then falls to some residual valueR. If the transformer were reenergized at the instant the voltage

waveform corresponds to the residual magnetic density within the core,

there would be a smooth continuation of the previous operation with no

magnetic transient.

In practice, however, the instant when switching takes place cannot be

controlled and a magnetizing transient is practically unavoidable.


8/56

AB

B

PowerTechnology

1_

11

4Q07-8-

Initial inrush If the circuit is re-energized at the instant the flux would normally be at

its negative maximum value (-max) as the residual flux would have a

positive value and since magnetic flux can neither be created nordestroyed instantly, the flux wave, instead of starting at its normal value

(-max) and rising along the dotted line, will start with the residual value

(R) and trance the curve (L).


9/56

AB

B

PowerTechnology

1_

11

4Q07-9-

Initial inrush Curve t is a displaced

sinusoid, regardless of the

magnetic circuit's saturationcharacteristics.

Theoretically, the value of

max is + (|R| + 2|max|).

In transformers designed for

some normal, economicalsaturation density s, the

crest oft will produce super

saturation in the magnetic

circuit.

The result will be a very

large crest value in the

magnetizing current.


10/56

AB

B

PowerTechnology

1_

11

4Q07-10-

Initial inrush

For the first few cycles, the inrush current decays rapidly. Then,

however, the current subsides very slowly, sometimes taking many

seconds if the resistance is low.

The time constant of the circuit (L/R) is not, in fact, a constant: L varies

as a result of transformer saturation. During the first few cycles,

saturation is high and L is low. As the losses damp the circuit, the

saturation drops and L increases. According to a 1951 AIEE report, time

constants for inrush vary from 10 cycles for small units to as much as 1

min for large units.


11/56

AB

B

PowerTechnology

1_

11

4Q07-11-

Initial inrush The resistance from the source to the bank determines the damping of

the current wave.

Banks near a generator will have a longer inrush because theresistance is very low.

Likewise, large transformer units tend to have a long inrush as they

represent a large L relative to the system resistance.

At remote substations, the inrush will not be nearly so severe, since theresistance in the connecting line will quickly damp the current.


12/56

AB

B

PowerTechnology

1_

11

4Q07-12-

Initial inrush When there is more than one delta winding on a transformer bank, the

inrush will he influenced by the coupling between the different voltage

windings. Depending on the core construction, three-phase transformerunits may be subject to interphase coupling that could also affect the

inrush current.

Similar wave shapes would be encountered when energizing the wye

winding of a wye-delta bank, or an autotransformer. Here, the single-

phase shape would be distorted as a result of the interphase couplingproduced by the delta winding (or tertiary).


13/56

AB

B

PowerTechnology

1_

11

4Q07-13-

Initial inrush Maximum inrush will not, of course, occur on every energization.

The probability of energizing at the worst condition is relatively low.

Energizing at maximum voltage will not produce an inrush with no residual.

In a three-phase bank, the inrush in each phase will vary appreciably.

The maximum inrush for a transformer bank can be calculated from the

excitation curve if available, and Table shows a typical calculation of an

inrush current (used phase A voltage as 0 reference).

Peakvalueofinrushcurrent wave(p.u.)S

Closi

angleIa Ib Ic Ia-Ib Ib-Ic Ic-Ia

1. 0 5. -3.73-3. 8.33-3.73-8.31. 30 5.1 1. -5.15.965.10-9.

1. 0 6.5-4.67-4.610. -4.67-10.

1. 30 6. 2. -6.07.836.03-11.


14/56

AB

B

PowerTechnology

1_

11

4Q07-14-

Initial inrush From these calculated values it can be seen that:

The lower the value of the saturation density flux S, the higher the inrush

peak value.

The maximum phase-current inrush occurs at the 0 closing angle (i.e., 0

voltage).

The maximum line-current inrush occurs at 30 closing angles.

Because of the delta connection of transformer winding or currenttransformers, the maximum line-current in-rush value should be

considered when applying current to the differential relay.

Peakvalueofinrushcurrent wave(p.u.)S

Closi

angleIa Ib Ic Ia-Ib Ib-Ic Ic-Ia

1. 0 5. -3.73-3.78.33-3.73-8.

1. 30 5.1 1. -5.15.965.10-9.

1.1 0 6. -4.67-4.610. -4.67-10.

1.1 30 6. 2. -6.07.836.03-11.


15/56

AB

B

PowerTechnology

1_

11

4Q07-15-

Sympathetic inrush When a bank is paralleled with a second energized bank, the energized

bank can experience a sympathetic inrush.

The offset inrush current of the bank being energized will find a parallelpath in the energized bank.

The dc component may saturate the transformer iron. creating an

apparent inrush.

The magnitude of this inrush depends on the value of the transformerimpedance relative to that of the rest of the system, which forms an

additional parallel circuit.

Again, the sympathetic inrush will always be less than the initial inrush.


16/56

AB

B

PowerTechnology

1_

11

4Q07-16-

Sympathetic inrush The total current at breaker C is the sum of the initial inrush of bank A

and the sympathetic inrush of bank B.

Since this waveform looks like an offset fault current, it could causemisoperation if a common set of harmonic restraint differential relays

were used for both banks.

Unit-type generator and transformer combinations have no initial inrush

problem because the unit is brought up to full voltage gradually.

Recovery and sympathetic inrush may be a problem, but as indicated

above, these conditions are less severe than initial inrush.


17/56

AB

B

PowerTechnology

1_

11

4Q07-17-

PRINCIPLES

LINES PROTECTION


INTRODUCTION

SELECTING A PROTECTIVE SYSTEM

Differential protection






AGENDA


18/56

AB

B

PowerTechnology

1_

11

4Q07-18-

87

With internal fault Id > 0 Trip

With external fault Id = 0 No trip

It compares the current entering the transformer with the current

leaving the element.

If they are equal there is no fault inside the zone of protection

If they are not equal it means that a fault occurs between the two ends

Differential relaying for transformer protection


19/56

AB

B

PowerTechnology

1_

11

4Q07-19-

Alternatively one could form an algebraic sum of the two currents

entering the protected element, which could be termed as differentialcurrent (Id), and use a level detector relay to detect the presence of a

fault.

In general this principle is capable of detecting very small

magnitudes of fault.

Its only drawback is that it requires currents from the extremities

of a zone of protection



20/56

AB

B

PowerTechnology

1_11

4Q07-20-

Differential relays are the principal form of fault protection for

transformers rated at 10 MVA and above.

These relays, however, cannot be as sensitive as the differential relaysused for generator protection.

Transformer protection is further complicated by a variety of equipment

requiring special attention: multiple-winding transformer banks, zig-zag

transformers, voltage regulators, transformers in unit systems, and

three-phase trans-former banks with single-phase units.



21/56

ABB

PowerTechnology

1_11

4Q07-21-

Transformer differential relays are subject to several factors, not

ordinarily present for generators or buses, that can cause miss-

operation: Different voltage levels, including taps, that result in different

primary currents in the connecting circuits.

Possible mismatch of ratios among different current transformers.

For units with ratio-changing taps, mismatch can also occur on the taps.Current transformer performance is different, particularly at high

currents.

30 phase-angle shift introduced by transformer wye-delta

connections.

Magnetizing inrush currents, which the differential relay sees asinternal faults.



22/56

ABB

PowerTechnology

1_1

14Q07-22-

Id

(I1 +I2)/2

Operating zone

To prevent miss-operation

percentage characteristics

are used, with line currentrestraint.



23/56

ABB

PowerTechnology

1_1

14Q07-23-

Differential relaying for transformer protection Since the differential relays see the inrush current as an internal fault,

some method of distinguishing between fault and inrush current is

necessary. Such methods include:

A differential relay with reduced sensitivity to the inrush wave (such

units have a higher pickup for the offset wave, plus time delay to

override the high initial peaks).

A harmonic restraint or a supervisory unit used in con-junction with

the differential relay

Desensitization of the differential relay during bank energization.


24/56

ABB

PowerTechnology

1_1

14Q07-24-

Differential relay for transformer protection Induction relays are relatively insensitive

to the high percentage of harmonics

contained in magnetizing inrush current. The relay shown consists of a percentage

differential unit and an indication

contactor switch.

The percentage differential unit, an

induction disc type, has an electromagnet

with poles above and below the disc.

There are two restraint coils on the lower

left-hand pole; the operating coil is wound

on the lower right-hand pole.

Both the left- and right-hand poles have

transformer winding, connected in parallel

to supply current to the upper-pole

windings.


25/56

ABB

PowerTechnology

1_1

14Q07-25-

Differential relay for transformer protection The upper-pole current generates a flux in quadrature with the lower-

pole resultant flux, and the two fluxes react to produce a torque on the

disc. Under normal load or in external fault, the currents in the two restraint

windings flow in the same direction.

These restraining currents are equal (or effectively equal) if auto-

balance taps are used to compensate from mismatch in current

transformer ratios - and if no significant current flows in the operating

coil winding.

As a result, only contact-opening torque is produced.


26/56

ABB

PowerTechnology

1_1

14Q07-26-

Differential relay for transformer protection If the taps are mismatched or the main current transformers saturate

unequally on severe external faults, the effective difference between the

currents in the two restraining windings must flow in the operating coil. The operating coil current required to overcome the restraining torque

and close the relay contacts is a function of the restraining current. For

an internal fault, the restraining currents are opposite, and restraining

torque tends to cancel out.

The more sensitive operating coil, however, is energized by the sum ofthe two currents. As a result, a large amount of contact-closing torque is

produced.


27/56

ABB

PowerTechnology

1_1

14Q07-27-

Differential relay for transformer protection In applying the relay, the current transformer ratio error should not

exceed 10% during maximum symmetrical external fault current. The

relay's 50% characteristic satisfactorily handles up to 35% of currentmismatch, including the transformer tap changing on load and current

transformer mismatch.

The relay's restraining windings have a continuous rating of 10 A; the

operating winding has a continuous rating of 5 A. To prevent

overloading the operating winding, however, no more than 5 A shouldbe allowed in the untapped restraining winding.


28/56

ABB

PowerTechnology

1_1

14Q07-28-

Variable-Percentage Transformer Differential Relay This type of relays have a variable-percentage characteristic:

Percentage is low on light faults, where the current transformer

performance is good, and high on heavy faults, where currenttransformer saturation may occur.

The variable-percentage characteristic is obtained via a saturation

transformer in the operating circuit.

This transformer also tends to shunt the dc component away fromthe operating coil.


29/56

ABB

PowerTechnology

1_1

14Q07-29-

Variable-Percentage Transformer Differential Relay The relay consists of an induction-type differential unit, a dc-indicating

contactor switch, and an optional ac-indicating instantaneous trip unit.

The induction-type differential unit contains four electromagnets,operating on two discs fastened to a common shaft.

Of the electromagnets, one is the operating element and the other three

are restraint elements. On the center leg of each restraint

electromagnet are two primary coils and a secondary coil ; primary coils

are energized from the secondaries of the current transformersconnected to the bank to be protected.


30/56

ABB

PowerTechnology

1_1

14Q07-30-

A 5-A current in the restraint coil will produce restraining torque. The

same 5-A current flowing in two restraint coils of the same restraint

electromagnet will have either additive or subtractive restraining effect,depending on the polarity of the connection (Figure c).

This relay is well suited to protect transformer banks not subject to

severe magnetizing inrush, particularly if more than two restraining

circuits are needed. The relay has no built-in taps and generally

requires auxiliary current transformers for current matching. Theoperating time of the differential unit is two to six cycles; no setting is

required.

The faster IIT unit is connected to the differential circuit. It is

recommended for transformer protection in applications where internal

fault current can exceed twice the maximum total current flowingthrough the differential zone for a symmetrical external fault. The IIT

unit should be set at 50% external fault current or a value higher than

transformer inrush current, whichever is greater.

Variable-Percentage Transformer Differential Relay


31/56

ABB

PowerTechnology

1_1

14Q07-31-

Harmonic restraint Transformer Differential Relay Since magnetizing inrush current has a high harmonic content,

particularly the second harmonic, this second harmonic can be used to

restrain and thus desensitize a relay during energization. The method of harmonic restraint is not without its problems.

There must be enough restraint to avoid relay operation on inrush,

without making the relay insensitive to internal faults that may also have

some harmonic content.


32/56

ABB

PowerTechnology

1_1

14Q07-32-

Harmonic restraint Transformer Differential Relay In the differential unit, (DU) air-gap transformers feed the restraint

circuits, and a non-air-gap transformer energizes the operating coil

circuit. Since the rectified restraint outputs are connected in parallel, the relay

restraint is proportional to the maximum restraining current in any

restraint circuit.


33/56

A

BB

PowerTechnology

1_1

14Q07-33-

Harmonic restraint Transformer Differential Relay The percentage characteristic varies from around 20% on light faults,

where current transformer performance is good, to approximately 60%

on heavy fault, where current transformer saturation may occur. This variable-percentage characteristic is obtained via the saturating

transformer in the operating coil circuit.

The minimum pickup is the current that will just close the differential unit

contacts, with the operating coil and one restraint coil energized.

The continuous rating of the relay is 10 to 22 A, depending on the relay

tap used.


34/56

A

BB

PowerTechnology

1_1

14Q07-34-

Harmonic restraint Transformer Differential Relay The harmonic restraint unit (HRU) has a second-harmonic blocking filter

in the operating coil circuit and a second-harmonic pass filter in the

restraint coil circuit. Thus, the predominant second-harmonic characteristic of an inrush

current produces ample restraint with minimum operating energy.

The circuit is designed to hold open its contacts when the second-

harmonic component is higher than 15% of the fundamental.

This degree of restraint in the HRU is adequate to prevent relay

operation on practically all inrushes, even if the differential unit should

operate.


35/56

A

BB

PowerTechnology

1_1

14Q07-35-

Harmonic restraint Transformer Differential Relay For internal faults, ample operating energy is produced by the

fundamental frequency and harmonic other than the second.

The second harmonic is at a minimum during a fault. Since the HRU willoperate at the same pickup as the DU, the differential unit will operate

sensitively on internal faults.

For external faults, the differential unit (DU) will restrain.

The relay operating time is one cycle at 20 times tap value. The instantaneous trip unit (IIT) is included to ensure high-speed

operation on heavy internal faults, where current transformer saturation

may delay HRU contact closing.

The IIT pickup is 10 times the relay tap value.

This setting will override the inrush peaks and maximum false

differential current on external faults.


36/56

A

BB

PowerTechnology

1_1

14Q07-36-

Transformer Differential Relay Application The following guidelines are designed to assist in selecting and

applying relays for transformer protection.

When two or more relays appear to be equally suitable, engineeringexperience and economics will determine the final choice.

There is no clear-cut answer to the question of which relay or protective

method to apply.

As a general rule, however, the induction-disk differential relays are

used at substations remote from large generating sources where inrush

is not a problem and the kVA size of the bank is relatively small.

The more complex and more expensive harmonic relays are used at

generating stations and for large transformer units located close to

generating sources, where a severe inrush is highly likely.


37/56

A

BB

PowerTechnology

1_1

14Q07-37-

Transformer Differential Relay Application In general, the current transformers on the wye side of a wye-delta

bank must be connected in delta, and the current transformers on

the delta side connected in wye. This arrangement (1) compensates for the 30 phase-angle shift

introduced by the wye-delta bank and (2) blocks the zero sequence

current from the differential circuit on external ground faults.


38/56

A

BB

PowerTechnology

1_1

14Q07-38-

Transformer Differential Relay Application Zero sequence current will flow in the differential circuit for external

ground faults on the wye side of a grounded wye-delta bank; if the

current transformers were connected in wye, the relays would miss-operate.

With the current transformers connected in delta, the zero sequence

current circulates inside the current transformers, preventing relay miss-

operation.


39/56

A

BB

PowerTechnology

1_1

14Q07-39-

Transformer Differential Relay Application Relays should be connected to receive in and out currents that

are in phase for a balanced load condition.

When there are more than two windings, all combinations must beconsidered, two at a time.

Relay taps or auxiliary current transformer ratios should be as close

as possible to the current ratios for a balanced maximum load

condition.

When there are more than two winding, all combinations must he

considered, two at a time, and based on the sane kVA capacity.

Only ground one point in the differential scheme, never do multiple-

point grounding.


40/56

A

BB

PowerTechnology

1_1

14Q07-40-

Transformer Differential Relay Application The percentage of current mismatch should always be checked to

ensure that the relay taps selected have an adequate safety margin.

When necessary, current mismatch values can be reduced bychanging current transformer taps or adding auxiliary current

transformers.


41/56

A

BB

PowerTechnology

1_1

14Q07-41-

PRINCIPLES

LINES PROTECTION


INTRODUCTION








AGENDA


42/56

A

BB

PowerTechnology

1_1

14Q07-42-

Sudden-Pressure Relay (SPR) With the application of a gas-pressure relay, many transformers can be

protected by a simple differential relay set insensitively in the inrush current.

The sudden-pressure relay (SPR), which operates on a rate of rise of gas in thetransformer, can be applied to any trans-former with a sealed air or gas

chamber above the oil level.

The relay is fastened to the tank or manhole cover, above the oil level. It will not

operate on static pressure or pressure changes resulting from normal operation

of the transformer.


43/56

A

BB

PowerTechnology

1_1

14Q07-43-

Sudden-Pressure Relay (SPR) The SPR relay is recommended for all units of 5000 kVA or more.

The SPR relay is far more sensitive to light internal faults than the differential

relay. The differential relay, however, is still required for faults in the bushingand other areas outside the tank.

The SPR relay operating time varies from 1/2 cycle to 37 cycles, depending on

the size of the fault.

In the past, large-magnitude through-fault conditions on power transformers

have caused rate-of-change-of-pressure relays to occasionally operate falsely.There has been reluctance on the part of some users to connect these rate-of-

change-of-pressure relays to trip, and they have therefore used them for

alarming only. Schemes have been devised to restrict tripping of the rate-of-

change-of-pressure device only to levels of current below which the transformer

differential relay cannot operate.


44/56

A

BB

PowerTechnology

1_1

14Q07-44-

PRINCIPLES

LINES PROTECTION


INTRODUCTION








AGENDA


45/56

A

BB

PowerTechnology

1_1

14Q07-45-

Overcurrent and Backup Protection To allow transformer overloading

when necessary, the pickup value of

phase overcurrent relays must be setabove this overload current.

An inverse-time characteristic relay

usually provides the best

coordination.

Settings of 200 to 300% of thetransformer's self-cooled rating are

common, although higher values are

some-times used.

Fast operation is not possible, since

the transformer relays must

coordinate with all other relays they

overreach.

t

iIn n*In

Curva trafo

Reltiem po inv erso

t0

Reltiem po ind epen d.

50/51


46/56

A

BB

PowerTechnology

1_1

14Q07-46-

Overcurrent and Backup Protection Overcurrent relays cannot be used for primary protection without the

risk of internal faults causing extensive damage to the transformer.

Fast operation on heavy internal faults is obtained by usinginstantaneous trip units in the overcurrent relays.

These units may be set at 125% of the maximum through fault, which is

usually a low-side three-phase fault.

The setting should be above the inrush current. Often, instantaneoustrip units cannot be used because the fault currents are too small.

An overcurrent relay set to protect the main windings of an

autotransformer or three-winding transformer offers almost no

protection to the tertiary windings, which have a much smaller kVA.

Also, these tertiary windings may carry very heavy currents duringground faults. In such cases, tertiary overcurrent protection must be

provided.

O d B k P i


47/56

A

BB

PowerTechnology

1_1

14Q07-47-

Overcurrent and Backup Protection A through fault external to a transformer results in an overload that can

cause transformer failure if the fault is not cleared promptly.

It is widely recognized that damage to transformers from through faultsis the results of thermal and mechanical effects.

The thermal effect has been well understood for years.

The mechanical effect has recently gained increased recognition as a major

concern of transformer failure.

This results from the cumulative nature of some of the mechanical effects,

particularly insulation compression, insulation wear, and friction-induced

displacement.

The damage that occurs as a result of these cumulative effects is a function

of not only the magnitude and duration of through faults, but also the total

number of such faults.

O t d B k P t ti


48/56

A

BB

PowerTechnology

1_1

14Q07-48-

Overcurrent and Backup Protection The transformer can be isolated from the fault before damage occurs by

using fuses or overcurrent relays.

50/51N

50/51G

2-3 50/51

Di t R l i f B k P t ti


49/56

A

BB

PowerTechnology

1_1

14Q07-49-

Distance Relaying for Backup Protection Directional distance relaying can be used for transformer backup

protection when the setting or coordination of the overcurrent relays is a

problem. The directional distance relays are connected to operate when the fault

current flows toward the protected transformer.

They are set to reach into, but not beyond, the transformer.

AGENDA


50/56

A

BB

PowerTechnology

1_1

14Q07-50-

PRINCIPLES

LINES PROTECTION


INTRODUCTION








AGENDA

T f T k t ti


51/56

A

BB

PowerTechnology

1_1

14Q07-51-

Transformer Tank protection

This is a low cost protection against some of the internal faults of the

transformer, which consists of an overcurrent relay which measures

the current flow through the ground connection of the transformer tank.

It detects hence the ground faults of the transformer and bushings

trough the metallic tank.

To achieve this the transformer must be completely isolated from

ground (putting some isolating material under the transformerwheels), and a toroid current transformer is needed surrounding the

only ground connection cable.

64

T f T k t ti


52/56

A

BB

PowerTechnology

1_1

14Q07-52-

Transformer Tank protection

To prevent incorrect tripping (because of possible faults in the

connection cables to fans, etc) it is necessary to take some measure

as the indicated in fig, and to coordinate with the neutral protection.

AGENDA


53/56

A

BB

PowerTechnology

1_1

14Q07-53-

PRINCIPLES

LINES PROTECTION


INTRODUCTION








AGENDA

T i l t ti h f t f


54/56

A

BB

PowerTechnology

1_1

14Q07-54-

Typical protective scheme for power transformers Figure illustrates how a primary

breaker can be used for

transformer protection. The basic protection is provided

by the 87T transformer differential

relays.

Device 50/51, an inverse-time

relay with IIT unit, providestransformer primary winding

backup protection for phase

faults;

either device 50G (with a zero

sequence current transformer) or50N/51N can be used as

transformer primary winding

backup for ground faults.



55/56

A

BB

PowerTechnology

1_1

14Q07-55-

Typical protective scheme for power transformers Transformer overload, low-voltage

bus, and feeder backup protection

are provided by device 51 on thetransformer secondary side.

Since the low-voltage side is

medium-resistance-grounded, a

ground relay (51G) should be used

to trip breaker 52-1 for low-sideground faults and for resistor

thermal protection.

Device 151G, which trips breaker

52-11, provides feeder ground

backup, whereas device 63, suchas a type SPR relay, offers highly

sensitive protection for light faults.



56/56

B

PowerTechnology

4Q07-56-

Typical protective scheme for power transformers The current transformer ratings in

this scheme should be compatible

with the transformer short-timeoverload capability: approximately

200% of transformer selfcooled

rating for wye-connected current

transformers and 350% ( 200%)

for delta-connected current

transformers.

The neutral current transformer

rating should be 50% of the

maximum resistor current rating.

39010139 ABB Transformers Protection Course

Documents

Transcript of 39010139 ABB Transformers Protection Course