Toshiba GRT100 User Manual

6 F 2 S 0 8 5 7

INSTRUCTION MANUAL

TRANSFORMER PROTECTION RELAY

GRT100 - ∗∗∗D

© TOSHIBA Corporation 2007

All Rights Reserved.

( Ver. 4.0 )

R

Safety Precautions

Before using this product, be sure to read this chapter carefully.
This chapter describes safety precautions when using the GRT100. Before installing and using the

equipment, read and understand this chapter thoroughly.

Explanation of symbols used

Signal words such as DANGER, WARNING, and two kinds of CAUTION, will be followed by
important safety information that must be carefully reviewed.

Indicates an imminently hazardous situation which will result in death or

DANGE

Indicates a potentially hazardous situation which could result in death or

WARNING

CAUTION Indicates a potentially hazardous situation which if not avoided, may result in

serious injury if you do not follow instructions.

serious injury if you do not follow instructions.

minor injury or moderate injury.

6 F 2 S 0 8 5 7

CAUTION Indicates a potentially hazardous situation which if not avoided, may result in

property damage.

⎯ 1 ⎯

R

DANGE

• Current transformer circuit

Never allow the current transformer (CT) secondary circuit connected to this equipment to be
opened while the primary system is live. Opening the CT circuit will produce a dangerous high
voltage.

WARNING

• Exposed terminals

Do not touch the terminals of this equipment while the power is on, as the high voltage generated
is dangerous.

• Residual voltage

Hazardous voltage can be present in the DC circuit just after switching off the DC power supply. It
takes about 30 seconds for the voltage to discharge.

• Fiber optic

Do not view directly with optical instruments.

6 F 2 S 0 8 5 7

CAUTION

• Earth

Earth the earthing terminal of the equipment securely.

CAUTION

• Operation conditions

Use the equipment within the range of ambient temperature, humidity and dust as detailed in the
specification and in an environment free of abnormal vibration.

• Ratings

Before applying AC voltage and current or DC power supply to the equipment, check that they
conform to the equipment ratings.

• Printed circuit board

Do not attach and remove the printed circuit board while the DC power to the equipment is on, as
this may cause the equipment to malfunction.

• External circuit

When connecting the output contacts of the equipment to an external circuit, carefully check the
supply voltage used and prevent the connected circuit from overheating.

• Connection cable

Carefully handle the connection cable without applying excessive force.

• Modification

Do not modify this equipment, as this may cause the equipment to malfunction, and any such
modifications will invalidate the warranty.

• Short-link

Do not remove a short-link which is mounted at the terminal block on the rear of the relay before

⎯ 2 ⎯

6 F 2 S 0 8 5 7

shipment, as this may cause the performance of this equipment such as withstand voltage, etc., to
reduce.

• Disposal

When disposing of this product, do so in a safe manner according to local regulations.
This product contains a lithium-ion battery, which should be removed at the end-of-life of the

product. The battery must be recycled or disposed of in accordance with local regulations. The
battery can be removed by withdrawing the Signal Processing module (SPM) from the relay case,
and cutting the connecting leads and plastic strap which hold the battery.

⎯ 3 ⎯

Contents

Safety Precautions 1

1. Introduction 8

2. Application Notes 10

2.1 Protection Scheme 10

2.2 Current Differential Protection 12

2.3 Restricted Earth Fault Protection 34

2.4 Overcurrent Protection 38

2.5 Thermal Overload Protection 43

2.6 Frequency Protection 44

2.7 Overexcitation Protection 46

2.8 Trip by External Devices 48

2.9 Tripping Output 49

2.10 Characteristics of Measuring Elements 51

6 F 2 S 0 8 5 7

2.2.1 Differential Scheme 12

2.2.2 Stability for CT Saturation during Through-fault Conditions 16

2.2.3 Matching of CT Secondary Currents 18

2.2.4 Connection between CT Secondary Circuit and the GRT100 22

2.2.5 Setting 23

2.10.1 Percentage Current Differential Element DIF 51

2.10.2 High-set Overcurrent Element HOC 52

2.10.3 Restricted Earth Fault Element REF 52

2.10.4 Inverse Time Overcurrent Element OCI and EFI 54

2.10.5 Definite Time Overcurrent element OC and EF 55

2.10.6 Thermal Overload Element THR 55

2.10.7 Frequency Element FRQ 57

2.10.8 Overexcitation Element V/F 57

3. Technical Description 58

3.1 Hardware Description 58

3.1.1 Outline of Hardware Modules 58

3.1.2 Transformer Module 61

3.1.3 Signal Processing Module 62

3.1.4 Binary Input and Output Module 63

3.1.5 Human Machine Interface (HMI) Module 67

3.2 Input and Output Signals 69

3.2.1 Input Signals 69

3.2.2 Binary Output Signals 70

3.2.3 PLC (Programmable Logic Controller) Function 71

3.3 Automatic Supervision 72

3.3.1 Basic Concept of Supervision 72

3.3.2 Relay Monitoring and Testing 72

3.3.3 PLC Data and IEC61850 Mapping Data Monitoring 73

⎯ 4 ⎯

6 F 2 S 0 8 5 7

3.3.4 IEC61850 Communication Monitoring 73

3.3.5 Failure Alarms 73

3.3.6 Trip Blocking 74

3.3.7 Setting 74

3.4 Recording Function 75

3.4.1 Fault Recording 75

3.4.2 Event Recording 76

3.4.3 Disturbance Recording 76

3.5 Metering Function 78

4. User Interface 79

4.1 Outline of User Interface 79

4.1.1 Front Panel 79

4.1.2 Communication Ports 81

4.2 Operation of the User Interface 82

4.2.1 LCD and LED Displays 82

4.2.2 Relay Menu 84

4.2.3 Displaying Records 87

4.2.4 Displaying the Status 90

4.2.5 Viewing the Settings 95

4.2.6 Changing the Settings 95

4.2.7 Testing 114

4.3 Personal Computer Interface 118

4.4 Communication Interface 118

4.4.1 RSM (Relay Setting and Monitoring System) 118

4.4.2 IEC 60870-5-103 Interface 119

4.4.3 IEC 61850 interface 120

4.5 Clock Function 120

5. Installation 121

5.1 Receipt of Relays 121

5.2 Relay Mounting 121

5.3 Electrostatic Discharge 121

5.4 Handling Precautions 121

5.5 External Connections 122

6. Commissioning and Maintenance 123

6.1 Outline of Commissioning Tests 123

6.2 Cautions 124

6.2.1 Safety Precautions 124

6.2.2 Cautions on Tests 124

6.3 Preparations 125

6.4 Hardware Tests 126

6.4.1 User Interfaces 126

6.4.2 Binary Input Circuit 127

6.4.3 Binary Output Circuit 128

6.4.4 AC Input Circuits 129

⎯ 5 ⎯

6 F 2 S 0 8 5 7

6.5 Function Test 130

6.5.1 Measuring Element 130

6.5.2 Timer Test 146

6.5.3 Protection Scheme 148

6.5.4 Metering and Recording 148

6.6 Conjunctive Tests 149

6.6.1 On Load Test 149

6.6.2 Tripping Circuit Test 149

6.7 Maintenance 151

6.7.1 Regular Testing 151

6.7.2 Failure Tracing and Repair 151

6.7.3 Replacing Failed Modules 153

6.7.4 Resumption of Service 155

6.7.5 Storage 155

7. Putting Relay into Service 156

⎯ 6 ⎯

6 F 2 S 0 8 5 7

Appendix A Block Diagram 157
Appendix B Signal List 159
Appendix C Variable Timer List 179
Appendix D Binary Output Default Setting List 181
Appendix E Details of Relay Menu and LCD & Button Operation 185
Appendix F Case Outline 193
Appendix G External Connections 199
Appendix H Relay Setting Sheet 207
Appendix I Commissioning Test Sheet (sample) 241
Appendix J Return Repair Form 247
Appendix K Technical Data 253
Appendix L Setting of REF Element 261
Appendix M Symbols Used in Scheme Logic 267
Appendix N Implementation of Thermal Model to IEC60255-8 271
Appendix O IEC60870-5-103: Interoperability and Troublehsooting 275
Appendix P IEC61850: MICS & PICS 287
Appendix Q Inverse Time Characteristics 321
Appendix R Failed Module Tracing and Replacement 325
Appendix S Ordering 331

 The data given in this manual are subject to change without notice. (Ver.4.0)

⎯ 7 ⎯

1. Introduction

GRT100 provides high-speed transformer and reactor protection, and realises high dependability
and security for diverse faults such as single-phase faults, multi-phase faults, overload and
over-excitation.

GRT100 is used as a main protection and backup protection of the following transformers and
reactors.

• Two-winding or three-winding power transformers

• Auto-transformers

• Generator-transformer units

• Shunt reactors

GRT100 is designed to provide stability under magnetizing inrush and overexcitation conditions.
GRT100 is available for mixed 1A/5A inputs

GRT100 provides the following metering and recording functions.

6 F 2 S 0 8 5 7

• Metering

• Fault records

• Event records

• Disturbance records

GRT100 provides the following human interfaces for relay setting or viewing of stored data.

• Relay front panel: LCD, LED display and operation keys

• Local PC

• Remote PC

Password protection is provided to change settings. Eight active setting groups are provided. This
allows the user to set one group for normal operating conditions while other groups may be set to
cover alternative operating conditions by binary input using the PLC.

GRT100 can provide the following serial interface ports:

- RS232C for a local PC and Relay Setting and Monitoring System (RSM100)

- RS485 for a remote PC, and Relay Setting and Monitoring System (RSM100) or Substation
control and Automation System (SAS) with IEC60870-5-103 protocol

- Fibre Optic (FO, option) for a remote PC, and Relay Setting and Monitoring System
(RSM100) or Substation control and Automation System (SAS) with IEC60870-5-103
protocol

- 100BASE-TX, or -FX (option) for Substation control and Automation System (SAS) with
IEC61850 protocol

Another interface IRIG-B port is provided for an external clock connection.
The RS232C port is located on the front panel of the relay. Other ports (RS485, FO, 100BASE-TX

and IRIG-B) are located on the rear of the relay.

Further, the GRT100 provides the following functions.

⎯ 8 ⎯

6 F 2 S 0 8 5 7

- Configurable binary inputs and outputs

- Programmable logic for I/O configuration, alarms, indications, recording, etc.

- Automatic supervision

GRT100 has two model series which differ according to the number of three-phase current inputs
for differential protection as follows:

Relay Type and Model

Relay Type:

- Type GRT100; Numerical transformer protection relay

Relay Model:

- Model 100 series; 2 three-phase current inputs, applied to two-winding transformers

• Model 101; 16 binary inputs, 13 binary outputs, 5 binary outputs for tripping

• Model 102; 16 binary inputs, 23 binary outputs, 5 binary outputs for tripping

- Model 200 series; 3 three-phase current inputs, applied to two- and three-winding transformers

• Model 201; 16 binary inputs, 13 binary outputs, 5 binary outputs for tripping

• Model 202; 16 binary inputs, 23 binary outputs, 5 binary outputs for tripping

• Model 203; 15 binary inputs (12-independent), 13 binary outputs, 3 binary outputs for tripping

• Model 204; 15 binary inputs (12-independent), 23 binary outputs, 3 binary outputs for tripping

Model 100 series have 2 three-phase current inputs and can be applied to two-winding
transformers. Model 200 series have 3 three-phase current inputs and can be applied to two- and
three-winding transformers.

⎯ 9 ⎯

2. Application Notes

GRT100 is applied to both main protection and backup protection for the following transformers
and reactors:

• Two-winding or three-winding power transformers

• Auto-transformers

• Generator-transformer units

• Shunt reactors

2.1 Protection Scheme

GRT100 provides the following protection schemes with measuring elements in parentheses.
Appendix A shows the block diagrams of the GRT100 series.

• Current differential protection (DIFT)

• Restricted earth fault protection (1REF-3REF)

6 F 2 S 0 8 5 7

• Time-overcurrent protection (1OC-3OC, 1OCI-3OCI, 1EF-3EF and 1EFI-3EFI)

• Thermal overload protection (THR)

• Frequency protection (FRQ)

• Overexcitation protection (V/F)

• Trip and/or indication of external devices (Buchholtz relay, pressure or temperature sensing

devices etc.)

The DIFT, provided with DIF and HOC elements and the REF are applied for main protection. For
details, see Sections 2.2, 2.3 and 2.10.

They provide transformer protection coverage as follows:
REF: protection for winding to earth faults of star-winding side
DIF: protection for all internal transformer faults (The DIF can be blocked by 2F or 5F

element.)

HOC: protection for all internal transformer faults, specifically for heavy internal faults,

high-speed operation (The HOC is not blocked by 2F or 5F element. The sensitivity is
set above the estimated maximum inrush current.)

DIF

HOC

REF

For earth fault only

Small

The number of measuring elements for the restricted earth fault protection and time-overcurrent
protection is dependent on the relay models.

Figure 2.1.1, 2.1.2 and 2.1.3 show typical application and the relationship between AC inputs and
the measuring elements applied in each model.

Differential current

⎯ 10 ⎯

Large

6 F 2 S 0 8 5 7

1CT

HV

LV

2CT

2nCT

HV

MV

GRT100

1OC/1OCI THR

VT

FRQ V/F

Calculate 3I0

1nCT

2nCT

1EF/1EFI

2OC/2OCI

2EF/2EFI

1REF

2REF

Figure 2.1.1 Measuring Elements of Model 100 series

GRT100

1CT

VT

LV

3CT

1nCT
3nCT

1OC/1OCI THR

FRQ V/F

1EF/1EFI

Calculate 3I0

1REF

DIFT

Calculate 3I0

DIFT

1CT

HV

LV

3CT

2CT

2OC/2OCI

2EF/2EFI

3OC/3OCI

3EF/3EFI

Figure 2.1.2 Measuring Elements of Model 200 series

GRT100

1OC/1OCI

2CT

VT

1nCT

2OC/2OCI

FRQ V/F

1EF/1EFI

3OC/3OCI

Calculate 3I

1REF

Calculate 3I0

2REF

Calculate 3I0

3REF

0

Calculate 3I0

DIFT

Figure 2.1.3 Measuring Elements of Model 200 series

⎯ 11 ⎯

2.2 Current Differential Protection

2.2.1 Differential Scheme

Current differential protection DIFT provides an overall transformer protection deriving phase
current from each transformer winding, calculating the differential current on a per phase basis
and detecting phase-to-phase and phase-to-earth faults.

The current differential protection is based on Kirchhoff’s first law that the vector summation of
all currents flowing into a protected zone must be zero. Figure 2.2.1.1 shows the principle of
current differential protection. Differential current (id) is the vector summation of all terminal
current of the transformer. The differential current (id=i1+i2) is zero because the current (i1)
equals current (−i2) during a load condition or an external fault. During an internal fault, the
differential current (id) is not zero because the current (i1) does not equal to the current (−i2), and
the DIFT operates.

I1

Primary

6 F 2 S 0 8 5 7

Secondary

I2

Transformer

i1

id=i1+i2

Differential cu r r ent
detection

Figure 2.2.1.1 Current Differential Protection

DIFT

i2

Scheme logic

Figure 2.2.1.2 shows the scheme logic of the current differential protection. Current differential
element DIFT comprises sub-elements HOC, DIF, 2F and 5F which operate for differential
current on a per phase basis.

Note: For the symbols used in the scheme logic, see Appendix M.
HOC is a high-set overcurrent element operating for differential current. It provides high-speed

protection for heavy internal faults.
DIF is a percentage restraining element and has dual restraining characteristics, a weak restraint in

the small current region and a strong restraint in the large current region, to cope with erroneous
differential current which may be caused due to output imbalance of the CTs in case of an external
fault. (For the characteristics, see Section 2.10.)

The DIF output signal can be blocked when the 2F or 5F elements detect second harmonic inrush
current during transformer energization or fifth harmonic components during transformer
overexcitation. Blocking is enabled by setting scheme switch [2F-LOCK] or [5F-LOCK] to “ON”.
The following two or three blocking schemes are selectable by scheme switch [DIFTPMD].

“3POR”: When any one phase of the 2F or 5F element operates, tripping by the DIF

element is blocked in all 3 phases. “3POR” is recommended for transformers with
large capacity whose second harmonic component may be low. Its blocking
function is stronger than that of the “1P” or “2PAND” below.

“1P”: When any phase of the 2F or 5F elements operate, only the corresponding phase

output of the DIF element is blocked.

“2PAND”: Even if 2F or 5F element operates during manetising inrush, the trip by DIF

element is allowed when any two phases or more of DIF element operate.

⎯ 12 ⎯

DIFT

+

+

1616
1617
1618

HOC-A

HOC-B

HOC-C

DIF-A

DIF-B

DIF-C

2F-A

2F-B

2F-C

5F-A

5F-B

5F-C

2F-Lock

5F-Lock

DIF-A_BLOCK
DIF-B_BLOCK
DIF-C_BLOCK

6 F 2 S 0 8 5 7

“2PAND” is recommended for a transformer with small or midium capacity
whose second harmonic component in inrush current is genarally higher than that
of transformer with large capacity. This mode is applicable if [Phase matching] is
set to “Beta”.

Protection by DIF and HOC can perform instantaneous three-phase tripping of up to five breakers.
Any of the five breaker tripping signals DIFT-1 to DIFT-5 are enabled or disabled by the scheme
switch [DIF1] to [DIF5] settings.

Note: Models 203 and 204 are not provided with DIFT-4 and DIFT-5, and perform tripping of up to

three breakers.

41

42

43

HOC

374

≥1

DIF

121

44

&

&

&

98

99

100

95

96

97

1
1
1

1

≥1

1

≥1

1

≥1

122

≥1

123

≥1 1

&

&

&

&

&

&

45

46

&

&

&

DIFTPMD
+

1

3POR
1P
2PAND (*2)

&

&

&

&

&

&

&

&

&

&

Note:

(*1) Models 203 and 204 are not provided with DIFT-4 and DIFT-5.
(*2) [Phase matching]="Beta" setting only

&

≥1

&

&

≥1

&

&

&

≥1

&

224

≥1

+

+

≥1

+

+

+

≥1

DIF1

DIF2

DIF3

DIF4

DIF5

&

&

&

&

&

TRIP

DIFT-1

DIFT-2

DIFT-3

DIFT-4 (*1)

DIFT-5 (*1)

DIF

HOC

≥1

330

&

331

&

352

DIFT-DIF TP

DIFT-HOC TP

DIFT TRIP

Figure 2.2.1.2 Scheme Logic of Current Differential Protection

⎯ 13 ⎯

Display mode following differential tripping

Following a trip output, GRT100 can display either the operating phase or the faulted phase
according to the user’s requirements as shown in Table 2.2.1.1. The operating phase or faulted
phase display is selectable by a setting in the Record menu.

Table 2.2.1.1 Operating Phase / Faulted Phase Display

Operating phase display Faulted phase display

6 F 2 S 0 8 5 7

Setting
(Setting/Record/Fault
record/Phase mode)

Displayed phase Operating phase

Application All two- and three-winding transformers

1 = Operating 2 = Fault

Generally, the operating phase of the DIF element
does not correspond with the faulted phase, but
depends on the transformer configuration and the
electrical quantities that are input to the GRT100
current differential calculation.

Faulted phase (for single-phase to earth, phase to
phase, two-phase to earth and three-phase to
earth faults)

• Faults at primary side or secondary side of Yy0

and Yy6 transformers

• Faults at primary side of Yd1, Yd3, Yd5, Yd7,

Yd9, Yd11, Yy2, Yy4, Yy8 and Yy10
transformers

• Faults at secondary side of Dy1, Dy3, Dy5, Dy7,

Dy9 and Dy11 transformers

• Faults on Dd2, Dd4, Dd6, Dd8 and Dd10

transformers, faults at Zig-zag connected side
of transformers and faults at tertiary side of
three-winding transformers are not supported.

Logic Refer to Figure 2.2.1.4.

∗ Phase (A/B/C) display is based on the operating
signal of DIF or HOC element, and “N” display is
based on the operating signal of REF and DIFT
elements. If the REF is not used, “N” is not
displayed.

Refer to Figure 2.2.1.4.
∗ Phase (A/B/C) display is based on the operating

signal of DIF or HOC element and a differential
current value, and “N” display is based on the
operating signal of REF and DIFT elements. If the
REF is not used, “N” is not displayed.

⎯ 14 ⎯

6 F 2 S 0 8 5 7

DIFT

HOC-A

HOC-B

HOC-C

DIF-A

DIF-B

DIF-C

2F-A

2F-B

2F-C

5F-A

5F-B

5F-C

2F-Lock

+

5F-Lock

+

41

42

43

[Op erating phase]

≥1

≥1

121

DIF

44

&

45

&

46

&

98

99

100

95

96

97

≥1

≥1

≥1

1

1

1

&

&

&

&

&

&

1REF

1REF1

+

1REF5

+

2REF

2REF1
+

2REF5

+

3REF

3REF1
+

3REF5

+

&

&

&

≥1

≥1

≥1

≥1

≥1

Fau lt ed phase

& ≥1

&

&

Not e: Mod els 203 and 20 4 are not provided with 1RE F-4,

1REF-5, 2R EF-4, 2REF-5, 3REF-4 and 3REF -5.

selection logic

[Fau lted ph ase]

Phas e A

Phas e B

Phas e C

&

Phas e N

Figure 2.2.1.4 Operating Phase and Faulted Phase Selection Logic

⎯ 15 ⎯

6 F 2 S 0 8 5 7

2.2.2 Stability for CT Saturation during Through-fault Conditions

For current differential protection of transformers, GRT100 has a strong restraint characteristic in
the large current region for erroneous differential current due to CT saturation. Further, GRT100
provides a CT saturation countermeasure function. If any CTs saturate due to a large through-fault
current, an apparent differential current is generated in the differential circuit and may cause false
operation of the differential protection.

Operation Principle

Even when a CT saturates under very large primary currents, the waveform of the saturated CT
secondary current has two identifiable periods in each cycle: a non-saturated period and a
saturated period. The GRT100 utilizes this phenomenon and provides very secure operation for
external faults with a large through-fault current.

Figure 2.2.2.1 shows a block diagram of the CT saturation countermeasure (CTS). The CTS has a
waveform discriminating element (WDE) and starting element (SE). WDE operates if the change
in the instantaneous value of the differential current is less than a specified percentage of the
change in the instantaneous value of the restraining current. In the CTs non-saturated period, the
differential current is theoretically zero for through-fault currents. The element operates in this
period.

Current
Input

Figure 2.2.2.1 Differential Element with CT Saturation Countermeasure

Differential Element
(DIFT_DIF)

Waveform Discriminating
Element

Starting Element

[CTSEN]

&

ON

&

0

CTS

t

The algorithm of this element is given by the following equation:

ΔId < 0.15×(ΔIp + ΔIn)

where,

ΔId : Change in the differential current Id
(ΔIp + ΔIn) : Change in the restraining current in the positive and negative cycles

Tripping
Output

Id : Differential current
Ip : Sum of positive input currents
In : Sum of negative input currents

SE operates when the sum of the absolute values of the difference between the instantaneous
values of current data at each current input from one cycle is greater than 0.5 × (CT secondary
rated current).

SE discriminates between healthy and faulty power system conditions and blocks the output of
WDE which may otherwise operate during healthy conditions.

Figure 2.2.2.2 shows CT secondary current waveforms of the incoming and outgoing terminals,

⎯ 16 ⎯

6 F 2 S 0 8 5 7

and also the differential current at the time of an external fault with outgoing terminal CT
saturation.

Incoming terminal
current

Outgoing terminal
current

Differential
current

No change period

Figure 2.2.2.2 CT Secondary Current Waveforms and Differential Current for an External

Fault with CT Saturation

From the inception of the fault until the CT secondary current at the outgoing terminal saturates,
the differential current Id is zero and the change in the differential current ΔId obtained from
equation (2) is also zero. However, the change in the restraining current given by equation (3) is a
sufficiently large positive value, so equation (1) is met and WDE operates.

SE detects changes in the terminal currents and rapidly operates, producing an AND output with
WDE. After this, since there is a period during which equation (1) is not satisfied, a certain time
delay is inserted to reliably block the operation of the DIFT_DIF differential element.

If, during an internal fault, there is a period during which the change in the instantaneous value of
the differential current is small due to CT saturation, WDE will not operate because the change in
the restraining current is also small during that period. Thus, during an internal fault, operation of
the differential element is not blocked falsely.

The CTS function can be disabled by the scheme switch [CTSEN].

⎯ 17 ⎯

×

6 F 2 S 0 8 5 7

2.2.3 Matching of CT Secondary Currents

The currents supplied to the differential elements must be matched in phase displacement and
amplitude under through-load and through-fault conditions.

Generally, it is difficult to completely match the incoming current with the outgoing current for
the relay input because the CT ratios at the primary, secondary and tertiary sides of a transformer
are not matched in terms of the CT ratio, phase angle and cancelling of zero-sequence current.

GRT100 provides the following matching method:

CT ratio: N1

Ip/N1=i1

GRT100

Matching of phase

angle / Zero-sequence

current elimination

Matching of CT ratio Matching of CT ratio

Primary

Ip

Transformer

i1 Kct2×i2

Kct1

Differential relay calculation

Secondary

Is
CT ratio: N2

Is/N2=i2

Matching of phase

angle / Zero-sequence

current elimination

Figure 2.2.2.1 Matching Method

GRT100 supports selectable two matching methods, α-method (Alpha) and β-method (Beta). The
method is selected by the scheme switch [Phase matching].

Phase matching is performed by setting according to the hands of a clock and the transformer
connections described in IEC60076-1. For details of the setting, refer to 2.2.5.

2.2.3.1 α-method phase matching

This method corrects the phase angle by using each winding current calculated as follows:

- Current substructed zero-sequence current from each phase current in Star- winding side of
transformer

- Phase-to-phase Current in Delta-winding side of transformer

The followings show calculation formula and current vectors in an example of a transformer
Yd11.

Is

1

Isa

Isb

Isc

Ipa

Ip1

Ipb Ipc

2

&

1

pI

=

&&&

pcIpbIpaI

−−

,

&

1

sI

=

3

&&

scIsaI

−

(1)

3

⎯ 18 ⎯

6 F 2 S 0 8 5 7

&&&

2

&

=

2

pI

−−

paIpcIpbI

&

,

2

sI

=

3

2

&

3

pI

=

&&&

pbIpaIpcI

−−

,

&

3

sI

=

3

where,

Further, zero-sequence current is eliminated from the relay input current (Ip∗) for the calculation
of the differential current as follows:

&&&

pcIpbIpaI

,, : Primary side terminal current of transformer

&&&

scIsbIsaI

,, : Secondary side terminal current of transformer

&&&

2

&

pI −=

=

1

2

&

pI −=

=

2

2

&

pI −=

=

3

−−

3

=

&&&

−−
=

3

&&&

−−
=

3

3

3

3

&&

saIsbI

−

(2)

3

&&

sbIscI

−

(3)

3

IpcIpbIpaIpapcIpbIpaI

++−

)(3

IpcIpbIpaIpbpaIpcIpbI

++−

)(3

IpcIpbIpaIpapbIpaIpcI

++−

)(3

IpoIpa

IpoIpb

IpoIpc

2.2.3.2 β-method (Traditional method) phase matching

This is a traditional method that delta current (phase-to-phase current) on the Star-winding side of
a Star/Delta transformer and phase current on the Delta-winding side of that is introduced into a
relay input for the calculation of the differential current. Traditionally, the phase matching is
realized by Delta connecting the CTs on the Star-winding side and by Star connecting the CTs on
the Delta-winding side. In GRT100, however, it is realized by software.

The followings show calculation formula and current vectors in an example of a transformer
Yd11.

Ipa

Ip1

I

&

1

pI

Ipb

&&

−

=

pbIpaI

Is1

,

I

Isc

saIsI&&=1

I

(4)

3

&&

pcIpbI

&

2

pI

−

=

,

sbIsI&&=2

(5)

3

&

=

3

pI

⎯ 19 ⎯

&&

−

paIpcI

,

scIsI&&=3

(6)

3

6 F 2 S 0 8 5 7

2.2.3.3 Zero-sequence current elimination

In addition to compensating for the phase angle between the primary and secondary currents of the
transforemer, also phase angle matching prevents unnecessary operation due to zero-sequence
current during an external earth fault, such as in the following cases.

Case 1:
When an external fault occurs at the star-connected side of the transformer shown in Figure

2.2.3.2, a zero-sequence current flows in star-connected side, but the zero-sequence current at the
delta-side circulates in the delta winding. The zero-sequence current is only fed into the star
winding side of the DIFT which is star-connected at the CT secondary, thus causing the DIFT to
operate incorrectly. In α-method phase matching, the zero-sequence current is eliminated from a
relay input current as described above. In β-method phase matching, the zero-sequence current is
eliminated from the relay input current by Delta connection on the Star-winding side.

Since the DIFT provides a function to eliminate the zero-sequence current by software, the DIFT
is insensitive the fault described.

I

0

Transforme

I

0

I

0

I

0

I

0

3

0

I

I

0

I
I

DIFT

Figure 2.2.3.2 External Earth Fault at the Star-connected side of a Transformer

Case 2:
When the delta winding of a power transformer is earthed through an earthing transformer as

shown in Figure 2.2.3.3 and the earthing transformer is located within the differential protection
zone, in case of an external earth fault the zero-sequence current flows only on the delta side of the
power transformer and appears as a differential current.

I

0

I

0

Earthing
Transforme

3I

0

Ia

Ib

Ic

DIF

I

0

Figure 2.2.3.3 External Earth Fault at the Delta-winding side of a Transformer with

in-zone Earthing Transformer

⎯ 20 ⎯

6 F 2 S 0 8 5 7

In α-method phase matching, since the DIFT provides a function to eliminate the zero-sequence
current by software, the DIFT is insensitive to the fault described.

In β-method phase matching, however, since the zero-sequence current is not eliminated because
of Star connection on the Delta-winding side, the DIFT may operate unnecessary.

In case the GRT100 is applied to a transformer with in-zone earthing transformer, the [Phase
matching] = “Alpha” setting is recommended.

2.2.3.4 Matching of CT Ratio

If I

to I3 correspond to 1CT to 3CT secondary currents, differential current Id is calculated

1

according to the following equation,

= kct1⋅I1 + kct2⋅I2 + kct3⋅I3

I

d

where kct1 to kct3 are settings corresponding to 1CT to 3CT.
Setting kct1 is obtained by using the following equation.
kct1 = I

= I

n/Ibase1

/( 3 × I

n

) if 1CT is delta-connected.

base1

where
I

= rated secondary current of 1CT (1A or 5A)

n

I
= transformer capacity(kVA)/(
If the 1CT secondary circuit is delta-connected,

= secondary current of 1CT based on the kVA rating of the power transformer.

base1

3 × rated voltage(kV)) × CT ratio of 1CT

3 × I

is used instead of I

base1

above.
Settings kct2 and kct3 are obtained in the same way.
The differential current I
kct1 × I

to kct3 × I3 are equal to the rated secondary current of each CT when the rated line

1

is zero under through-load and through-fault conditions.

d

currents based on the kVA rating of the power transformer flow.

in the equation

base1

⎯ 21 ⎯

9

12

22 11

21

6 F 2 S 0 8 5 7

2.2.4 Connection between CT Secondary Circuit and the GRT100

GRT100 is provided with 2 or 3 three-phase current input terminals depending on the relay model.
To validate the phase angle matching described previously and apply in-phase current from each

winding to the relay, connect the CT secondary circuits to the current input terminals of the relay
as follows;

As shown below, the phases used in the phase angle setting (indicated by an arrowhead) must be
connected to the AC input terminals with the lowest number in the terminal group such as 1, 9, 17,
then the other two phases should be connected to the terminals with a larger number clockwise
from the setting phase, such as 3 and 5, 11 and 13, or 19 and 21.

Primary

Tertiary

Secondary

3

1 5

2 4 6

17 19

GRT100

18 10

13

14 20

Figure 2.2.4.1 Connection of CT Secondary Circuit and the GRT100

Terminal numbers and corresponding input currents are shown in the following table.

Model Terminal block Terminal number Input current

100 series / 200 series TB1 1-2
3-4 Current of primary winding
5-6
9-10
11-12 Current of secondary winding
13-14
17-18
19-20 Current of tertiary winding
21-22

⎯ 22 ⎯

6 F 2 S 0 8 5 7

2.2.5 Setting

The following shows the setting elements necessary for the current differential protection and their
setting ranges. Setting can be performed on the LCD screen or PC screen.

Element Range Step Default Remarks

DIFT

DIF

ik

0.10 − 1.00

(∗)

0.01 0.30 Minimum operating current

p1
p2
kp
k2f
k5f

HOC kh
CT matching
kct1
CT ratio kct2
kct3
Phase angle matching
yd_p 1(star) / 2(delta) 1 Primary winding
(α-method)
yd_t 1(star) / 2(delta) 1 Tertiary winding
vec_s 0 – 11 1 0 Phase angle difference between primary

vec_t 0 – 11 1 0 Phase angle difference between primary

If [Phase matching]=Alpha setting

yd_s 1(star) / 2(delta) 1 Secondary winding

10 − 100%
10 − 200%

1.00 − 20.00(*)
10 − 50%
10 − 100%

2.00 − 20.00(*)

0.05 − 50.00

0.05 − 50.00

0.05 − 50.00

1% 100% % slope of small current region
1% 200% % slope of large current region

0.01 1.00 Break point of dual characteristics
1% 15% Second harmonic detection
1% 30% Fifth harmonic detection

0.01 2.00 High-set overcurrent protection

0.01 1.00 Primary winding

0.01 1.00 Secondary winding

0.01 1.00 Tertiary winding

and secondary

and tertiary
If [Phase matching]=Beta setting
d1
(β-method)
d3
Scheme switch

[Phase matching] Alpha / Beta Beta Matching methods of CT secondary

[DIFTPMD] 3POR / 1P 3POR Trip mode (if [Phase matching] = Alpha)
[DIFTPMD] 3POR / 2PAND / 1P
[2F – LOCK] Off / On On Block by second harmonic
[5F - LOCK] Off / On On Block by fifth harmonic

[DIF1] to [DIF5] Off / On (**) Output tripping signal

[CTSEN] Off / On Off CT saturation function

(∗): Multiplier of CT secondary rated current including CT ratio correction.
(**): Default settings are dependent on the models. See Appendix H.

d2

0 − 11
0 − 11
0 − 11

1 0 Primary winding
1 0 Secondary winding
1 0 Tertiary winding

currents

3POR Trip mode (if [Phase matching] = Beta)

⎯ 23 ⎯

6 F 2 S 0 8 5 7

Setting of ik

ik determines the minimum operation sensitivity of the DIF element. ik is set as a ratio to the CT
secondary rated current.

The minimum sensitivity setting ik is determined from the maximum erroneous differential
current under normal operating conditions.

Setting of p1, p2 and kp

Percentage restraining factor (% slope)

= (Differential current) / (Through current)
= (Differential current) / [{(Incoming current) + (Outgoing current)} /2]

p1 is the percentage restraining factor which defines the DIF restraining characteristic in the small
current region. The setting is determined by the sum of:

• CT accuracy error (generally considered as 5%)

• Tap error: Error between maximum/minimum tap and the middle tap when taking the middle

tap of the tap changer as a reference.

• Matching error: The error due to CT mismatch may be small enough to be neglected in the
setting.

• Relay calculation error, and others (5%)

The recommended setting is “Sum of above” × 1.5 (margin).
p2 is the percentage restraining factor which defines the restraining characteristic in the large

current region. The setting is determined from the maximum erroneous differential current which
is generated when a large through fault current flows.

kp is the break point of the dual percentage restraining characteristics. It is set above the maximum
operating current level of the transformer between the maximum forced-cooled rated current and
the maximum emergency overload current level, as a ratio to the CT secondary rated current.

Setting of k2f

k2f is set to detect the second harmonic content in the inrush current during transformer
energization and blocks GRT100 to prevent incorrect operation due to the inrush current. A
setting of 15% is suggested if there is no data on the minimum second harmonic content.

Setting of k5f

k5f is set to detect the fifth harmonic content during transformer over-excitation and blocks
GRT100 to prevent incorrect operation due to transient over-excitation conditions.

A setting of 30% is suggested if there is no data on the minimum fifth harmonic content.

Setting of k

h

Kh is the HOC setting and should be set above the estimated maximum inrush current.
The recommended setting is more than “Maximum peak value of Inrush current” × kct.

Setting for CT ratio matching

Taking the transformer shown in Figure 2.2.5.1 as an example, the CT ratio matching settings kct1
to kct3

can be calculated as follows. For transformer capacity, take the maximum of the rated

capacites of the three windings.

⎯ 24 ⎯

A

6 F 2 S 0 8 5 7

Calculation steps Primary Secondary Tertiary

3

(1) Transformer capacity (kVA)

40 × 10
(2) Voltage(kV) 154 66 11
(3) Rated line current(A) 150 350 2100

=(1)/(

3 × (2))
(4) CT ratio 60 120 240
(5) Secondary rated line current(A) =(3)/(4)

2.50 2.92 8.75
(6) CT secondary rating(A) 5 5 5
(7) Setting =(6)/(5) Kct1=2.00 Kct2=1.71 Kct3=0.57

Note: kct1 to kct3 should be set to 2.00 or less. If more, the CT ratio matching of relay input current

may be not stable.

CT1
300/5

Primary
40MVA

154kV

B

Tertiary

12MVA

11kV

Secondary

40MVA

66kV

CT3
1200/5

CT2
600/5

C

kct1 kct3

GRT100

kct2

Figure 2.2.5.1 CT Ratio Matching

As explained in Section 2.2.3 for Mathcing of CT Secondary Currents, examples of setting for
both α-method and β-method are described as follows:

⎯ 25 ⎯

2 3 4

10

6 F 2 S 0 8 5 7

Setting for phase angle matching

The phase angle difference between line currents on either side of the power transformer are
corrected by setting according to the hands of a clock and the transformer connections described in
IEC60076-1 as follows:

(When α-method is selected for [Phase matching])

If a winding is star-connected, set 1 (=star) for winding setting yd_p, yd_s, and yd_t. If
delta-connected, set 2 (=delta). Next, set the phase angle difference vec_s and vec_t from the
primary winding as a lagging angle winding expressed in hours. One hour corresponds to lagging
by thirty degrees.

Note: In the case of a zigzag connected winding, set 2 (=delta).

Example: Setting for star/star/delta transformer.

Primary

Secondary

Tertiary

IEC60076-1

yd_p yd_s vec_s yd_t vec_t
Y y 0 d 11 1 1 0 2 11

Setting

yd_p: Because the primary winding is star-connected, set 1.
yd_s: Because the secondary winding is star-connected, set 1.
vec_s: Because the secondary winding is in phase with the primary winding, set 0.
yd_t: Because the tertiary winding is delta-connected, set 2.
vec_t: Because the tertiary winding lags the primary winding by 330°, set 11.

The settings for the transformer connections described in IEC60076-1 are listed in Table 2.2.5.2.

Note: The following calculation is performed in the relay for phase angle correction.

Table 2.2.5.1 Phase Angle Matching Calculation

O’clock Calculation Remarks

0
1

2
3

4
5

6
7

8
9

10
11

Ia’ = (2Ia − Ib − Ic)/ 3 Ib’ = (2Ib − Ic − Ia)/ 3
Ia’ = (Ia – Ib)/

Ia’ = (Ia − 2Ib + Ic)/ 3 Ib’ = (Ia + Ib − 2Ic)/ 3
Ia’ = (Ic − Ib)/

Ia’ = (2Ic − Ia − Ib)/ 3 Ib’ = (2Ia − Ib − Ic)/ 3
Ia’ = (Ic – Ia)/

Ia’ = (Ib + Ic −2Ia)/ 3 Ib’ = (Ia − 2Ib + Ic)/ 3
Ia’ = (Ib − Ia)/

Ia’ = (2Ib − Ia − Ic)/ 3 Ib’ = (2Ic − Ia − Ib)/ 3
Ia’ = (Ib – Ic)/

Ia’ = (Ia + Ib − 2Ic)/ 3 Ib’ = (Ib + Ic −2Ia)/ 3
Ia’ = (Ia – Ic)/

3 Ib’ = (Ib − Ic)/ 3 Ic’ = (Ic – Ia)/ 3

3 Ib’ = (Ia – Ic)/ 3 Ic’ = (Ib − Ia)/ 3

3 Ib’ = (Ia – Ib)/ 3 Ic’ = (Ib – Ic)/ 3

3 Ib’ = (Ic − Ib)/ 3 Ic’ = (Ia – Ic)/ 3

3 Ib’ = (Ic – Ia)/ 3 Ic’ = (Ia – Ib)/ 3

3 Ib’ = (Ib − Ia)/ 3 Ic’ = (Ic − Ib)/ 3

Ic’ = (2Ic − Ia − Ib)/ 3

Ic’ = (Ib + Ic −2Ia)/ 3

11

Ic’ = (2Ib − Ia − Ic)/ 3

9

Ic’ = (Ia + Ib − 2Ic)/ 3

8

Ic’ = (2Ia − Ib − Ic)/ 3

Ic’ = (Ia − 2Ib + Ic)/ 3

Setting value

0

7

6

1

5

⎯ 26 ⎯

Table 2.2.5.2 Setting for Phase Angle Matching (for α-method)

(a) Settings for typical connections of 2-windings transformer

Transformer connections
described in IEC60076-1
Primary, Secondary
(P) (S)

Yy0

Dd0

Yd1

Dy1

Dd2

Dd4

Yd5

Dy5

Yy6

Dd6

Yd7

Dy7

Dd8

Dd10

Yd11

Dy11

Dz10

Note: A 2-windings transformer covers a 3-windings transformer with a stabilizing-winding circuit

for which 2-windings transformer protection relay can be applied.

Settings for phase angle correction Remarks
Primary, Secondary, Phase angle Diff.

(yd_p) (yd_s) (vec_s)

1 1 0

2 2 0

1 2 1

2 1 1

2 2 2 P: 1 O’clock

2 2 4 P: 1 O’clock

1 2 5 P: 0 O’clock

2 1 5 P: 7 O’clock

1 1 6 P: 0 O’clock

2 2 6 P: 1 O’clock

1 2 7 P: 0 O’clock

2 1 7 P: 5 O’clock

2 2 8 P: 1 O’clock

2 2 10 P: 1 O’clock

1 2 11 P: 0 O’clock

2 1 11

2 2 10 P: 1 O’clock

Phase angle matching
calculation (Table 2.2.5.1)

P: 0 O’clock
S: 0 O’clock

P: 1 O’clock
S: 1 O’clock

P: 0 O’clock
S: 1 O’clock

P: 11 O’clock
S: 0 O’clock

S: 3 O’clock

S: 5 O’clock

S: 5 O’clock

S: 0 O’clock

S: 6 O’clock

S: 7 O’clock

S: 7 O’clock

S: 0 O’clock

S: 9 O’clock

S: 11 O’clock

S: 11 O’clock
P: 1 O’clock

S: 0 O’clock

S: 11 O’clock

6 F 2 S 0 8 5 7

⎯ 27 ⎯

(b) Settings for typical connections of 3-windings transformer

6 F 2 S 0 8 5 7

Transformer connections described in
IEC60076-1
Primary , Secondary,
Tertiary
(P) (S) (T)

Yy0d1

Yy0d11

Yd1d1

Yd11d11

Dy11d0

Dy1d0

Dd0d0

Yy0y0

Settings for phase angle correction
Primary, Secondary, PA Diff., Tertiary, PA Diff.

(yd_p) (yd_s) (vec_s) (yd_t) (vec_t)

1 1 0 2 1

1 1 0 2 11

1 2 1 2 1

1 2 11 2 11

2 1 11 2 0

2 1 1 2 0

2 2 0 2 0

1 1 0 1 0

Remarks
Phase angle matching
calculation (Table

2.2.5.1)

P: 0 O’clock
S: 0 O’clock
T: 1 O’clock

P: 0 O’clock
S: 0 O’clock
T: 11 O’clock

P: 0 O’clock
S: 1 O’clock
T: 1 O’clock

P: 0 O’clock
S: 11 O’clock
T: 11 O’clock

P: 1 O’clock
S: 0 O’clock
T: 1 O’clock

P: 11 O’clock
S: 0 O’clock
T: 11 O’clock

P: 1 O’clock
S: 1 O’clock
T: 1 O’clock

P: 0 O’clock
S: 0 O’clock
T: 0 O’clock

Note: Dotted line: Reference phase

<How to set phase angle matching for GRT100>

Reference phase for phase angle matching
The phase of a star-connected winding side is used as the reference phase for phase angle

matching.

Yd: primary
Dy: secondary
Yy: primary

Dd: the reference vector leads the A phase of the primary side by 30°.
Phase rotation
The relationship between each terminal current vector of a transformer, which depends on the

transformer connection and the connection between the transformer and the power system, must
be checked. The phase displacement of a delta-connected side may not be determined only by the
transformer connection described in IEC60076. Table 2.2.5.3 shows an example illustrating the
connection of a transformer and power system and their current vectors when a Yd1 type
transformer is connected to the power system with both clockwise and anticlockwise phase
rotation. In this case, the setting for phase angle correction is not corresponding to that of Table

2.2.5.1.

⎯ 28 ⎯

−

−

−

−

−

−

−

−

−

−

−

6 F 2 S 0 8 5 7

Table 2.2.5.3 Transformer Connection and Current Vector

Connection between
Yd1 Transformer
and Power system

Each winding
connection and
Incoming/Outgoing
current

Incoming current
vector and Outgoing
current vector

Delta-side connected with 30° lagging Delta-side connected with 30° leading

Primary

a

I1a

b

I

1b

c

I

1c

a
b
c

Transformer

U
V
W

Transformer

U

V

W

Yd1

I

2a

I

2b

I

2c

Secondary

u

a

v

b

w

c

u

a

I

2a’=I2a

v

b

I

2b’=I2b

w

c

I

2c’=I2c

Primary

a

I

I

2c

I

2a

I

2b

1a

b

I

1b

c

I

1c

a
b
c

Transformer

U
V
W

Transformer

U

I

1c

V

I

1b

W

I

1a

Yd1

I2c
I
I

2b

2a

Secondary

u

a

v

b

w

c

u

a

I

2a’=I2a

v

b

I

2b’=I2b

w

c

I

2c’=I2c

I

2b

I

2c

I

2a

I

I

1a

I

1c

Incoming

Current

I

1b

I

2a’=I2a

2b’=I2b

I

2b

I

2c

Outgoing

Current

I

2a

I

2c

30

°

I

I

2c’=I2c

2b

I

2a

I

I

1c

Incoming

Current

1a

I

2b’=I2b

I1b

I2b

I

−

2c

I

2a

Outgoing

Current

I

2c’=I2c

I

2c

30°

I

2a’=I2a

I

2a

I

2b

Setting Yd_p=1, yd_s=2, vec_s=1 (Same as Yd1) Yd_p=1, yd_s=2, vec_s=11 (same as Yd11)

Auto-transformer (with internal delta-winding)
Set Yy0.
Zigzag connected transformer
Set yd_p, yd_s and vec_s to 2 (=delta) for zigzag connected side. Zero-sequence current is

canceled.
When three-winding model (model 200 series) applied to two-winding transformer:
Keep the settings of “yd_t” and “vec_t” to the default setting values.
One-and-a-half breaker system
When applied to one-and-a-half breaker system, note the DIFT and REF setting as shown in Table

2.2.5.4.

Table 2.2.5.4 Example of DIFT and REF Setting

Setting
DIFT 1REF 2REF

Yd11

One-and-a-half breaker system

Yd11

Yy0d11

Yd11 yd_p=1

yd_s=2

vec_s=11

Yy0d11

yd_p=1
yd_s=1

vec_s=0

yd_t=2

vec_s=11

Yy0d11

yd_p=1
yd_s=1

vec_s=0

yd_t=2

vec_s=11

1I0 --

2Io --

1I0 1I0

⎯ 29 ⎯