Test-universe-advanced-differential-module-application-note-example-of-use-transformer-enu

Parameter Name Parameter Value Notes Transformer data 231 kV Rated voltage, Side 1 used for the calculation of the transformation ratio of the transformer 115.5 kV Rated voltage, Sid

Testing Transformer Differential Protection

Practical Example of Use

Testing Transformer Differential Protection

Manual Version: Expl_TDiffProt.ENU.1 - Year 2013

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Content

Preface 4

1 Application Example 5

2 Theoretical Introduction to Transformer Differential Protection 7

2.1 Protection Principle 7

2.2 Operating Characteristic 8

2.3 Zero Sequence Elimination 11

2.4 Transformer Inrush 13

3 Practical Introduction to Transformer Differential Protection Testing 15

3.1 Defining the Test Object 16

3.1.1 Device Settings 16

3.1.2 Defining the Differential Protection Parameters 18

3.2 Global Hardware Configuration of the CMC Test Set 26

3.2.1 Example Output Configuration for Differential Protection Relays 26

3.2.2 Analog Outputs 27

3.2.3 Binary Inputs 27

3.3 Local Hardware Configuration for Differential Protection Testing 28

3.3.1 Analog Outputs 28

3.3.2 Binary Inputs 28

3.4 Defining the Test Configuration 29

3.4.1 General Approach 29

3.4.2 Configuration Test 30

3.4.3 Operating Characteristic Test 33

3.4.4 Trip Times Test 36

3.4.5 Inrush Blocking Test 39

3.4.6 Testing Three-Winding Transformer Differential Protection 42

Support 43

Please use this note only in combination with the related product manual which contains several important safety instructions The user is responsible for every application that makes use of an OMICRON product

Preface

This paper describes how to test the transformer differential protection function It contains an application example which will be used throughout the paper The theoretical background of transformer differential

protection will be explained This paper also covers the definition of the necessary Test Object settings as

well as the Hardware Configuration for these tests Finally the Advanced Differential test modules are used

to perform the tests which are needed for this protection function

Supplements: Sample Control Center file Example_AdvDifferential_Transformer.occ (referred to in this

document)

Requirements: Test Universe 2.41 or later; Advanced Differential and Control Center licenses

Note: The description of the Differential test module is not a part of this document

Parameter Name Parameter Value Notes

Transformer data

231 kV Rated voltage, Side 1 (used for the calculation of the

transformation ratio of the transformer) 115.5 kV Rated voltage, Side 2 (used for the calculation of the

transformation ratio of the transformer)

6.0 I ref Idiff>>, Second element of the differential protection

(there is no stabilization above this value) 0.3 Slope 1 of the differential characteristic 0.7 Slope 2 of the differential characteristic 4.0 I ref Bias current where the first slope ends and the second

Table 1: Relay parameters for this example

Note: Testing of the Restricted Earth Fault protection function, Thermal Overload protection function,

etc is not part of this document

2 Theoretical Introduction to Transformer Differential Protection

2.1 Protection Principle

The most important components in a power transmission and distribution system are the transformers, the generators and the busbars Usually differential relays are applied as their main protection against short-circuit faults within the protected area

The current differential principle is based on Kirchhoff’s law, i.e the sum of the currents flowing into a

conducting network is zero

Protected Object

Figure 2: Protection principle of the transformer differential protection

This principle applies to each phase separately Therefore, the following equation can be calculated for each phase

However, this is only valid if all CT ratios are the same and if the current is not transformed within the

protected object The transformation ratio and the vector group of a transformer, as well as the CT ratios and the positions of the CT star-points, will cause problems with the calculation of the current sums Numerical differential relays can calculate these effects and, therefore, compensate for their influence For

electromechanical differential relays, interposing transformers have to be used instead

Note: The following parts of this document will only focus on transformer differential protection

2.2 Operating Characteristic

If the transformer is equipped with an on-load tap changer (OLTC), its transformation ratio varies over the tapping range This changes the ratio of the currents on side 1 and side 2 and thus produces a spill (out-of-balance) current in the relay Some other effects, such as the current transformer accuracy (including CT saturation), the magnetization of the transformer, etc., also add to this spill current

The magnitude of the spill current increases as the load on the transformer increases The differential relay, however, must not operate in this case The corresponding solution and further sources for spill currents will

be dealt with in the following sections

Magnetization

Tap changer / Leakage

Current Transformer

In Figure 3 it can be seen that the magnitude of the spill current (Sum) depends on the transformer load current To compensate for these error currents, the differential protection must be provided with a bias element This bias element depends on the current flowing through the transformer which, under normal conditions, is the load current

Note: The calculation method of the bias current depends on the relay manufacturer (see Table 2)

 ISide 1 ISide 2 K1 AEG/ALSTOM/AREVA *), (K 1 = 2), e.g PQ7x, P6x

Various conventional (electromechanical) relays

*) = only valid for two-winding transformers, for three-winding

transformers see below

 ISide 1  ISide 2 / K1

SIEMENS (K 1 =1), e.g 7UT5x/7UT6x GEC (K 1 =1), e.g series KBCH SEL (k 1 =2), e.g SEL5

Table 2: Selection of different calculation methods for the bias current (depending on the relay manufacturers); The currents are scaled

to the nominal current of the transformer

With this value the construction of an operating characteristic is possible

Current Transformer

As shown in Figure 4, the operating characteristic has to cover the spill currents during normal conditions, thus enabling the device to determine between blocking and operating The design of the operating

characteristic (number of line segments, slope, etc.) differs widely between manufacturers and relay types For the following example, the AREVA P633 is used Figure 5 and Figure 6 show the parameters and the tripping characteristic of the P633

Figure 5: Relay settings for the differential operating characteristic (AREVA P633)

va

lue)

m1 = 0.

3 (072.145)

Figure 7 and Figure 8 show the settings and the operating characteristic of the Schweitzer SEL-387 for comparison

Figure 7: Relay settings for the operating characteristic (SEL-387)

IRS1 = 4 O87P = 0.25

U87P = 6

SLP1 = 30%

SLP2 = 0%

I diff

I bias

Figure 8: Operating characteristic for the SEL-387

2.3 Zero Sequence Elimination

External phase-to-phase or three-phase faults cannot cause differential currents This is not the case, however, with external phase-to-ground faults at a winding with a grounded star-point

nom

nom

211

300

I I

Figure 9: Differential currents due to an external phase-to-earth fault

The fault current on the grounded side (side 2) will lead to a current in the faulty phase on the non-grounded side (side 1) as shown in Figure 9 As the star-point of side 1 is not grounded, the current of the faulty phase splits in to the non-faulty phases The zero sequence current of side 2 will be compensated in the delta winding The fact that side 2 has a zero sequence current and side 1 does not have one causes a differential current This differential current, during external phase-to-ground faults, may lead to an unwanted operation

of the protection relay Therefore, the zero-sequence must be eliminated from the currents seen by the relay

Note: The way the elimination is achieved differs between conventional and numerical relays The

following discussion is only valid for numerical relays

Zero-sequence current elimination methods for

numerical relays

Internal correction of the currents

by means of mathematical models

Disadvantage: like electromechanical relays with YdY-

interposing current transformers the

sensitivity for phase-to-ground

faults is reduced by 1/3

Differential Relay Side 1 Side 2

Figure 10: Methods of zero-sequence current elimination (numerical relay)

Note: This document only focuses on the arithmetical method The activation logic of which depends

on the manufacturer Figure 11 shows an example of these settings

Figure 11: Relay settings for the activation of the arithmetical methods of Zero-sequence current elimination (AREVA P633)

1 The arithmetical method of zero-sequence elimination is activated for side 2 (the 110-kV-side, see

300

I I

Zero Sequence Elimination for Side 2:

Differential and Bias Currents after Zero Sequence Elimination:

Side 1 Side 2

Figure 12: Arithmetical zero sequence elimination

With the arithmetic zero-sequence current elimination, there is an “error” based on the correction formula which influences the bias currents displayed in the relay Therefore, the relay will also measure bias currents

in the non-faulty phases The same effect occurs when using interposing transformers

1

2.4 Transformer Inrush

Inrush is a phenomenon which commonly takes place directly after a transformer is energized, due to saturation of its magnetic core This saturation causes high power losses which lead to high currents As they only flow on one side of the transformer, the relay will interpret them as differential currents, which will lead to an unwanted trip, if the relay is not stabilized against inrushes The three phase currents during an inrush are shown in Figure 13

Figure 13: Transient record of a transformer inrush

This inrush current has a unique wave form which is characterized by a high percentage of even harmonics – especially of the second and fourth harmonic There are different ways of stabilizing a relay against inrush currents, which use frequency analysis or time signal analysis The most common methods are described in the following section

> Harmonic Blocking: Whenever the percentage of the second harmonic current exceeds the

setting value, the relay will block as shown in Figure 14

I D >

Harmonic Blocking Setting

Figure 14: Harmonic blocking scheme

> Harmonic Restraint: The second and fourth harmonic currents will be added to the bias current

Figure 15 shows that the increased bias current will prevent the relay from tripping during inrushes

Figure 15: Differential protection operating characteristic with harmonic restraint

> Wave form analysis: Numerical time domain analysis of the transient current signal is used to

recognize wave shapes which are typical for transformer inrushes

During the inrush, the magnitudes of the currents are different in each phase In some phases the harmonic currents may be just enough to block the relay whereas in the remaining phases it may be just insufficient enough These non-blocked phases will cause an unwanted operation To prevent this unwanted operation

the relay can use cross-blocking This function blocks the trip in all phases if one phase detects an inrush

The AREVA P633 uses harmonic blocking to prevent unwanted operations during transformer inrush

occurrences Its harmonic blocking characteristic is displayed in Figure 16 It shows that, in addition to the characteristic in Figure 14, the blocking is stopped when the differential current exceeds the Idiff>> setting

Figure 16: Inrush blocking characteristic of the AREVA P633

3 Practical Introduction to Transformer Differential Protection

Testing

The Advanced Differential test modules are designed for testing any kind of three-phase current differential

protection functions, for assets such as transformers, motors, generators, busbars, lines and cables These test modules are:

> The Diff Configuration module for testing the configuration of the differential protection which

consists of the wiring and the relay parameters such as transformer data, CT data and zero sequence elimination

> The Diff Operating Characteristic module for testing the operating characteristic of the

differential protection

> The Diff Trip Time Characteristic module for testing the trip times of the differential protection

> The Diff Harmonic Restraint module for testing the blocking of the differential trip due to current

harmonics

These test modules can be found on the Start Page of the OMICRON Test Universe They can also be inserted into an OCC File (Control Center document)

3.1 Defining the Test Object

Before testing can begin, the settings of the relay to be tested must be defined In order to do that, the

Test Object has to be opened by double clicking the Test Object in the OCC file or by clicking the

Test Object button in the test module

3.1.1 Device Settings

General relay settings (for example, relay type, relay ID, substation details) are entered in the RIO function Device The CT data is not entered in this RIO function It will be entered in the RIO function Differential

(see chapter 3.1.2)

Note: The parameters V max and I max limit the output of the currents and voltages to prevent

damage to the device under test These values must be adapted to the respective

Hardware Configuration when connecting the outputs in parallel or when using an amplifier

The user should consult the manual of the device under test to make sure that its input rating will not be exceeded

3.1.2 Defining the Differential Protection Parameters

More specific data concerning the transformer differential relay can be entered in the RIO function

Differential This includes the transformer data, the CT data, general relay settings, the operating

characteristic, as well as the harmonic restraint definition

Note: Once an Advanced Differential test module is inserted, this RIO function is available

Protected Object

This first tab contains the definition of the primary equipment which is protected by the relay

1 As a transformer differential protection is to be tested, Transformer has to be selected

2 The names of the transformer windings can be entered here They can be chosen freely and once they are set, they will appear in the respective test modules

3 The transformer data has to be entered here For each winding, the nominal voltage and the nominal power have to be defined Also, the vector group of the transformer must be entered For each Y winding the star-point grounding can be defined This setting has influence on the currents during single-phase faults

Note: If the nominal power of the different transformer windings is not equal, the reference winding of the

relay must be entered in the first column

4 The nominal current of each winding is calculated automatically It can be used to check if the

transformer settings have been entered correctly

1

2

3

4

CT

In this tab the data for the current transformers is entered

1 The nominal currents of the CTs are entered here

2 With this option, the CT star-point direction can be chosen according to the wiring of the CTs

Towards Protected Object Towards Line

Protection Device

In this tab the basic settings of the protection device are entered

1 Select the calculation method of the bias current This method depends on the relay type and Table 2

shows some examples of how to set these parameters Select No combined characteristic if the relay

uses only the phase with the highest current magnitude for the differential and bias current calculation For the AREVA P633 this option remains cleared as the relay calculates these currents in all three phases simultaneously

2 Test Max: is the test shot time if the relay does not trip It should be set higher than the expected relay

trip time but shorter than possible trip times of additional protection functions (for example, overcurrent protection) Since a differential relay typically trips instantaneously this time can be set quite low in this case (for example, 0.2 s) to speed up the test

3 The Delay Time defines the pause between two test shots and during this time no currents will be

generated Therefore, this time may be increased to prevent overheating of electromechanical relays

4 As all differential current settings are entered relative to the nominal current, this current has to be

defined With the settings Reference Winding and Reference Current, the nominal current which will be

used as the reference current can be selected In this example the reference current is the nominal current of the transformer on side 1

5 As described in chapter 2.3, the Zero Sequence Elimination has an influence on the currents during phase-to-ground faults Select IL - I0, if the relay uses numerical zero sequence elimination

6 The setting Idiff> defines the pick-up of the differential protection function The relay will not trip if the differential current does not exceed this setting Idiff>> defines the high differential current element If the

differential current exceeds this value the relay will always trip Figure 4 shows the tripping characteristic with these settings as defined in the Test Object and Figure 6 shows the corresponding relay settings of the AREVA P633 The relay setting Idiff>> of the P633 corresponds to the harmonic blocking whereas

the relay setting Idiff>>> corresponds to the Test Object parameter Idiff>>

7 The time settings tdiff> and tdiff>> define the trip times of the differential elements

8 The current and time tolerances can be obtained from the relay manual