Transformer Protection Training 1

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TRINIDAD&TOBAGOELECTRICITYCOMMISSIONPROTECTIONANDSCADADEPARTMENT

TECHNICALTRAINING

To Manager Protection and SCADADepartment

Origin: Jason Chin SangReview: Jason Chin Sang

Issue Date: AUG. 2008Review Date: AUG. 2009

Number:

Title TRANSFORMER PROTECTION.


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Table Of Contents

1

Forword............................................................................................................................ 4

2 Introduction...................................................................................................................... 43

General principles............................................................................................................. 7

4 Differential protection....................................................................................................... 84.1 Percent Differential Protection................................................................................... 104.2 Advantage of Percent Differential Relays.................................................................... 104.3

Defining the Restraint Current................................................................................... 11

4.4

CT Saturation and the Dual Slope............................................................................... 15

4.5 System Error............................................................................................................. 164.6

Choosing the Percent Slope........................................................................................ 17

4.6.1 THE BREAKPOINT:............................................................................................. 174.6.2 SLOPE 1:............................................................................................................. 174.6.3

SLOPE 2:............................................................................................................. 18

4.6.4 Choosing the Basic PickUp Current (System Error)............................................. 19

4.7 Multitap Differential Relays...................................................................................... 204.8

Instantaneous Highset Differential Relays.................................................................. 21

4.9

Exciting Current Consideration.................................................................................. 21

4.10

Magnetic Inrush on Bank Energization.................................................................... 224.10.1

The DC Offset................................................................................................... 25

4.10.2 The Second Harmonic...................................................................................... 264.10.3 The Third Harmonic........................................................................................ 264.10.4

Higher harmonics............................................................................................ 26

4.11

Magnetic Inrush On Paralleled Transformer Energization....................................... 27

4.12 Relay Restraint....................................................................................................... 274.13

CT Connections...................................................................................................... 294.14 Choosing CT Ratios................................................................................................. 324.15 Computing the Current Transformer Ratio Relationship.......................................... 32

4.15.1

Example Computation...................................................................................... 34

4.16

Two Winding Percent Differential Relay for Three winding Transformers................ 35

4.17 Problems with Differential Relays........................................................................... 385

Application Considerations.............................................................................................. 39

5.1

Influence of Winding Connections and Earthing on Earth Fault Current...................... 39

5.1.1 Fault on wye winding.......................................................................................... 405.1.2

Fault on Delta Winding........................................................................................ 42

5.1.3 Types of Delta Connections................................................................................. 435.1.4 CT Connection for Zig Zag Transformer............................................................... 44

5.2 Master Ground.......................................................................................................... 456

Restricted Earth Fault Protection (REF)........................................................................... 46

6.1 Guidelines for the design parameters and set point for REF protection........................ 486.1.1 Determination of Stability................................................................................... 496.1.2

Current Transformer Requirements.................................................................... 49

6.1.3 Setting Resistor................................................................................................... 496.1.4

Non Linear Resistor............................................................................................ 50


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6.1.5

Worked Example Protection of Power Transformer HV Delta Winding Using A REFElement of an ARGUS Relay.............................................................................................. 516.1.6

Amount of Winding Protected against Earth Faults.............................................. 56

7

Short Circuit Protection with Overcurrent Relays............................................................. 58

8 Other Schemes................................................................................................................ 598.1

Standby Earth Fault................................................................................................... 59

8.2 Tank Leakage Protection........................................................................................... 598.3 Overfluxing Protection............................................................................................... 608.4

Circulating currents in parallel banks......................................................................... 61

8.5

Gas Protection........................................................................................................... 61

8.6 The Pressure Relief Device (PRD).............................................................................. 638.7 Winding temperature and Oil temperature Protection................................................ 648.8

Earthing Transformer Protection............................................................................... 67

8.9 Plain Balance Scheme................................................................................................ 688.10

Combined Scheme when Earthing Reactor is Included in the Protection Zone.......... 69

8.11

Combined line and transformer schemes................................................................ 70

9 Functional circuit Design................................................................................................. 719.1 the single line schematic............................................................................................ 719.2

the ac schematic........................................................................................................ 71

9.3

the dc schematic........................................................................................................ 71

10

RELAYS IN service........................................................................................................ 7610.1 The GE745 Differential Relay.................................................................................. 76

10.1.1 Unit Withdrawal and Insertion......................................................................... 7610.1.2

Front Panel Interface....................................................................................... 79

10.1.3

Rear View........................................................................................................ 83


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1

FORWORD

This document seeks to describe the schemes for transformer protection which exists, some ofwhich are used by the Protection and SCADA Department of the Trinidad and Tobago Electricity

Commission. This document is designed to expose the second year EngineerinTraining to boththe theory and application aspects of transformer protection.

2

INTRODUCTION

Among the abnormal conditions affecting power transformers, there are five common kinds,namely, short circuits, open circuits, overheating, over voltages and under frequency. Generallyspeaking, relay protection is not provided against open circuits because they are not harmful in

themselves and are statistically improbable. It is possible however, that sustained zero sequencecurrent in the delta tertiary winding due to an open phase condition left undetected may beabove the rating.

Furthermore, sustained overloading of a transformer will cause its temperature to rise toabnormal levels, which can result in insulation degradation. In oil immersed transformers,failures of fans, pumps or blockages in the radiators due to the buildup of sludge will also causeabnormal temperature rise within the transformer. For that matter, overheating or overloadprotection is also provided allowing full advantage to be taken of the transformer overloadcapacity. At transformer stations, there may be controls to send an alarm or to control pumpsand banks of fans for cooling purposes but without tripping the breakers to isolate the

transformer. Further increase in temperature may trip load side breakers preventing furthertemperature rise.

Horn gap protectors and lightning arresters provide protection against transient over voltagessuch as those caused by lightning strikes and switching operations. These cause endturnstresses and possible insulation breakdown. Lightning protection is beyond the scope of thistechnical document and will not be discussed. Power frequency over voltages are also prevalentand are caused by the sudden loss of load on the system. This condition causes over fluxing of thetransformer and an increase in stress on the winding insulation. Over fluxing increases ironlosses and may result in a large increase in exciting current. Such conditions result in rapidheating of the iron circuits of the transformer, with possible damage to core lamination

insulation and even winding insulation.

Under frequency is also cause by a major system disturbance when there is not enoughgeneration to meet the load, e.g. the sudden loss of generation. At low frequencies the excitingcurrent of the transformer is greatly increased. The hysteresis loop widens as frequency falls.This also causes over fluxing of the transformer iron circuits.

A transformer may be able to continue operation at either condition but if the two conditions areexperienced at the same time, this may lead to a disastrous outcome. Hence Voltage per Hertz


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protection is sometimes provided. Usually the ratio of Voltage to frequency should not exceed 1.1volts per hertz.

When a short circuit occurs (external or internal to the transformer) the high current cause largemechanical stresses within the transformer. The largest mechanical force is experienced withinthe first half cycle of the fault and this short time frame makes it impossible to protect againstthis condition. The protection strategy for this is therefore a matter of transformer design.

There remains the protection against faults in the transformers or their connections such aswinding short circuits and incipient faults.

The majority of internal faults, which occur within the winding, are either earth faults (note theHV winding is usually wound over the LV winding which is closest to the core; as such the HVwinding is that which is closest to the transformers earthed frame, and is the winding which islikely to flash to earth) or interturn faults, the severity of which depends on the design of thetransformer and the method of system earthing. Phase faults within the winding are rare, andwhere singlephase transformers are operated in three phase banks, are impossible. The maincauses of phase faults are bushing flashovers and faults in tap change equipment.

Incipient faults are internal faults that are not detectable at the transformer terminals, whichconstitute no immediate hazard. However, if they are left undetected they may develop into amajor fault. The purpose of providing protection against these failures is to limit the damage,such that the transformer can be repaired without an extended outage. The main faults in thisgroup are core faults, due to insulation failure between core laminations, and interturn coilinsulation failure due to degradation of the paper insulation.

Interturn coil faults are unlikely in low voltage (pole & pad mount) transformers unless the

windings have been damaged mechanically by large through currents due to external faults,which can crack the insulation.

For highvoltage transformers connected to a high voltage system, the unit is likely to bedamaged by steep front travelling waves or impulses (switching and lightning) that can be muchhigher than the rated transformer voltage. The risk of interturn flashover is greatest in the endof the winding which are prone to failure for this type of event. Shorting a few turns will causelarge fault currents to flow in the shorted section, but the terminal currents will not be greatlyaffected, making detection difficult. It is claimed that up to 80% of all highvoltage transformerfailures are due to this cause.

Another subcategory of short circuit faults is the CORE fault. The transformer core laminationsare carefully insulated from each other to prevent eddy currents from crossing the gap betweenadjacent laminations. Even the bolts that clamp the laminations together are insulated from eachof the laminations to prevent the bolts from causing a magnetic short across the laminations. Anyoverheating or over fluxing of the transformer provides the possibility of causing a magneticshort of this kind due to the deterioration of the insulation between laminations or around bolts.

Such a shorted path will allow eddy currents to flow, and will greatly increase the core losses andcause localized heating to occur. This condition does not greatly affect the terminal currents of


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the transformer, making this type of fault difficult to detect by electrical relays connected to theterminals.

The Buchholz device is a major protection device for oil immersed conservator typetransformers. It has the ability to detect both high energy and low energy internal faults.

For oil immersed nitrogen cushioned sealed tank transformers, a pressure sensitive device isalso applicable.

It is important to recognize that no single protection element can fully cater for the range ofabnormal conditions which can result. In the event that any element within the full transformerprotection scheme shall be inoperable, it is the remaining protections and the risk of damagewhich can result if a particular fault condition shall develop, which are the factors for decidingthe acceptable risk.


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3 GENERALPRINCIPLES

To provide a transformer bank adequate protection against internal faults, a number ofprotections are necessary. The basic philosophy of protective devices is different for incipientfaults than active faults.

Active fault protection must be fast to isolate the unit in order to minimize the effect of thedisturbance on the system, minimize damage to the equipment and prevent injury to personnelwho are in the vicinity.

Incipient faults do not require fast detection and equipment isolation. These faults developslowly and there is time for careful observation and testing. Moreover, these faults are usuallynot protected by the same devices used for active fault detection.

The exception to this philosophy is perhaps the Buchholz, which has elements to detect bothincipient and active fault conditions.

A differential protection is provided on most transformers rated above 3MVA. This does notmean that a differential protection would not be applied to a smaller capacity transformer. Thedecision to use a full range of protection elements is based on the relative importance of thetransformer. For example, a factory may have a 1MVA transformer for its operations, the loss ofwhich will mean the hault of production until it is replaced. Hence, though the company can payfor a replacement, the lead time to delivery may lead to a loss which cannot be withstood by thecompany.

Restricted ground fault protection is provided, and is sensitive enough to operate on internalground faults even where the transformer is grounded through high impedance.

In addition to a main gas protection, if the transformer is equipped with an onload tap changer, aseparate surge protection is provided.

A pressure relief device (PRD) may also be provided to prevent tank rupture on severe internalfaults.

External shortcircuits may only be limited by the transformer reactance and where this is low,fault currents may be excessive. The duration of external short circuits, limited only by thetransformer reactance, which a transformer can sustain without damage are quoted from BS

1711936:Transformer % Reactance Permitted Fault Duration (sec)4 25 36 47 & over 5For this reason a separate backup overcurrent protection may be graded with downstreamequipment.


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4

DIFFERENTIALPROTECTION

Differential protection is defined as a protection that operates when the vectorial difference(orsum) of two or more electrical quantities of the same type exceeds a predetermined value.

Differential protection derives its name from the type of connection that is used to comparequantities at two or more points of the protected equipment. It is probably true that most activefaults involve arching to ground, and can probably be cleared by ground relays. Still, thedifferential protection relay predominates as the preferred active fault detection method forpower transformers.

Any type of current measuring relay, when suitably connected, can be operated as differentialprotection. Most differential protection applications are of the current differential type.

Consider the simple example shown in the following figures.

Suppose current flows through the protected zone to a load or to a fault outside of the protectedzone of the differential protection, the conditions will be as depicted by the arrows in the figurebelow. I.e. the current will flow around the CTs and not through the operating coil of the relay.

Defining the current entering the protected equipment as the reference, a phasor diagram for thesystem of currents would be as shown.

IA or IBIa or Ib

IA IB

IaIb

Node


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Hence, using KCL; the sum of currents entering the node is equal to the sum of currents leavingthe node.

0

operate0 0 A=Ia bI I

Should a fault, however, develop anywhere between the two CTs, i.e. within the protected zoneof the differential protection, then current will flow through the operating coil, as shown in thefollowing figure and cause the operation of the relay if its value exceeds the set point of the relay.

operate setpoint. . if I Ii e


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4.1

PERCENTDIFFERENTIALPROTECTION

One type of differential relay is the percent differential. This is essentially the same as the basictype of differential relay except for the addition of restraint coils. It has a rising pickup asopposed to an absolute pick up current.

If we define the set point of the relay as a ratio of the difference current to the restraint (circuit)current, then as the circuit current increases, the current required to operate the relay will alsoincrease.

Protected Equipment

Relay Coil

No current flows through

the operating coil

i1-i2

i1 i2

I1 I2

4.2

ADVANTAGEOFPERCENTDIFFERENTIALRELAYS.

The advantage of a percent differential relay is that it is less likely to operate incorrectly when afault occurs external to the protected zone. It is therefore considered to be more stable.

There are three sources of error that can lead to unbalances in the CT secondarycurrents:

1. Errors in the CT transformation.2. The changing ratio of the power transformer, due to the onload tap changer, without any

compensation for the fixed CT ratios.

3. Mismatch between the CT currents and the relay tap rating for electromechanical relays.

Current transformers of the types normally used for transformerdifferentialprotectionmay nottransform their primary current accurately under fault conditions. They are often of differenttypes and have dissimilar magnetization characteristics, resulting in spill currents. This isparticularly true when a short circuit current is offset (transientandsub-transientshortcircuitcurrents) causing saturation of the magnetic core. Under such conditions, supposedly identicalcurrent transformers may not have identical secondary currents and a spill is produced. Thegreater the short circuit current, the greater will be the difference current. Since the percent


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differential relay has a rising pickup characteristic, as the magnitude of the through currentincreases, the relay is restrained against improper operation. That is, the pickup currentincreases with the through current, thereby providing security against erroneous operationwhenever difference current results.

Consider a unit being protected where the overload into the equipment is 100A. CTs would formthe boundaries for the zone of protection. If each CT has a maximum error of 10% at a current ofup to 20 times its rating (10P20), then the maximum error current from each CT is 10A.Assuming a +10A on CT1 and a 10A error on CT2, the maximum error spill is 20A. Hence, onemay anticipate that an overcurrent relay set with a pickup current greater than 20 A may besufficient.

Consider now if there is an external fault of 1000A, CT1 output may correspond to 1050A whileCT2 output may correspond to 950A. Both CTs are within their 10% error specification but therelay will operate spuriously due to the spill being greater than 20A. This operation would not bedesirable.

Increasing the set point current of an overcurrent relay will desensitize the relay for lowlevelinternal faults and hence this is not a viable option for the detection of such faults.

The solution is to have an operating characteristic that is sensitive to differences at low currentlevels, yet secure at high current levels. A percent differential characteristic is thus used. Thischaracteristic is plotted on an XY graph with the vectorial current difference (Id) on the Yaxisand a restraining current (IR) plotted on the Xaxis. The restraining current is that value whichrepresents the magnitude of the current flowing into, out of, or through the equipment beingprotected.

Stability is also achieved for CT ratio mismatches that occur due to the operation of the onloadtap changer (OLTC). If the CT % error is large compared to the maximum deviation due to the onload tap changer, then this factor is negligible as demonstrated later on.

4.3

DEFININGTHERESTRAINTCURRENT.

Refer to the previous figure. The differential current in the operating coil is I1I2. The equivalent

current in the restraint coil is

2

21 II since the operating coil is connected to the midpoint of

the restraint coil for the circuit shown. Consider in this example if N is the number of turns onthe restraint coil, which is the same as the number of turns on the operating coil, the restraining

ampereturns would be

22

21 NINI . This is equivalent to

2

21 II flowing through the entire

coil. This is by no means the only way to define the restraint current.


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The restraint coil receives currents proportional to the current flowing to the protectedequipment and produces contact opening torque, while the operating coil receives currentproportional to the fault or difference current flowing into the equipment and produces contactclosing torque. Consider a multi restraint circuit relay for a three winding transformer. Therestraining currents are I1, I2, and I3, while the differential current is the KCL vectorial differenceof I1, I2, and I3.

Operating Coil

Restraint Coil

Restraint CoilRestraint Coil

I1

I2

I3

I1+I2+I3

The operating current is readily agreed upon but the restraining currents are subject to a varietyof interpretations. The common definition of restraining current considers the average of thethrough current flowing through the restraint coils.

There are several accepted definitions for calculating the restraining current. There is noadvantage to using one method over another. However, the amount restrain provided by thedifferent methods differ significantly, particularly where there is multipoint equipmentprotection such as in bus protection.

The Sumofmethod

nR IIIII ...321

The ScaledSumofmethod

nR IIII

nI ...

1

321

The GeometricAveragemethodn

nR IIIII ...321

The Maximumofmethod

1 2 3, , ,...,R nI Max I I I I


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Before the percent differential is calculated the maximum error of the CTs must be plotted on theId IRgraph as a slope. Hence if the maximum error of the CTs is 10% then a slope of 20% mustbe plotted.

Id

IR

20% slope for CT error

OPERATE

NON-OPERATE

Any reading above the slope is in the operate region, while any below is in the nonoperateregion.

The percent differential is then calculated as 10021 xI

II

R

.

Hence for a 1000A fault, as for our example, using the Maximum of method for the restraintcurrent, IR= 1050A. 21 II is 100A since I1and I2are measured by the relay from the CTs. The

calculated differential is then

100 9.52%. This is below the 20% set point and the relay

will not operate.


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Slope is the ratio of the differential current to cause relay operation to the restraining current. Inthe basic percent differential relay, the ratio of the differential operating current to the restraintcurrent is a fixed value, giving a slope of a particular gradient in the relays operatingcharacteristic.

In practice, many transformer percent differential relays have a variable percentagecharacteristic as shown in the next figure, selectable by some adjustment; so that one of severalslopes can be chosen over a given range of through restrain currents.

I1-I2

I1+I2

2 Intelligent Electronic Device (IED) type percent differential relays may employ the technique ofallowing the user to set the slope, of the relay characteristics between restraint current values,giving a characteristic having two slopes as shown in the next figure.

I1-I2

I1+I2

2

K1

K2


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4.4

CTSATURATIONANDTHEDUALSLOPE

Bus and transformer fault currents tend to be very large and hence we must be concerned withthe possibility of CT saturation.

The 10% error is the maximum error if the CT does not go into saturation, i.e. if the CT operatesin its linear region. However during through faults, one CT may saturate before the other andboth may saturate to different degrees as no two CTs can match perfectly. For example CT1 mayhave 65% saturation while CT2 has 50% saturation. The worstcase spill for a through faultcondition will exist if one CT (say CT1) saturates completely while the other (CT2) does not.

Once one of the CTs starts to saturate, an additional Spurious current will be measured by therelay. Note that even when a fault occurs that results in deep CT saturation, the CT will initiallystep down the current correctly. The operating points initial trajectory is such that it willdepart from the prefault position and shift to the right as shown with the green arrow. Once theCTs go into saturation the measured current and hence the restraining signal decreases. Thiscauses the operating point to shift up and to the left as shown by the red arrow. With sufficientsaturation the operating point could enter the elements operate region, resulting in a maloperation.

Id

IR


Normal Trajectory

Spurious Current

To provide greater stability under large through fault conditions the element can utilize asteeper slope beyond a defined breakpoint. The resulting characteristic is a dual slope percentdifferential characteristic.


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Id

IR


Breakpoint

90% slope for CT Saturation

(Maximum Overload Curerent)

4.5

SYSTEMERROR

Under normal operating Conditions it was found that the element could maloperate underextremely light load conditions due to system error. System error is the cumulative error of theCTs and the analogtodigital converters within the relay. The total of this is typically close to therated CT error. It is possible that a very small current flow can be registered in one restraint coiland the operating coil with comparatively negligible current flow being registered through thesecond restraint coil. To eliminate the possibility of maloperation under such conditions, theelement has a setting for the minimum differential error to cause operation.

Id

IR


Breakpoint

90% slope for CT Saturation

(Maximum Overload Curerent)

Min Valueto cause Operation


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4.6

CHOOSINGTHEPERCENTSLOPE.

The set points for this characteristic are calculated as follows:

4.6.1 THEBREAKPOINT:

If using the Maximum of method for the restraint current calculation, the breakpoint is set to acurrent just above the overload current of the device being protected. The breakpoint in terms ofthe restraint current must be calculated for the other definitions of restraint current assuming amaximum through current of 40% overload.

4.6.2 SLOPE1:

The normal maximum setting of slope 1 is the cumulative rated error of the CTs. For example, iftwo CTs have a maximum error of 10% the slope would be set at 20%.However if the maximum fault current will generate a voltage that is less than or equal to half the

knee point voltage of the CTs, it is common practice to reduce the CTs rated error by half.Therefore the CT maximum error would be 5% and the slope 10%. This provides greatersensitivity for lowlevel faults.

The slope setting is further complicated by the existence of the OnLoadTapChanger. Unbalancein the secondary outputs of the differential zone CTs may be caused by the tap changer of thepower transformer. Many power transformers have taps at the extreme that would give plus orminus k percent change in transformer ratio based on the mid tap. This means that themaximum error that can occur is k%.

CT ratios are however chosen to balance the secondary currents at a value equal to or slightly

higher than the relay rated current considering a load equal to the emergency rating of the bank(normally 1.4 x forced cooled rating of the bank on the T&TEC system), with the tap changer atits midpoint of the tap changer range. The unbalance that can occur from tap changer operationneeds to be determined for maximum stability.

Since the CT ratios are fixed, and there is known CT error, the maximum primary HV sideequivalent spill can be determined. This maximum spill expressed as a ratio of the restraintcurrent for the maximum tap changer deviation, gives the required slope setting.

For example consider a 66/33 kV transformer with 21 tap positions having a midtap of 11 witha 1.25% voltage variance between taps. Hence the tap changer has a range of (10x1.25)%. The

maximum ratio error will result when the Transformer is at Tap 21 not 1, since this will result inthe maximum secondary current while Tap 1 will result in the minimum secondary current.

Since there are 10 steps between 11 and 21 the power transformer ratio changes by (10 * 1.25)12.5%.

Using a primary CTR of 100/1 and a secondary CTR of 200/1, both with 10% error. If X ampsflows through the HV primary, the error current is (X * 0.1). The error current of the LVsecondary assuming the transformer is at tap 21, is:


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66 1 0.1250.1

33

2 1 0.125 0.1

X

X

Factoring the CT ratios on either side of the TF the LV spill referenced to the HV side of the TF(via the CT secondary circuits) becomes:

1 1002 1 0.125 *0.1* *

200 1

1 0.125 *0.1

X

X

The maximum total Spill current in primary terms is

0.1* * 1 1 0.125X

*0.1* 2.125X

The maximum spill at nominal tap is *0.1*2X . Hence the operation of the tap changer hasonly increased the spill by an additional (10 X 1.25%) 12.5%.

Assuming any load current for our example (say X=100A primary HV), the HV primary referredspill will be 21.25 A.

Assuming also the CT error current is additive on the primary will yield 110A seen by the relay. Ifinstead, we assume the error is additive on the secondary, this will yield

66*1.125 100100 100*0.1* * 111.2533 200

A, referred to the HV primary.

Assuming then, the HV primary referred spill is subtractive; giving 90A, and the CT error isadditive on the secondary of the power transformer, gives a spill of 21.25 A. Using also aMaximum of method for restraint, the restraint current is 111.25 A. The required slope is thus21.25

*100 19.1%111.25

. This is a negligible change in slope and hence 20% can be used.

4.6.3

SLOPE2:Using the maximum fault level from the fault study, the maximum CT saturation can bedetermined by testing the CTs. The second slope is then plotted such that the element will notoperate under worstcase calculated CT saturation conditions. If we are to assume a worst casewhere one CT fully saturates and the other does not, then using the Maximum of method thesecond slope would be 100%.


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4.6.4 ChoosingtheBasicPick-UpCurrent(SystemError)

Historically this setting has been described as the minimum operating current required to causethe tripping when current appears in only one restraint coil and the operating coil (restraint andoperating registers as in the case of IEDs). As the faults associated with transformer windings areoften of a low current magnitude, it is preferred to set the basic pickup current as sensitive as

possible. A low setting will have minimal effect on the relay performance at high currents andalso on the percentage harmonic restraint action.


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4.7

MULTI-TAPDIFFERENTIALRELAYS

These are generally electromechanical relays which can accept the differential currents in sucha manner to compensate for CT ratio mismatch on the power transformer HV and LV.

Consider a deltawye grounded transformer. The transformer is rated 42 MVA, 69kV delta12.5kV wye. The transformer is to be protected by a percentage differential relay, which is an electromagnetic induction disk relay with two restraint coils and one operating coil. The relay has tapsof 1.0, 1.1, 1.2, 1.3, 1.5, 1.7 and 2.0. The relay has a nominally 50% percentage slope. Thetransformer previously had a numeric percentage differential relay which became defective. Theonly replacement is the electromechanical relay. The CTs were previously sized based on a CTsecondary wye connection, giving a ratio of 400/1 for the HV CTs and a ratio of 2000/1 for theLV CTs. Since the electromechanical relay is affected by zero sequence currents the LV CTsecondary must now be connected in delta. Determine a suitable tap to apply the secondary CTconnections.

The secondary current from the wye connected CTs is:351400

0.8775

The secondary current from the delta connected CTs is:31940

2000 1.6781

The ratio of the delta connected output to the wye connected output is:1.67810.8775

1.912

The closest tap is 2.0.


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Using this tap, the mismatch is computed as:

% 2.0 1.912

1.912 4.6%

Considering the CTs have a ratio error of 10% and the error due to the tap changer is 12.5% thetotal error is:

%Error= 2 10 1.125 1.046= 23.5%

Hence the relay has a safety margin of 26.5%.

4.8

INSTANTANEOUSHIGHSETDIFFERENTIALRELAYS.

A differential relay with a high overcurrent setting for its operating coil may be used as a highspeed protection.

4.9

EXCITINGCURRENTCONSIDERATION

A transformer draws a steady state magnetizing current under normal operation. This currentflows in the relay's operating coil and it is so low under normal load conditions that the relay hasno tendency to operate. This current seldom exceeds 0.2% of the bank rated load current.

But any operating abnormal condition that calls for an instantaneous change in flux linkages willcause magnetizing currents to increase tending to operate the relay.

For example when a transformer is subjected to overvoltages, the exciting current increasesgreatly, ; ;

di N iV L H B H

dt l

, and because of the nonlinear magnetization characteristic

of the core, harmonic currents predominate, especially the 3rd and 5th harmonic components.Note where there exists a delta connected winding of a power transformer and delta connectedCTs, the 3rdharmonic current will not be seen by the relay as they circulate in the closed path ofthe delta.


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4.10

MAGNETICINRUSHONBANKENERGIZATION

The most important consideration however is the large transient current inrush that occurswhen a power transformer is energized from one side with the other side disconnected fromload or source. When a power transformer is first switched on it acts as a simple inductor. Theoperating coil of the differential relay will therefore, receive currents with high peak valuesleading to greater tendency for the relay to operate.

The magnitude and the waveform shape of the inrush current depends upon many factors, The size of the bank. Strength of the power system to which the bank is connected. Resistance in the system from the equivalent source to the bank. The type of Iron used in the core. The magnitude and point on the supply voltage wave at the instant the bank is energized. The residual flux and its relationship in polarity and magnitude with respect to the

instantaneous value of steady state flux corresponding to the particular initial energizing

point on the voltage wave. The ratio of saturation flux density to the operating flux density at rated voltage. Sympathetic inrush in parallel transformers.

The time duration of the inrush is influenced by the transformer size and the L/R ratio of thesupply source. A typical inrush current wave is shown' in the next Figure.

The flux induced in the core is proportional to the magnetizing current and is in quadrature withthe applied voltage during steady state.

Consider a transformer that is to be energized from a bus voltage that is sinusoidal. The steadystate flux is the integral of the voltage, or

1 1

sin cos

C is a constant of integration.

t dt t C N N

Where


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Note that the flux lags the voltage by 90 degrees.

If at the instant of switching on, the voltage is zero, the corresponding steady state value of fluxshould be at a negative maximum. This is clearly impossible, as in the absence of remanence (themagnetic flux that remains in a magnetic circuit after an applied magnetomotive force has beenremoved), no flux linked the core prior to switch on. This steady state value of flux cannot beinstantly accommodated as this would imply an infinite rate of energy transfer. Therefore this

steady state value of flux can only be reached after a finite time determined by the rate at whichthe circuit can accept energy. This time interval is infinitely long in a purely inductive circuit

0

LLR

, therefore the flux is a fully displaced sine wave which reaches a maximum of

2m

, half cycle after switch on.

Mathematically, the conditions which exist in the absence of a residual flux at zero voltage statethat the flux is zero when the applied voltage is zero at t=0. This leads to an integration constant

of m . Hence at

2

Tt , the flux builds to a maximum of 2

m .

As the flux builds, the exciting current grows with the flux. The magnetizing current isproportional to and in phase with the flux. If the winding inductance were linear, the currentwould have exactly the same waveform as the flux, i.e.

21 1

cosi v dt t C L L


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However, the inductance is not linear, and saturation can be expected to occur since powertransformers are designed to operate near the knee of the saturation curve (a cost issue, utilizingthe entire core in the maximum manner for flux channeling) under normal conditions. Henceunder full load, the maximum flux that can be accommodated by the core is m. The saturation of

the core causes the exciting currents to increase greatly beyond those seen under normal

operating conditions. These exciting currents even exceed the transformer rated phase currents.The actual value of magnetizing current will depend on the winding inductance and theinductance will become very small when the core saturates.

The worst case inrush is experienced when the transformer is energized at the zero point on thevoltage wave with a residual flux of m (i.e. C = 0). Zero inrush is experienced if the transformer

is energized on the peak of the voltage wave as the maximum flux developed will bem

.

The way in which saturation causes severe exciting current buildup is illustrated below. Thesaturation curve on the left shows the exciting current required in order to provide a given levelof flux.

For each point on the flux wave, starting at the residual flux value R, a value of current may be

found from the saturation curve and plotted on the time axes. This is illustrated for one value ofcurrent, labeled mI . Plotting many different points gives the fully offset current pulse shown.

Note that the current waveform is not sinusoidal, but is a sharp pulse, with the peak occurring atmaximum flux.

After this point where the voltage goes negative the flux cannot build up any more as its valuemust now decrease with time. For other values of voltage at switch on, the flux peak will varybetween and 2m m , and will reach the peak when the voltage reaches its next zero crossing.


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The decay of the excitation current is rapid for the first few cycles, but then decays very slowly.Usually several seconds are required for the current to reach normal levels. The time constant

governing this decay is not a constant LR

, since the inductance is varying due to the high flux

leakage (saturation). Thus, the time constant is small at first (hence a fast decay), then increases

as the saturation is reduced (reduced leakage). Moreover, the time constant is a function of thetransformer size and may vary from 10 cycles for small transformers to one minute for largesizes.

The decay of exciting current also depends on the resistance seen looking into the power system.If the transformer is close to a generator, this resistance is very small and the exciting currentwill damp very slowly. The current drawn by the transformer can be distorted in its waveformfor as much as 30 minutes after energization.

The degree of the inrush also depends on the type of steel used. The permeance of the material isdifferent for each steel type and hence the BH characteristic differs, which affects the excitation

saturation characteristic.

The inrush as discussed above and typical of single phase banks is further complicated for 3phase banks. The three phase inrush currents are influenced by the electrical connections of thetransformer windings and/or magnetic coupling between phases (delta or wye configurationand core design). Since the point on the voltage wave at which energization begins is different forall three phases, it is normally expected that the inrush in each phase of a 3phase bank willdiffer appreciably.

Generally speaking, the inrush current is a distorted wave having all orders of harmonics, with apredominant 2nd and 3rd harmonic component. Energization of a delta or ungrounded wyewinding will have no tripling (3rd order) harmonics. The dcoffset of the current is alsosignificant.

4.10.1 TheDCOffset

If the residual flux happens to equal to the normal required steady state flux for that phase at theinstant of switching, then that phase will not have a dc component in the magnetizing inrushcurrent, but the dc offset will occur in both of the other phases.


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4.10.2 TheSecondHarmonic

The proportion of second harmonic current varies with the degree of saturation in each phase,but is always present as long as the dc offset is present in the core flux. The second harmoniccontent as percentage of the fundamental can therefore, vary considerably with a value as highas 63 percent for older transformers. The minimum second harmonic magnitude has been shown

to be about 20% of the excess magnetizing current (over its steadystate value). However, theminimum value upon which harmonic restraint setting is to be based must be determined by theparticular utility and is based on experience

It is important to note that, although normal fault currents do not contain second harmoniccomponents or any other even harmonics, a value that is too low may cause the relay to restrainfor internal faults. A value that is too high may result in the false tripping upon energization.Furthermore, saturation of ironcored devices (such as a CT or the power transformer itself) maycause distortion in the currents, but these distorted currents contain only odd harmonics.

4.10.3

TheThirdHarmonicThe inrush current also contains a large amount of third harmonic current, in about the sameproportion as the second harmonic. In three phase transformers, the third harmonic current inthe three phases are all in phase and may not appear in the line current of delta connected banks.It is also important to note that third harmonic currents are likely to flow as a result of CTsaturation.

4.10.4 Higherharmonics

Many higher harmonics are present in the inrush current, but their proportion is much smallerthan those discussed previously. These are usually not of great interest although there has been

interest in detecting the fifth harmonic by some relay manufacturers.

Over the years of transformer design, the value of the ratio of the saturation density to operatingflux density has been decreasing and seems to have bottomed out at about 1.13 to 1.15, mainlydue to the advent of high permeability steel. The closer the residual flux to the operating fluxdensity, the greater the base width of the magnetizing current wave with consequent reductionin second harmonic component.

Transformer core construction being as it is, with all the joints permitting small inadvertent airgaps, the residual flux is normally around 6580 % of the peak operating flux density.

Another method to overcome this unwanted operation is to time delay the protection as is donefor overcurrent backup protection.


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4.11

MAGNETICINRUSHONPARALLELEDTRANSFORMERENERGIZATION

When abank is already energized and a second bank is then energized, in parallel, not only willthe bank being energized have an inrush, but the energized bank can experience an outrush,referred to as sympathetic inrush. Moreover, the inrush to the banks will decay at a much slowerrate.

This is caused by the dc component of the offset inrush current of the bank being energizedfinding a parallel path in the energized bank and finally circulating in the loop circuit betweenthe banks. The dc component, in fact, may saturate the core of the already energized bank,causing this bank to experience the apparent inrush. Fortunately the sympathetic inrush willalways be less than the initial inrush and depends on the size of the unit and on the strength ofthe power system.

4.12

RELAYRESTRAINT

As far as the magnetizing inrush is concerned, there are four common methods used to preventthe tripping of a sound transformer.

1. Detect magnetizing inrush by observing the current harmonics.2. Add a time delay.3. Desensitize the relay during startup.4. Supervise the relay with voltage relays.

1. DetectmagnetizinginrushbyobservingthecurrentharmonicsOne way to get around the problem of misoperation due to the magnetic inrush on energizationis by means of a technique called harmonic current restraint. The principle lies in desensitizingthe relay during the inrush without jeopardizing the ability of the relay to operate should a shortcircuit occur in the transformer during the inrush period. The predominant second harmoniccomponent of the magnetic inrush current is utilized to restrain the relay.

Because of the various factors involved, it is not possible to accurately predict by calculation theharmonic content in the inrush current to the threephase power transformer. The question thatnow arises is how one selects the optimum value for the percent second harmonic content abovewhich the relay is to be restrained. This value is normally based ona combination of engineeringjudgment and practical experience. The second harmonic restraint characteristic employed inour transformer protection use approximately 15 to 20 percent value for the second harmonic

content in terms of the fundamental on a single phase basis. For internal faults there is stillsufficient energy in the fundamental and other harmonics to cause tripping.

When a three phase transformer is energized, the inrush experienced on each phase is differentand the 2nd harmonic content in each phase also differs. There exists the situation where theharmonic content on a single phase may be below the restraint level with a sufficient inrush tocause tripping. To guard against these situations, harmonic averaging may be employed innumeric differential relays. Harmonicaveragingis the technique used where the average of the2ndharmonic content of all phases is used to restrain each differential phase.


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As stated earlier, a transformer already in service when subjected to overvoltage will have itsnormal steady state exciting current multiplied several fold becoming rich in third harmonic andfifth harmonic components. It is conceivable that these exciting currents with magnitude greaterthan the pickup value can cause the relay to operate.

It is preferable that a dedicated over excitation protection be provided when it is feared that overvoltages would damage the transformer in a short time. It is undesirable to trip a transformer byinstantaneous differential relay when a fault does not exist in the transformer, on transient overvoltage. Such a trip can be misleading in terms of deciding if to test the transformer or not,resulting in excessive down time. In order to prevent the relay pickup on over excitation, thefifth harmonic component can be used to restrain the relay. The third harmonic currents aregenerally not seen by the relay either due to delta windings in the power transformer, delta CTconnections, or relay filtering circuits or algorithms.

Note, the usefulness of the fifth harmonic restraint feature is prudent because of the following:

(a) It is not valid to generalize regarding the harmonic current of three phase transformer bankexciting currents during overvoltage conditions.

(b) Operating experience does not bear out the contention that over voltages causes misstripsdue to relay operation. This is understandable because the normal exciting current is such a lowpercent of the pickup value that even if it is tripled, it would be still below the pickup level.

The 5th harmonic restraint is generally not employed on our transmission and distributionsystems.

2.AddatimedelaySimply adding a time delay to the differential relays during energization of the transformer iseffective, but it must be accompanied by some method of overriding the time delay if an actualfault occurs during start up. Usually the time delay is used in conjunction with other relayintelligence. A 50ms delay is usually sufficient. A definite time delay is usually set forinstantaneous overcurrent elements having a low pickup.

3. DesensitizetherelayduringstartupThere are various methods for desensitizing the differential relay during energization. Onemethod parallels the operating coil with a resistor, with the resistor circuit being closed by anundervoltage relay b contact. When the transformer bank is deenergized, the undervoltagerelay resets, thereby closing the resistor bypass circuit. On startup, the operating coil is bypassed until the undervoltage relay picks up, which is delayed for some time.Another method uses a fuse to parallel the differential relay operating coil. The fuse is sized towithstand normal startup currents, but internal fault currents are sufficient to blow the fuse anddivert all current to the operating coil.

4. SupervisetherelaywithvoltagerelaysThe voltage supervised relay measures the threephase voltage as a means of differentiatingbetween inrush current and a fault condition, a fault being detected by the depression in one ofthe three phase voltages.


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4.13

CTCONNECTIONS

The CT ratio selection and connections for differential protection should meet four basicrequirements.

Correction of the secondary currents in the connecting circuits due to the differentvoltage levels of the protected transformer bank by proper choice of CT ratios,interposing CTs (ICTs) or via the relays ratio correction facility in numeric relays.

Correction of the 30o phase angle shift introduced by power transformer internalconnections.

The secondary current through the differential relay must have such a value as to ensurethat the relay does not operate on maximum emergency load. The setting is a direct resultof the CT error. The lower the CT error the more sensitive the relay can be set.

The current in the operating coil of the differential relay for internal faults must besufficiently above the zero restraint pickup level to ensure the relay operation. This isrelated to the polarity of connecting the CTs.

The phase shift correction can be achieved by connecting the CTs on the wye side of theTransformer in delta and the CTs on the delta side in wye, taking into account the vector group ofthe power transformers.

For all external fault conditions, except for ground faults on the wye side of a groundedbank, thepair of CT connections used on either side of the transformer is inconsequential, as so long as theCT secondary currents to the relay are balanced through the proper choice of CT ratios.

If the wye side of the transformer is ungrounded there is no source for zero sequence currents.When the wye is grounded, ground current can flow in the wye windings for an external fault.

The delta connection is thus required for the CTs to circulate the zero sequence component ofthe current inside the delta thereby preventing it from entering the relay. The added advantage,though of little effect, is that the delta connection circulates the third harmonic of the excitationcurrent.

The zero sequence phase component of current do not exist on the delta side of a powertransformer for a ground fault on the wye side; and therefore, if the CTs on the wye side were notdelta connected, the zero sequence currents would not find a circulating path. These currentswould then flow in the operating coils, causing the relay to maloperate for external groundfaults. The next figure illustrates the delta CT connection for a wyedelta power transformer.


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This consideration of CT connection is not important in numeric relays as they have the ability tocompensate for the 30oshift and to filter the zero sequence current components.

The question now arises as to how the relay will operate for an internal LG fault because thezero sequence currents are kept out. The answer is that the relay still receives positive andnegative sequence components of the fault current for it to operate.


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For an ungrounded wyedelta power transformer with a zigzag grounding transformerconnected externally on the delta side (or the equivalent wyezigzag power transformer), theCTs on the delta side need to be connected in wye to correct the phase angle shift of thetransformer.

Because of the ground source in the protected zone, as can be seen in the preceding figure, zerosequence currents result for an external LG fault on the delta side. These currents are required

to be prevented from going through the relay as they are not matched from the wye side of thetransformer. This requirement is realized by the use of a current trap, referred commonly as azero sequence shunt. The shunt comprises of three identical auxiliary CTs which can have anyratio, and connected as shown. In order not to reduce the effectiveness of the shunt in circulatingthe zero sequence currents, the neutral point oftherelayshould not be connected to the neutralpoint of the wye connected CTs on the delta side.


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4.14

CHOOSINGCTRATIOS

The best practice is to choose the CT ratio that will give a secondary current close but less thanthe nominal rated current of the relay under maximum load condition. This assures that the relaywill be operating at its maximum sensitivity when faults occur. If the current supplied is only halfthe rating, the relay will only be half as sensitive.

4.15

COMPUTINGTHECURRENTTRANSFORMERRATIORELATIONSHIP.


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Note the effective ratio of the transformer is 13 : or 0.577: Where N is the transformation ratio of the transformer, and not the turns ratio n.I.e. 3.

For the protection to be stable yet as sensitive as possible, we would like the ratio of the CTsecondary currents to be as close as possible to unity.

1

3

Note, the ratio of each current transformer must be such that the secondary currents flowingunder full load, does not exceed the rating of the restraint coils.


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4.15.1 ExampleComputation.

A deltawye transformer is rated as follows:

S = 50 MVA

= 115 kV = 69 kV= 600/5

Find a suitable ratio for NCfor the delta connected CTs of the 69 kV side.

Solution:

Recall: 1

Recall Also:

Hence:

This is a ratio of 346:1, which is not standard. The standard ratios are 300 and 400.

It is best to choose a Standard CTR greater than the required CTR calculated, rather than aStandard CTR that is lower. This gives a higher voltage on the secondary side of the CT whichtends to minimize the effects of secondary lead resistance.

Note, the maximum spill current due to the mismatch must be calculated for the transformer

overload condition, and factored in with the CT error, when setting the percent differential slope1 as previously discussed.

When standard ratio current transformers are used, the secondary currents on the two sides ofthe power transformer may differ and can be corrected by using interposing CTs with taps in therelay winding.


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4.16

TWO WINDING PERCENT DIFFERENTIAL RELAY FOR THREE WINDING

TRANSFORMERS.


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A three winding power transformer can have one primary and two secondary windings. It ispossible to protect this transformer with a two winding percentage differential relay instead of athree winding version. The connection of the two winding differential is shown. As can be seen,the two CTs on the secondary side of the transformer are connected in parallel. Thisarrangement is acceptable at distribution stations where there is no transfer of power betweenthe low voltage windings when the high voltage disconnect switch is open, i.e. the transformer isconnected to the system via a single source point. If the transformer is connected to the powersystem at both its high and low voltage terminals, each winding of the transformer must havetheir own restraint coil.

The advantage of using a two winding differential relay for a three winding transformer is thesaving in cost.

When two transformers are placed in parallel without separate breakers for each bank, a singledifferential protection scheme can be used. The result however, is a transformer protection withonly half the sensitivity of that if separate protections were used for each bank, since the CTsmust be rated to at least twice that of a single bank. This is assuming that both transformers havethe same rating. If one bank is smaller, then the imbalance in sensitivity is even worse.


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Autotransformers can also be protected using differential protection schemes. If theautotransformer is configureed in a three phase configuration, the neutral of each phase must beavailable for externally for CT connection if grounded. For single phase aplications the neutralmust also be CT connected.


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4.17

PROBLEMSWITHDIFFERENTIALRELAYS

In applying differential protection it is important to use current transformers which have similarexcitation characteristics. If the two sets of CTs are of different characteristics, any currentflowing in the operating coil of the relay tends to add to the burden of the more accurate CT andreduce the burden of the less accurate one. In such cases, it is sometimes recommended that ashunt burden, having a saturation characteristic similar to the less accurate CT, be added acrossthe terminals of the more accurate CT, thereby making the two sets equally poor but still betterbalanced.

If only one set of CTs have poor accuracy, there is also the hazard of locking in for internalfaults. This means that the less accurate CT is unable to sustain any secondary induced emf or itssecondary winding is effectively shorted. Thus the better CTs secondary currents are shuntedaround the operating coil and tripping is defeated.


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5 APPLICATIONCONSIDERATIONS

5.1

INFLUENCEOFWINDINGCONNECTIONSANDEARTHINGONEARTHFAULTCURRENT

Two conditions must be fulfilled for an earth fault current to flow in the case of a winding fault.

1. A ground path must exist for current to flow into and out of the winding. I.e. the windingor the system which feeds the winding is grounded.

2. The ampere turns between paired windings are balanced (ZigZag grounding).

The magnitude of earth fault current for a given fault position within a winding depends uponthe winding connections and method of system earthing.

Where the neutral of a star winding is earthed the connection is made solidly or through aresistance.

On the Delta side of a transformer it is common to earth the system via an earthing transformerhaving a zigzag winding. The zero sequence currents in the two windings on each limb havecanceling ampereturns and the impedance to earth is therefore negligible. For positive andnegative sequence currents the connection offers infinite impedance.


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5.1.1 Faultonwyewinding

The following discussion assumes a deltagrounded wye transformer configuration with a sourcepresent only on the delta side.

When the Wye side is earthed through a resistance, the earth fault magnitude is determinedprimarily by the value of the earthing resistance since the transformer winding impedance(though influenced by an unbalanced flux linkage between the windings, which causes it tochange) is negligible by comparison.

The closer to the neutral of the secondary winding, the fault occurs; the lower is the fault supplyvoltage, being proportional to the percent of the winding which is faulted. The value of thesecondary side earth fault current is therefore proportional to the position of the fault in the

winding.

%

%

sA

A s

VI

R

I V

.

Recall% S

P S

P

VI I

V

Hence

2

2

% %

%

%

S SP

P

S

P

P

B S

V VI

R V

VI

R VI V

The primary side current is thus proportional to the square of the percentage of secondarywinding short circuited.


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When the star winding is solidly earthed, the fault current magnitude is limited solely by thewinding impedance and the fault current is no longer proportional to the position of the fault. Inthis case the unbalance in the flux linkages in the winding causes the impedance of thetransformer to change, and hence the impedance to the fault to change. The impedance of thetransformer varies as the square of the number of turns.


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Furthermore, the voltage at the fault point no longer varies proportionally to the number ofturns for faults near to the neutral because of the increased leakage. Therefore the impedancefunction becomes very complex and the current on the wye side (IF) has a minimum at about40% of the total winding faulted and increases as the fault point approaches the neutral,dropping quickly to zero at the neutral.

5.1.2 FaultonDeltaWinding

The variation of fault current with fault position is not as great as for a star winding, mainlybecause none of the winding is less than 50% of the normal phase to neutral voltage above earth;but the actual value of fault current will be governed by the method of system earthing.

In the special case of an earth fault occurring at the centre point of one leg of the delta winding,the impedance in the fault path is no longer the series leakage impedance between the primaryand secondary windings, but rather the leakage impedance between the two halves of theaffected winding. The impedance in transformers with concentric windings can be very high, ofthe order of 3 to 6 times the normal transformer series impedance. Hence, the minimum faultcurrent occurs at this point.


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5.1.3 TypesofDeltaConnections

There are two types of delta connections involved to obtain 30 degree phase shift.

Because of the existence of the two types of delta connection, care must be exercised whenmaking the delta connections for the CT secondaries in the differential circuit. The CT deltaconnection should be a replica of the power transformer delta connection.


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5.1.4 CTConnectionforZigZagTransformer

The CT secondary connections for the wyezigzag power transformer corresponds to that forthe wyedelta transformer except that a zero sequence shunt will have to be use to keep awaythe zero sequence currents from the differential relay. The internal connection and the vectorialrelationship are illustrated.


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5.2

MASTERGROUND

For the transformers with grounded wye LV windings and used for 3 wire distribution systems,the neutrals can be used to provide a sensitive supervision for the feeder ground relays.

During the transfer of loads between two feeders (fed from transformers whose secondaries arenot paralleled), the three phases of the switching device, e.g. a disconnect or circuit breaker, maynot operate in unison and therefore, create a zero sequence current in the residual circuit of theCT connections.

This current can operate the ground relays connected to the secondary residual circuits. But, it

will not operate any over current relay connected to parallel connected CTs between the twotransformer grounds as shown. The zero sequence current flows up the neutral of onetransformer and down the neutral of the other transformer with the result that the masterground relay will not receive any current or operation. By having the contacts of the feederground measuring over current relays supervised by a contact from the master ground relay,maloperation of feeder protections during switching operations are avoided. The practiceinvolves connecting the two master ground relay coils in series to form a current loop.

Note if feeders are characterized by load unbalance, feeder earth fault relays are not employed asthe zero sequence components may operate ground protection under normal conditions.


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6

RESTRICTEDEARTHFAULTPROTECTION(REF)

If the current for an internal LG fault is limited to a low value by high impedance grounding ofthe transformer neutral or a fault on the end of the winding close to the neutral point, it is

possible that the differential relay may not receive adequate current for operation due to acombination of factors such as deltawye transformer connection with high turns ratio, large CTratios, etc.

This problem can be solved by using a sensitive time overcurrent relay in the impedancegrounded neutral or a separate REF protection.

If dedicated CTs cannot be provided for REF for practical and economical reasons, it can beoperated from the CTs associated with the overall differential protection.

A typical arrangement for REF is shown in the next figure for a deltawye transformer.

The operation for an external or internal fault on the secondary side of the transformer is easilyanalyzed by vectorial summation of the currents in the phase and neutral CTs.

The arrangement of residually connected transformers on the delta side of a transformer is onlysensitive to earth faults on the delta side because zero sequence is blocked by the delta winding.Consider an unbalanced single line to ground fault on the star side. This can be represented asthree sets of balanced currents (positive sequence, negative sequence and zero sequence) in thesequence domain. The zero sequence currents when referred to the primary are trapped by thedelta of the power transformer while the positive and negative sequence currents balance. Interms of the physical currents, a single line to ground fault on the secondary will translate into adouble line current on the primary which will not cause the Delta REF to operate as the CT vectorsum will be zero.

It is usual that the REF protection be based on high impedance principle for through faultstability, though any over current device can be used. The measuring relay is a 60Hz tunedinstantaneous relay, which operates for an internal fault as the current is forced through it. Themeasuring relay circuit path across the CT differential junction points is made high impedance toensure stability for an external LG fault. The set point is chosen to be slightly higher than themaximum voltage which can possibly appear across the relay for a maximum external faultcondition. If the transformer is an Inter Bus transmission transformer which can have a source ofsupply from either the HV or the LV side then the fault level to be used it the maximum of the twoavailable. For a single supply transformer such as a distribution transformer the fault level isthat on the load side. In order to limit high voltage across the relay circuit during an internalfault, a nonlinear resistor is used in parallel.

Another method utilized in REF implementation is the use of low impedance over current relaywith load biasing employed. Here a slope setting is employed similar to the Bias Differentialprotection in order to guard against operation where CTs can saturate for high magnitudethrough faults. This feature can be seen in the GE SR745 relay. The advantage of this


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implementation lies in the ability to use different ratio CTs for the phase and neutral inputs, as allCT inputs are wired directly to the relay rather than parallel at a point before.

Figure 3.2.a

Current due to internal L-G fault

Current due to external L-G fault


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6.1

GUIDELINESFORTHEDESIGNPARAMETERSANDSETPOINTFORREFPROTECTION.

A low impedance earth fault overcurrent relay may, with the addition of an external seriesresistor, and a nonlinear resistor, be connected as a high impedance restricted earth fault relayfor the protection of transformer windings or the stator windings of large machines.

Vs ,relay circuit setting voltageVstab ,min voltage required to ensure stabilityVfs ,rms value of relay circuit voltage not withstanding CT saturationVpk ,peak voltage produced across relay circuit during internal fault

conditionsIf ,maximum inzone fault currentIfs ,max through fault currentRct ,CT secondary winding resistanceRL ,CT lead resistance (loop)N ,CT turns ratioVk ,CT knee point voltageImag ,CT magnetisation currentInlr ,nonlinear resistor currentRs ,setting resistanceIs ,relay setting currentPcon ,continuous power rating of resistorPhalf ,0.5 second power rating of resistor


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6.1.1 DeterminationofStability

The stability of a REF scheme using a high impedance relay circuit depends upon the relay circuitsetting voltage being greater than the maximum voltage which can appear across the relaycircuit under a given through fault condition (i.e. external fault). This voltage can be determinedby means of a simple calculation which makes the following assumptions:

a) One CT is fully saturated making its excitation impedance negligible.b) The resistance of the secondary winding of the saturated CT together with the leads

connecting it to the relay circuit terminals constitutes the only burden in parallel with therelay.

c) The remaining CTs maintain their ratio.

Thus the minimum stability voltage is given by:

Vstab= Ifs(Rct+ RL)

For stability, the relay circuit voltage setting should be made equal to or exceed this calculatedvalue. No factor of safety is necessary because this is built into the assumptions made.

Experience and extensive laboratory tests have proved that if this method of estimating the relaysetting voltage is adopted, the stability of the protection will be very much greater than the valueof Ifs used in the calculation. This is because a CT is not normally continuously saturated andconsequently any voltage generated by this CT will reduce the voltage appearing across the relaycircuit (less current flows in the CTloop arm if the CT is partially saturated).

6.1.2

CurrentTransformerRequirementsThe CTs used in this type of scheme should be of the high accuracy and low leakage reactancetype, and the minimum CT knee voltage should be greater than twice the minimum stabilityvoltage setting calculated for the relay.AlowleakagereactanceCThasajointlessringtypecore,the secondary winding evenly distributed along the whole length of the magnetic circuit and theprimary conductor passes through the approximate center of the core.

Also, all CTs should, if possible, have identical turns ratios.

6.1.3

SettingResistor

In setting the relay operating point, the relay operating current must be selected or be known.The effect of all shunt paths must also be considered, i.e. all CT magnetizing currents, all shuntresistor paths, and the nonlinear resistor if installed. Hence since the primary fault setting isgiven by.

s 1 2 3Primary Fault Setting = N(I )

shunt MetrosilI I I I I


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Where,Is = Relay operating currentI1, I2, I3 = The excitation currents of the CTs at the relay setting Voltage.Ishunt = Shunt current due to shunt resistor connected across the Relay and Hi

Impedance.IMetrosil = Leakage through metrosil at relay setting voltage.

If the relay used in the scheme has a low burden, then a series setting resistor will be required toprovide the relay circuit setting voltage for stability. Assuming the relay burden is very small andthe CTs do not have very low knee point voltages (less than 25V), the relay burden can be

neglected and the setting resistor value is then given by: ss

s

VR

I

The primary fault current setting obtained may be too low, and may be required to be increased.Where the operating current of the relay is variable this is achieved by changing the pickup ofthe relay. Alternatively the operating current of the relay may be fixed.

For any relay, if the relative increase in fault setting required is small, an increase in the relaycircuit voltage setting and hence an increase in the values of I1, I2, and I3 (desensitizing thescheme), may give the required result. Alternatively, when the required increase in fault settingis large, the correct result can be obtained by connecting a resistor in parallel with the relaycircuit, thereby effectively increasing the value of primary current (difference) setting.

6.1.4 NonLinearResistor

The maximum internal primary fault current in the protected zone will be the same as that forthe stability condition when the primary network circuit is solidly earthed. This current may

cause high voltage spikes across the relay at instants of zero flux since a practical CT core enterssaturation on each halfcycle for voltages of this magnitude.

A formula in common use, which gives a reasonable approximation to the peak voltage producedunder internal fault conditions, is expressed as

2 2pk k fs kV V V V

Where Vkis the CT knee point voltage.

Re( )fs f S layV I R R

Recall that the CT will saturate at Vkalthough Vfs is greater than this value. This will limit thevalue Vpk.

To protect the CTs, the secondary wiring, and the relay from damage due to excessively highvoltages, a nonlinear resistor is connected in parallel with the relay circuit if the peak voltage


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would exceed 3kV. If the calculated peak is less than 3kV, it is not necessary to employ a nonlinear resistor.

The type of nonlinear resistor required is chosen by:

1. Its thermal rating as defined by the empirical formula:

4fs kP I V

2. Its nonlinear characteristic i.e

BV CI Where C and B are constants.

A nonlinear resistor with C and B values is selected which ensures

1. The peak voltage cannot exceed 3kV and,2. In the region of the relay circuit setting voltage, the current shunted by the nonlinear

resistor is very small (e.g. < 10 mA).

6.1.5 WorkedExampleProtectionofPowerTransformerHVDeltaWindingUsingAREFElementofanARGUSRelay.

4.1. Data required(With values inserted from a typical example)

4.1.1. CT secondary winding resistance 34.1.2. Lead resistance (loop) 3


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4.1.3. Magnetising characteristic of CT see Fig. 4 [ Vk > 270 ]4.1.4. CT turns ratio 1/2004.1.5. Nameplate rating of power transformer 30MVA4.1.6. Voltage ratio of power transformer 132/11kV4.1.7. Required primary fault setting 10% to 60%4.1.8. Power transformer impedance 9.5%4.1.9. System earthing solid4.1.10. Maximum system fault level 3500MVA4.1.11. Relay data, Argus 1 relay (REF/SEF version)

REF setting range 0.5% to 95% of In in 0.5% stepsAC burden, 5A tap 0.4VA1A tap 0.2VA

A UK standard in use for some years now, EATS 483, recommends that the figure used for Ifsshould be 16times the rated current of the protected winding. This is a typical figure based oninfeeds to an external earth fault from the transformer under consideration, which is in parallelwith the remainder of the system up to the point of connection of the transformer.

Note alternatively one can calculate the secondary side fault level for a distribution transformerby using the HV side fault level, and the transformer impedance.

Using the UK Standard

( )

( )

(sec )

_16

3 _

3016 2.1

3 132

2100/ 200 10.5

fs primary

fs primary

fs ondary

TF RatingI

System Voltage

MVAI kA

kV

I A

The minimum CT knee point voltage should be greater than [2 x Ifs (RCT+RL)] volts.Thus Vkmin= 2[10.5(3+3)] = 126V

Minimum stability voltage to ensure stability during maximum through fault is:Vstab > Ifs (RCT+RL)

> 10.5 (3+3) > 63V

EATS 483 recommends that the primary fault setting should be in the range of 10% to 60% ofthe rated current of the protected winding (when the protected winding is connected to a solidlyearthed power system). Generally a value of 20% is normal. If the power Transformer is earthed


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through a resistor rated to pass an earth fault current of 100% or more of the rated current ofthe protected winding, a fault setting of 10 to 25% of the rated current of the earthed resistor isrecommended.

The acceptable limits for the primary fault setting are:

Therefore the relay operating current limits are:13.1 to 78.9

65 to 400mA200

mA

The Argus relay REF element has a setting range from 0.005 to 0.96A in 5mA steps. An initialsetting of 0.18A (180mA) is chosen. However the shunt connection of all other paths must be

added to this to allow the actual fault setting to be determined. The fault setting is the actualcurrent (primary amps) at which the relay operates.

Shunt paths = (number of CTs x their magnetizing current) + nonlinear resistor (if required).

Thus, actual setting = 0.18 + 3Imag + Inlr

Note there is no Shunt Resistor in this example. In restricted earth fault applications where therelay setting voltage is considerably lower than the nonlinear resistor C value, Inlr can beignored. The magnetizing current of all parallel CTs must be taken into account at the relaysetting voltage, Vs, which is now calculated.

In reference to figure 4, the magnetisation curve shows a knee point voltage of 270V. A stabilityvoltage within the range Vk/4 to Vk/2 is normal unless a customer has special requirements,therefore a value of say 90VforVscan be chosen. This is more than the minimum value of V stabcalculated at 63V (see section 4.2 above) and is less than Vk/2.

3 to 1813.1 to 78.7A (I.E for 30MVA transformer)

3 132

MVA MVAA

kV


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The value of magnetising current, Imag, at Vs is 0.011A.

Reverting to the calculation of current setting, this can now be completed.

Operating Setting, in secondary amps,Is = 0.18 + 3(0.011) = 0.213ASay0.20A(nearest setting for Argus 1 relay)

The Primary operating current (POC) for the scheme is = Is x CTR=0.213 x 200 = 42.6 A

Full load current at 30MVA = 131A Therefore P.O.C. = 42.6/131 = 32.5% of rating.

This ignores any current passed through the Metrosil at the setting voltage. With typicalstandard values for the Metrosil characteristic for B and C, the current at setting voltage would

be relativelyvery low, e.g. < 1mA.

Based on a relay circuit setting voltage of 90V, the series stabilizing resistor can now becalculated by the following formula:

Rs = (Vs Vrelay)/Is

The Argus relay burden is very small and can be neglected.


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Rs = 90/0.18= 500

The resistor value of 500 can be obtained, with standard tolerance band e.g. +/ 5%.

Thus the relay circuit setting voltage becomes,Vs = 0.18 x 500 = 90VTo check whether a voltage limiting device is required to protect the relay circuit, calculate Vpk.

Vpk = 2 [2Vk(VfsVk)]> 3000

Where,Vk= 270V (lowest knee point voltage of CTs from fig.4)Vfs= If (Rs+ Rrelay)

The resistors incorporated in the scheme must be capable of withstanding the associatedthermal conditions.

Continuous power rating of the setting resistor = Pcon=(Icon)xRs

where Icon= continuous resistor current, normally taken as being the current at circuit settingvoltage (Vs).

Pcon= 0.18 x 500 = 16.2 Watt

The short time rating of the resistor is taken to be 0.5 seconds. This is considered so as to ensurethat the relay circuit components are not damaged in the event of a circuit f

Documents

Transformer Protection Training 1