Easergy P3T32

Transformer protection relay

User Manual
P3T/en M/J006
11/2022

www.schneider-electric.com
Transformer protection relay 2 Product introduction

2 Product introduction

2.1 Warranty
This product has a standard warranty of 10 years.

2.2 Product overview

The relay has a modular design, and it can be optimized to medium and big sized
transformers.

Main characteristic and options

• The relay is a transformer protection relay for medium sized transformers in

power distribution.
• The relay has optional arc flash communications and high speed outputs to
allow for simple arc flash system configuration.
• Two alternative display options
◦ 128 x 128 LCD matrix
◦ 128 x 128 LCD matrix detachable
• Power quality measurements and disturbance recorder enable capture of
transients
• Wide range of communication protocols, for example:
◦ Modbus TCP/IP
◦ Profibus
◦ IEC61850

The following options depend on the order code:

• power supply options

• ground fault overcurrent input sensitivity
• number of digital inputs
• number of trip contacts
• integrated arc-options (point sensors)
• various possibilities with communication interfaces:
◦ high-speed outputs
◦ simple arc flash system communications (BIO)
◦ fiber loop
• front panel protection of IP54

Protection functions

• Universal, adaptive protection functions for user-configurable transformer

applications
• Neutral overvoltage, overvoltage and frequency protection including
synchronism check for two breakers
• Single-line diagram, measurements and alarms in the user-machine interface
(UMI)
• User-configurable interlocking for primary object control
• Optional arc flash detection utilizing point sensors and a fiber loop that can
provide system wide arc flash detection.

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Virtual injection

• Current and voltage injection by manipulating the database of the product by

setting tool disturbance recorder file playback through the product's database

Robust hardware

• User-selectable Ethernet, RS485 or RS232 -based communication interfaces

• Designed for demanding industrial conditions with conformal-coated printed
circuit boards
• Standard USB connection (type B) for Easergy P3 setting software

Common technology for cost efficiency

• Powerful CPU supporting IEC 61850

• Thanks to four setting groups, adaptation to various protection schemes is
convenient

User-machine interface (UMI)

• Clear LCD display for alarms and events

• Single-line diagram mimic with control, indication and live measurements
• Programmable function keys and LEDs
• Circuit breaker ON/OFF control
• Common firmware platform with other Easergy P3 range protection relays

NOTE: If the device has been powered off for more than about one week, the
UMI language after starting is IEC but after about two minutes, it is
automatically updated to ANSI.

2.3 Product selection guide

The selection guide provides information on the Easergy P3 platform to aid in the
relay selection. It suggests Easergy P3 types suitable for your protection
requirements, based on your application characteristics. The most typical
applications are presented along with the associated Easergy P3 type.

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Table 3 - Applications

Easergy P3 Standard Easergy P3 Advanced

4 3
1

Voltage – – –

Feeder P3F30
w.
directional
–
P3L30
w. line diff. &
P3U30 distance
with
Transformer directional P3T32
o/c – with
P3U10 P3U20
with voltage differential
protection
Motor P3M32
P3M30 with
differential

Generator P3G32
P3G30 with
differential

Measuring Phase current 1/5A CT (x3) 1/5A CT (x3) or 1/5A CT (x3) or 1/5A CT (x6)
inputs LPCT (x3) LPCT (x3)2)

Residual current 1/5A CT or 0.2/1A CT or CSH 5/1A+1/0.2A or 5/1A+1/0.2A +

or 5/1A + CSH 5/1A+1/0.2A
CT

Voltage VT (x1) VT (x4) or VT (x4) or LPVT VT (x4)

LPVT (x4) (x4)2)

Arc flash sensor input – 0 to 4 point 0 to 4 point

sensor sensor

Digital I/O Input 2 8/10 14/16 6 to 36 6 to 16

Output 5 + WD 5/8 + WD 11/8 + WD 10 to 21 + WD 10 to 13 + WD

Analog I/O Input – 0 or 4 3) 0 or 4 3)

Output – 0 or 4 3) 0 or 4 3)

Temperature sensor input – 0 or 8 or 123) 0 or 8 or 123)

Front port USB USB

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Easergy P3 Standard Easergy P3 Advanced

Nominal power supply 24 V dc or 24...48 V dc or 48...230 V ac/dc4) 24...48 V dc or 110...240 V ac/dc

Ambient temperature, in service -40...60°C (-40...140°F) -40...60°C (-40...140°F)

2) LPCT/LPVT available for P3F30 and P3M30 only
3) Usingexternal RTD module
4) Check the available power supply range from the device's serial number label.

Table 4 - Communication & others

Easergy P3 Standard Easergy P3 Advanced

4 3
1

Communication

Rear ports RS-232 – ■ ■ ■

IRIG/B ■ ■ ■

RS-485 – ■ Using external Using external

I/O module I/O module

Ethernet – ■ ■ ■

Protocols IEC 61850 Ed1 – ■ ■ ■ ■

& Ed2

IEC 60870-5-101 – ■ ■ ■ ■

IEC 60870-5-103 – ■ ■ ■ ■

DNP3 Over – ■ ■ ■ ■
Ethernet

Modbus serial – ■ ■ ■ ■

Modbus TCP/IP – ■ ■ ■ ■

Ethernet/IP – ■ ■ ■ ■

Profibus DP – ■ ■ ■ ■

SPAbus – ■ ■ ■ ■

Redundancy RSTP – ■ ■ ■ ■
protocols
PRP – ■ ■ ■ ■

Others

Control 1 object 8 objects 8 objects

Mimic Mimic Mimic

Logic Matrix ■ ■

Logic equations ■ ■

Cyber security Password Password

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Easergy P3 Standard Easergy P3 Advanced

Withdrawability (Pluggable ■ –
connector)

Remote UMI – ■

NOTE: The numbers in the following tables represent the amount of stages
available for each Easergy P3 type.

Table 5 - Protection functions for P3U

Protection functions ANSI Feeder Feeder P3U30 Motor P3U10/20 Motor P3U30
code P3U10/20

Fault locator 21FL – 1 – 1

Synchronism check5) 25 – 2 – 2

Undervoltage 27 – 3 – 3

Directional power 32L, 32R – 2 – 2

Phase undercurrent 37 1 1 1 1

RTD temperature 38/49T 12 12 12 12

monitoring6)

Negative sequence 46 – – 2 2
overcurrent (motor,
generator)

Cur. unbalance, broken 46BC 1 1 – –

conductor

Incorrect phase sequence 47 – – 1 1

Negative sequence 47 – 3 – 3
overvoltage protection

Motor start-up 48/51LR – – 1 1

supervision / Locked rotor

Thermal overload 49 1 1 1 1

Phase overcurrent 50/51 3 3 3 3

Ground fault overcurrent 50N/51N 5 5 5 5

Breaker failure 50BF 1 1 1 1

SOTF 50HS 1 1 1 1

Capacitor bank 51C 2 2 2 2

unbalance7)

Voltage-dependent 51V – 1 – 1
overcurrent

Overvoltage 59 – 3 – 3

Capacitor overvoltage 59C 1 1 – –

Neutral overvoltage 59N 3 3 3 3

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Protection functions ANSI Feeder Feeder P3U30 Motor P3U10/20 Motor P3U30
code P3U10/20

CT supervision 60 1 1 1 1

VT supervision 60FL – 1 – 1

Restricted ground fault 64REF 1 1 1 1

with external connection
64BEF
(high impedance)

Starts per hour 66 – – 1 1

Directional phase 67 – 4 – 4
overcurrent

Directional ground fault 67N 3 3 3 3

o/c

Transient intermittent 67NI 1 1 – –

Second harmonic inrush 68F2 1 1 1 1

detection

Fifth harmonic detection 68H5 1 1 1 1

Vector shift 78V – – – 1

Auto-Recloser 79 5 5 – –

Over or under frequency 81 – 2/2 – 2/2

Rate of change of 81R – 1 – 1

frequency

Under frequency 81U – 2 – 2

Lockout 86 1 1 1 1

Programmable stages 99 8 8 8 8

Cold load pickup (CLPU) – 1 1 1 1

Programmable curves – 3 3 3 3

Setting groups 8) – 4 4 4 4
5) The availability depends on the selected voltage measurement mode (in the Scaling setting view in Easergy Pro)
6) Using external RTD module
7) Capacitor bank unbalance protection is connected to the ground fault overcurrent input and shares two stages with the ground fault

overcurrent protection.
8) Not all protection functions have 4 setting groups. See details in the manual.

Table 6 - Protection functions for Px3x

Protection functions ANSI P3F30 P3L30 P3M30 P3M32 P3G30 P3G32 P3T32
code

Distance 21 – 1 – – – – –

Under-impedance 21G – – – – 2 2 –

Fault locator 21FL 1 1 – – – – –

Overfluxing 24 – – – – 1 1 1

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Protection functions ANSI P3F30 P3L30 P3M30 P3M32 P3G30 P3G32 P3T32
code

Synchronism check9) 25 2 2 2 2 2 2 2

Undervoltage 27 3 3 3 3 3 3 3

Positive sequence under- 27P – – – – 2 2 –

voltage

Directional power 32L, 32R 2 2 2 2 2 2 –

Phase undercurrent 37 – – 1 1 – – –

RTD temperature 38/49T 12 12 12 12 12 12 12

monitoring10)

Loss of field 40 – – – – 1 1 –

Under-reactance 21/40 – – – – 2 2 –

Negative sequence 46 – – 2 2 2 2 2
overcurrent (motor,
generator)

Cur. unbalance, broken 46BC 1 1 – – – – –

conductor

Incorrect phase sequence 47 – – 1 1 – – –

Negative sequence 47 3 3 3 3 3 3 3
overvoltage protection

Excessive start time, 48/51LR – – 1 1 – – –

locked rotor

Thermal overload 49 1 1 1 1 1 1 1

Phase overcurrent 50/51 3 3 3 3 3 3 3

Ground fault overcurrent 50N/51N 5 5 5 5 5 5 5

Breaker failure 50BF 1 1 1 1 1 1 1

SOTF 50HS 1 1 1 1 1 1 1

Capacitor bank 51C 2 2 2 2 2 2 2

unbalance11)

Voltage-dependent 51V 1 1 – – 1 1 –
overcurrent

Overvoltage 59 3 3 3 3 3 3 3

Capacitor overvoltage 59C 1 1 – – – – –

Neutral overvoltage 59N 2 2 2 2 2 2 2

CT supervision 60 1 1 1 1 1 2 2

VT supervision 60FL 1 1 1 1 1 1 1

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Protection functions ANSI P3F30 P3L30 P3M30 P3M32 P3G30 P3G32 P3T32
code

Restricted ground fault 64REF 1 1 1 1 1 1 1

with external connection
64BEF
(high impedance)

Restricted ground fault 64REF – – – – – 1 1

(low impedance)

Stator ground fault 64S – – – – 1 1 –

Starts per hour 66 – – 1 1 – – –

Directional phase 67 4 4 4 4 4 4 4
overcurrent

Directional ground fault 67N 3 3 3 3 3 3 3

o/c

Transient intermittent 67NI 1 1 – – – – –

Second harmonic inrush 68F2 1 1 1 1 1 1 1

detection

Fifth harmonic detection 68H5 1 1 1 1 1 1 1

Pole slip 78PS – – – – 1 1 –

Auto-Recloser 79 5 5 – – – – –

Over or under frequency 81 2/2 2/2 2/2 2/2 2/2 2/2 2/2

Rate of change of 81R 1 1 1 1 1 1 1

frequency

Under frequency 81U 2 2 2 2 2 2 2

Lockout 86 1 1 1 1 1 1 1

Line differential 87L – 2 – – – – –

Machine differential 87M – – – 2 – 2 –

Transformer differential 87T – – – – – – 2

Programmable stages 99 8 8 8 8 8 8 8

Arc flash detection (AFD) – 8 8 8 8 8 8 8

Cold load pickup (CLPU) – 1 1 1 1 1 1 1

Programmable curves – 3 3 3 3 3 3 3

Setting groups 12) – 4 4 4 4 4 4 4

9) The availability depends on the selected voltage measurement mode (in the Scaling setting view in Easergy Pro)
10) Using external RTD module
11) Capacitor bank unbalance protection is connected to the ground fault overcurrent input and shares two stages with the ground fault

overcurrent protection.
12) Not all protection functions have 4 setting groups. See details in the manual.

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Table 7 - Control functions

Control functions P3U10/ P3U30 P3F30 P3L30 P3M30 P3M32 P3G30 P3G32 P3T32
20

Switchgear control and 1/2 4 6 6 6 6 6 6 6

monitoring

Switchgear monitoring – – 2 2 2 2 2 2 2
only

Programmable switchgear ■ ■ ■ ■ ■ ■ ■ ■ ■
interlocking

Local control on single- ■ ■ ■ ■ ■ ■ ■ ■ ■

line diagram

Local control with O/I keys ■ ■ ■ ■ ■ ■ ■ ■ ■

Local/remote function ■ ■ ■ ■ ■ ■ ■ ■ ■

Function keys 2 2 2 2 2 2 2 2 2

Custom logic (logic ■ ■ ■ ■ ■ ■ ■ ■ ■

equations)

Control with Smart App ■ ■ ■ ■ ■ ■ ■ ■ ■

Table 8 - Measurements

Measurement P3U10/ P3U30 P3F30 P3L30 P3M30 P3M32 P3G30 P3G32 P3T32
20

RMS current values ■ ■ ■ ■ ■ ■13) ■ ■13) ■13)

RMS voltage values ■ ■ ■ ■ ■ ■ ■ ■ ■

RMS active, reactive and – ■ ■ ■ ■ ■ ■ ■ ■

apparent power

Frequency ■ ■ ■ ■ ■ ■ ■ ■ ■

Fundamental frequency ■ ■ ■ ■ ■ ■13) ■ ■13) ■13)

current values

Fundamental frequency – ■ ■ ■ ■ ■ ■ ■ ■
voltage values

Fundamental frequency – ■ ■ ■ ■ ■ ■ ■ ■
active, reactive and
apparent power values

Power factor – ■ ■ ■ ■ ■ ■ ■ ■

Energy values active and – ■ ■ ■ ■ ■ ■ ■ ■

reactive

Energy transmitted with – ■ ■ ■ ■ ■ ■ ■ ■

pulse outputs

Demand values: phase ■ ■ ■ ■ ■ ■ ■ ■ ■

currents

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Measurement P3U10/ P3U30 P3F30 P3L30 P3M30 P3M32 P3G30 P3G32 P3T32
20

Demand values: active, – ■ ■ ■ ■ ■ ■ ■ ■

reactive, apparent power
and power factor

Min and max demand ■ ■ ■ ■ ■ ■ ■ ■ ■

values: phase currents

Min and max demand ■ ■ ■ ■ ■ ■ ■ ■ ■

values: RMS phase
currents

Min and max demand – ■ ■ ■ ■ ■ ■ ■ ■

values: active, reactive,
apparent power and
power factor

Maximum demand values – ■ ■ ■ ■ ■ ■ ■ ■

over the last 31 days and
12 months: active,
reactive, apparent power

Minimum demand values – ■ ■ ■ ■ ■ ■ ■ ■

over the last 31 days and
12 months: active,
reactive power

Max and min values: ■ ■ ■ ■ ■ ■ ■ ■ ■

currents

Max and min values: – ■ ■ ■ ■ ■ ■ ■ ■

voltages

Max and min values: ■ ■ ■ ■ ■ ■ ■ ■ ■

frequency

Max andmin values: – ■ ■ ■ ■ ■ ■ ■ ■

active, reactive, apparent
power and power factor

Harmonic values of phase ■ ■ ■ ■ ■ ■13) ■ ■13) ■13)

current and THD

Harmonic values of – ■ ■ ■ ■ ■ ■ ■ ■
voltage and THD

Voltage sags and swells – ■ ■ ■ ■ ■ ■ ■ ■

13) Function available on both sets of CT inputs

Table 9 - Logs and records

Logs and Records P3U10/ P3U30 P3F30 P3L30 P3M30 P3M32 P3G30 P3G32 P3T32
20

Sequence of event record ■ ■ ■ ■ ■ ■ ■ ■ ■

Disturbance record ■ ■ ■ ■ ■ ■ ■ ■ ■

Tripping context record ■ ■ ■ ■ ■ ■ ■ ■ ■

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Table 10 - Monitoring functions

P3U10/
Monitoring functions P3U30 P3F30 P3L30 P3M30 P3M32 P3G30 P3G32 P3T32
20

Trip circuit supervision 1 1 1 1 1 1 1 1 1

(ANSI 74)

Circuit breaker monitoring 1 1 1 1 1 1 1 1 1

Relay monitoring ■ ■ ■ ■ ■ ■ ■ ■ ■

2.4 Access to device configuration

You can access the device configuration via:
• the Easergy Pro setting tool
• the device’s front panel

NOTE: There is a timeout mechanism for Telnet/Serial/Http connections.

When logging on via the front panel or web HMI, you are automatically logged
out after 15 minutes inactivity.

2.4.1 User accounts

By default, the Easergy P3 device has five user accounts.

Table 11 - User accounts

User account User name Default Use

password

User user 0 Used for reading parameter

values, measurements, and
events, for example

Operator operator 1 Used for controlling objects and

for changing the protection stages’
settings, for example

Configurator conf 2 Needed during the device

commissioning. For example, the
scaling of the voltage and current
transformers can be set only with
this user account.

2.4.2 Logging on via the front panel

NOTE: To log on via the front panel, you need a password that consists of
letters, digits, or other characters in the scope of ASCII 0x21~0x7E.

1. Press and on the front panel. The Enter password view opens.

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Figure 1 - Enter password view

2. Enter the password for the desired access level.

Select a digit value using , and if the password is longer than one digit,
move to the next digit position using .

NOTE: There are 16 digit positions in the Enter password view. Enter the
password starting from the first digit position.

For example, if the password is 2, you can enter 2***, **2*, ***2, or 0002
to log on.

3. Press to confirm the password.

Related topics
2.4.3 Password management

2.4.3 Password management

NOTICE
CYBERSECURITY HAZARD

To improve cybersecurity:

• Change all passwords from their default values when taking the protection
device into use.
• Change all passwords regularly.
• Ensure a minimum level of password complexity according to common
password guidelines.

Failure to follow these instructions can increase the risk of unauthorized

access.

You can change the password for the operator or configurator user accounts in
the General > Device info setting view in Easergy Pro.
The password can contain letters, digits or other characters in the scope of ASCII
0x21~0x7E. However, the new password cannot be any of the default passwords
(digits 0–4 or 9999).

Follow these guidelines to improve the password complexity and thus device
security:
• Use a password of minimum 8 characters.
• Use alphabetic (uppercase and lowercase) and numeric characters in addition
to symbols.
• Avoid character repetition, number or letter sequences and keyboard patterns.

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• Do not use any personal information, such as birthday, name, etc.

• Do not use the same password for different user accounts.
• Do not reuse old passwords.

Also, all users must be aware of the best practices concerning passwords
including:
• not sharing personal passwords
• not displaying passwords during password entry
• not transmitting passwords in email or by other means
• not saving the passwords on PCs or other devices
• no written passwords on any supports
• regularly reminding users about the best practices concerning passwords

Related topics
2.4.2 Logging on via the front panel

2.4.4 Password restoring

If you have lost or forgotten all passwords, contact Schneider Electric to restore
the default passwords.

2.5 Front panel

Easergy P3T32 has a 128 x 128 LCD matrix display.

Figure 2 - Easergy P3T32 front panel

A
A B D
D E F
F

F1 F2

I
A GJ
J GG
B B GC
B
C G
E J
D H
F

A. Power LED F. Service LED

B. CANCEL push-button G. Function push-buttons and LEDs showing their status
C. Navigation push-buttons H. Local port
D. LCD I. Object control buttons
E. INFO push-button J. User-configurable LEDs

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2.5.1 Push-buttons

Symbol Function

HOME/CANCEL push-button for returning to the previous menu. To

return to the first menu item in the main menu, press the button for at
least 3 seconds.

INFO push-button for viewing additional information, for entering the

password view and for adjusting the LCD contrast.

Programmable function push-button.14)

Programmable function push-button.14)

ENTER push-button for activating or confirming a function.

UP navigation push-button for moving up in the menu or increasing a

numerical value.

DOWN navigation push-button for moving down in the menu or

decreasing a numerical value.

LEFT navigation push-button for moving backwards in a parallel menu

or selecting a digit in a numerical value.

RIGHT navigation push-button for moving forwards in a parallel menu or

selecting a digit in a numerical value.

Circuit breaker close push-button

Circuit breaker trip push-button

14) The default names of the function buttons are Function button 1 and 2. You can change the names
of the buttons in the Control > Names for function buttons setting view.

2.5.2 LED indicators

The relay has 18 LEDs on the front panel:

• two LEDs for function buttons (F1 and F2)

• two LEDs represent the unit's general status (power and service)
• 14 user-configurable LEDs (A-N)

When the relay is powered, the power LED is green. During normal use, the
service LED is not active, it activates only when an error occurs or the relay is not
operating correctly. Should this happen, contact your local representative for
further guidance. The service LED and watchdog contact are assigned to work
together. Hardwire the status output into the substation's automation system for
alarm purposes.

The user-configurable LEDs may be red or green. You can configure them via
Easergy Pro.

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To customize the LED texts on the front panel for the user-configurable LEDs, the
text may be created using a template and then printed. The printed text may be
placed in the pockets beside the LEDs.

You can also customize the LED texts that are shown on the screen for active
LEDs via Easergy Pro.

Table 12 - LED indicators and their information

LED indicator LED color Meaning Measure /

Remarks

Power LED lit Green The auxiliary power Normal operation

has been switched state
on

Service LED lit Red Internal fault. The relay attempts

Operates in parallel to reboot. If the
with the self- service LED remains
supervision output lit, call for
maintenance.

A–H LED lit Green or red Application-related Configurable in the

status indicators. Matrix setting view

F1 or F2 LED lit Green Corresponding Depending on the

function key function
pressed / activated programmed to F1 /
F2

2.5.3 Configuring the LED names via Easergy Pro

1. Go to General > LED names.

2. To change a LED name, click the LED Description text and type a new
name. To save the new name, press Enter.

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Figure 3 - LED NAMES menu in Easergy Pro for LED configuration

2.5.4 Controlling the alarm screen

You can enable or disable the alarm screen either via the relay's local display or
using Easergy Pro:

• On the local display, go to Events > Alarms.

• In Easergy Pro, go to General > Local panel conf.

2.5.5 Accessing operating levels

1. On the front panel, press and .

2. Enter the password, and press .

2.5.6 Adjusting the LCD contrast

Prerequisite: You have entered the correct password.

1. Press , and adjust the contrast.

◦ To increase the contrast, press .

◦ To decrease the contrast, press .

2. To return to the main menu, press .

NOTE: By nature, the LCD display changes its contrast depending on the
ambient temperature. The display may become dark or unreadable at low
temperatures. However, this condition does not affect the proper operation of
the protection or other functions.

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2.5.7 Testing the LEDs and LCD screen

You can start the test sequence in any main menu window.

To start the LED and LCD test:

1. Press .

2. Press .

The relay tests the LCD screen and the functionality of all LEDs.

2.5.8 Controlling an object with selective control

Prerequisite: You have logged in with the correct password and enabled selective
control in the Objects setting view.

When selective control is enabled, the control operation needs confirmation

(select before operate).
• Press to close an object.

– Press again to confirm.

– Press to cancel.
• Press to trip an object.

– Press again to confirm.

– Press to cancel.

2.5.9 Controlling an object with direct control

Prerequisite: You have logged in with the correct password and enabled direct
control in the Objects setting view.

When direct control is enabled, the control operation is done without confirmation.
• Press to close an object.
• Press to trip an object.

2.5.10 Menus

This section gives an overview of the menus that you can access via the device's
front panel.

The main menu

Press the right arrow to access more measurements in the main menu.

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Table 13 - Main menu

Menu name Description

Active LEDs User-configurable texts for active LEDs

Measurements User-configurable measurements

Single line Single line or Single line mimic,

measurements and control view. This is a
default start view. To return to this view
from any location, press the HOME/
CANCELL button for at least 3 seconds.

Info Information about the relay: relay's name,

order code, date, time and firmware version

P Power: power factor and frequency values

calculated by the relay. Press the right
arrow to view more measurements.

E Energy: the amount of energy that has

passed through the protected line,
calculated by the relay from the currents
and voltages. Press the right arrow to view
more energy measurements.

I Current: phase currents and demand

values of phase currents. Press the right
arrow to view more current measurements.

V Line-to-line voltages. Press the right arrow

to view other voltage measurements.

Dema Minimum and maximum phase current and

power demand values

Vmax Minimum and maximum values of voltage

and frequency

Imax Minimum and maximum current values

Pmax Minimum and maximum power values

Month Monthly maximum current and power

values

FL Short-circuit locator applied to incomer or

feeder

Evnt Event log: event codes and time stamps

DR Disturbance recorder configuration settings

Runh Running hour counter

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Menu name Description

TIMR Timers: programmable timers that you can

use to preset functions

DI Digital input statuses and settings

DO Digital output statuses and settings

Arc Arc flash detection settings

Prot Protection: settings and statuses for various

protection functions

50/51-1–50/51-4 Protection stage settings and statuses. The

availability of the menus are depends on
the activated protection stages.

AR Auto-reclosure settings, statuses and

registers

OBJ Objects: settings related to object status

data and object control (open/closed)

Lgic Logic events and counters

CONF General device setup: CT and VT scalings,

frequency adaptation, units, device info,
date, time, clock, etc.

Bus Communication port settings

Slot Slot info: card ID (CID) that is the name of

the card used by the relay firmware

Diag Diagnosis: various diagnostic information

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2.5.10.1 Moving in the menus

Figure 4 - Moving in menus using the front panel

Main menu Submenus

ARC Arc detection settings

OK

I pick-up setting

OK OK

• To move in the main menu, press or .

• To move in the submenus, press or .
• While in the submenu, press or to jump to the root.
• To enter a submenu, press and use or for moving down or up
in the menu.
• To edit a parameter value, press and .
• Enter the password, and press .
• To go back to the previous menu, press .
• To go back to the first menu item in the main menu, press for at least three
seconds.
NOTE: To enter the parameter edit mode, enter the password. When the
value is in edit mode, its background is dark.

2.5.10.2 Local panel messages

Table 14 - Local panel messages

Value is not editable: The value can not be edited or password is
not given

Control disabled: Object control disabled due to wrong

operating level

Change causes autoboot: Notification that if the parameter is changed

the relay boots itself

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2.6 Easergy Pro setting and configuration tool

DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC
FLASH

Only qualified personnel should operate this equipment.

Such work should be performed only after reading this
entire set of instructions and checking the technical
characteristics of the device.

Failure to follow this instruction will result in death or

serious injury.

Easergy Pro is a software tool for configuring Easergy P3 relays. It has a

graphical interface where the relay settings and parameters are grouped under
seven tabs:

• General
• Measurements
• Inputs/outputs
• Protection
• Matrix
• Logs
• Communication

The contents of the tabs depend on the relay type and the selected application
mode.

Easergy Pro stores the relay configuration in a setting file. The configuration of
one physical relay is saved in one setting file. The configurations can be printed
out and saved for later use.

For more information, see the Easergy Pro user manual.

NOTE: Download the latest version of the software from se.com/ww/en/

product-range-download/64884-easergy-p3-protection-relays.

NOTICE
HAZARD OF EQUIPMENT DAMAGE

After writing new settings or configurations to a device, perform a test to verify

that the relay operates correctly with the new settings.

Failure to follow these instructions can result in unwanted shutdown of

the electrical installation.

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5 Control functions

5.1 Digital outputs

The digital outputs are also called controlling outputs, signaling outputs and self-
supervision outputs. Trip contacts can be controlled by using the relay output
matrix or logic functions. Also forced control is possible. To use forced control,
you must enable it in the Device/Test > Relays setting view.

Any internal signal can be connected to the digital outputs in the Matrix > Arc
matrix - output setting views.

The Output matrix and Relays setting views represent the state (de-energized /
energized) of the digital output's coil. For example, a bright green vertical line in
the Output matrix and a logical "1" in the Relays view represent the energized
state of the coil. The same principle applies for both NO and NC type digital
outputs. The actual position (open / closed) of the digital outputs' contacts in coil's
de-energized and energized state depends on the type (NO / NC) of the digital
outputs. De-energized state of the coil corresponds to the normal state of the
contacts. A digital output can be configured as latched or non-latched. 5.5
Releasing latches describes releasing latches procedure.

The difference between trip contacts and signal contacts is the DC breaking
capacity. The contacts are single pole single throw (SPST) normal open (NO)
type, except signal relay A1 which has a changeover contact single pole double
throw (SPDT).

In addition to this, the relay has so called heavy duty outputs available in the
power supply modules C and D. For more details, see Table 157.

Programming matrix

1. Connected (single bullet)

2. Connected and latched (single bullet rounded with another circle)

3. Not connected (line crossing is empty)

Trip contacts can be connected to protection stages or other similar purpose in

the Output matrix setting view.

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Figure 16 - Output matrix view

Figure 17 - Trip contacts assigned directly to outputs of logical operators

NOTE: Logic outputs are assigned automatically in the output matrix as well
when logic is built.

Trip contact status can be viewed and forced to operate in the Relays setting
view. Logical "0" means that the output is not energized and logical "1" states that
the output is set active.

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Figure 18 - Relays view

Enable NO / NC outputs in the Polarity setting view for the signals shown.

Figure 19 - Polarity view

Default numbering of DI / DO

Every option card and slot has default numbering. Below is an example of model
P3x30 CGGII-AAEAA-BA showing the default numbering of digital outputs.

You can see the default digital output numbering and change the numbering of
the following option cards in the Inputs/Outputs > Relay config setting view: slot
2, 3, 4, 5: G, I.

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Figure 20 - Default numbering of digital outputs for model P3x30-CGGII-AAEAA-

BA

C: T1, T9–12, A1, SF I: –

G: T13-16 I: –
G: T17-20

Power supply card outputs are not visible in the Relay config setting view.

Figure 21 - Relay config setting view

Table 28 - Parameters of digital outputs

Parameter Value Unit Description Note

T1 – Tx the available 0 Status of trip controlling output F22)

parameter list
1
depends on the
number and type of
the I/O cards.

A1 0 Status of alarm signalling output F

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Parameter Value Unit Description Note

WD 0 Status of the WD relay F

1 In Easergy Pro, it is called

"Service status output"

Force On Force flag for digital output Set23)

forcing for test purposes
Off

Names for output relays (editable with Easergy Pro only)

Description String of Names for DO on Easergy Pro Set

max. 32 screens. Default is
characte
"Trip relay n", n=1 – x or
rs
"Signal relay n", n=1
22) F = Editable when force flag is on
23) Set = An editable parameter (password needed).

5.2 Digital inputs

Digital inputs are available for control purposes. The number of available inputs
depends on the number and type of option cards.

The polarity normal open (NO) / normal closed (NC) and a delay can be
configured according to the application by using the front panel or Easergy Pro.

Digital inputs can be used in many operations. The status of the input can be
checked in the Output matrix and Digital inputs setting views. The digital inputs
make it possible to change group, block/enable/disable functions, to program
logics, indicate object status, etc.

The digital inputs require an external control voltage (ac or dc). The digital inputs
are activated after the activation voltage is exceeded. Deactivation follows when
the voltage drops below threshold limit. The activation voltage level of digital
inputs can be selected in the order code when such option cards are equipped.

Digital inputs can be connected, latched or unlatched to trip contacts or other

similar purpose in Output matrix setting view.

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Figure 22 - Output matrix view

Digital inputs can be assigned, latched or unlatched directly to inputs/outputs of

logical operators.

Figure 23 - Digital inputs assigned to outputs of logical operators

Digital inputs can be viewed, named and changed between NO/NC in the Digital
inputs and Names for digital inputs setting views.

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Figure 24 - Digital inputs view

If inputs are energized by using ac voltage, “mode” has to be selected as ac.

All essential information on digital inputs can be found in the same location in the
Digital inputs setting view. DI on/off events and alarm display (pop-up) can be
enabled and disabled in Digital inputs setting view. Individual operation counters
are located in the same view as well.

Label and description texts can be edited with Easergy Pro according to the
demand. Labels are the short parameter names used on the local panel and
descriptions are the longer names used by Easergy Pro.

The digital input activation thresholds are hardware-selectable.

Digital input delay determines the activation and de-activation delay for the input.
Figure 25shows how the digital input behaves when the delay is set to 1 second.

Figure 25 - Digital input’s behavior when delay is set to 1 second

1 s. 1 s.

1
VOLTAGE
0
1
DIGITAL INPUT
0

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Table 29 - Parameters of digital inputs

Parameter Value Unit Description Note

Mode dc, ac Used voltage of Set24)

digital inputs

Input DI1 – DIx Number of

digital input. The
available
parameter list
depends on the
number and
type of the I/O
cards.

Slot 2–6 Card slot

number where
option card is
installed.

State 0, 1 Status of digital

input 1 – digital
input x.

Polarity NO For normal open Set

contacts (NO).
NC
Active edge is 0
>1

For normal
closed contacts
(NC)

Active edge is 1
>0

Delay 0.00 – 60.00 s Definite delay Set

for both on and
off transitions

On event On Active edge Set

event enabled

Off Active edge

event disabled

Off event On Inactive edge Set

event enabled

Off Inactive edge

event disabled

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Parameter Value Unit Description Note

Alarm display no No pop-up Set

display

yes Alarm pop-up

display is
activated at
active DI edge

Counters 0 – 65535 Cumulative (Set)

active edge
counter

NAMES for DIGITAL INPUTS (editable with Easergy Pro only)

Label String of max. Short name for Set

10 characters DIs on the local
display

Default is "DI1 –
DIx". x is the
maximum
number of the
digital input.

Description String of max. Long name for Set

32 characters DIs. Default is
"Digital input 1 –
Digital input x".

x is the
maximum
number of the
digital input.
24) Set = An editable parameter (password needed).

Every option card and slot has default numbering. After making any changes to
the numbering, read the settings from the relay after the relay has rebooted.

Below is an example of model P3x30-CGGII-AAEAA-BAAAA showing default

numbering of DI.

You can see the default digital input numbering and change the numbering of the
following option cards in the Inputs/Outputs > Digital inputs setting view: slot 2,
3, 4, 5: G, I.

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Figure 26 - Default numbering of digital inputs for model P3x30-CGGII-AAEAA-

BA

C: -
G: DI1–6
G: DI7–12
I: DI13–22
I: DI23–32

Figure 27 - Digital inputs setting view

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5.3 Virtual inputs and outputs

There are virtual inputs and virtual outputs that can in many places be used like
their hardware equivalents except that they are located in the memory of the
relay. The virtual inputs act like normal digital inputs. The status of the virtual input
can be changed via the local display, communication bus and Easergy Pro. For
example setting groups can be changed using virtual inputs.

Virtual inputs can be used in many operations. The status of the input can be
checked in the Matrix > Output matrix and Control > Virtual inputs setting
views. The status is also visible on local mimic display, if so selected. Virtual
inputs can be selected to be operated with the function buttons F1 and F2, the
local mimic or simply by using the virtual input menu. Virtual inputs have similar
functions as digital inputs: they enable changing groups, block/enable/disable
functions, to program logics and other similar to digital inputs.

The activation and reset delay of the input is approximately 5 ms.

Table 30 - Virtual inputs and outputs

Number of inputs 20

Number of outputs 20

Activation time / Reset time < 5 ms

Figure 28 - Virtual inputs and outputs can be used for many purpose in the
Output matrix setting view.

Figure 29 - Virtual inputs and outputs can be assigned directly to inputs/outputs of

logical operators

Notice the difference between latched and non-latched connection.

Virtual inputs and outputs can be used for many purposes in the Output matrix
setting view.

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Virtual inputs and outputs can be assigned, latched or unlatched, directly to

inputs/outputs of logical operators.

Virtual inputs

The virtual inputs can be viewed, named and controlled in the Control > Virtual
inputs setting view.

Figure 30 - Virtual inputs view

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Figure 31 - Names for virtual inputs view

Table 31 - Parameters of virtual inputs

Parameter Value Unit Description Set25)

VI1-VI20 0 Status of virtual

input
1

Events On Event enabling Set

Off

Names for virtual inputs (editable with Easergy Pro only)

Label String of max. Short name for Set

10 characters VIs on the local
display

Default is "VIn",
n = 1–20

Description String of max. Long name for Set

32 characters VIs. Default is
"Virtual input n",
n = 1–20
25) Set = An editable parameter (password needed).

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Virtual outputs

In Easergy Pro, the Virtual outputs setting view is located under Control.

Figure 32 - Virtual outputs view

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Figure 33 - Names for virtual outputs view

Table 32 - Parameters of virtual outputs

Parameter Value Unit Description Set26)

0 Status of virtual output F

VO1-VO20
1

Events On Event enabling Set

Off

NAMES for VIRTUAL OUTPUTS (editable with Easergy Pro only)

Label String of Short name for VOs on the local Set

max. 10 display
characte
rs Default is "VOn", n=1-20

Description String of Long name for VOs. Default is Set

max. 32
characte "Virtual output n", n=1-20
rs
26) Set = An editable parameter (password needed). F = Editable when force flag is on.

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5.4 Matrix
The relay has several matrices that are used for configuring the relay:

• Output matrix used to link protection stage signals, digital inputs, virtual
inputs, function buttons, object control, logic output, relay's internal alarms,
GOOSE signals and release latch signals to outputs, disturbance recorder trig
input and virtual outputs
• Block matrix used to block protection stages
• LED matrix used to control LEDs on the front panel
• Object block matrix used to inhibit object control
• Auto-recloser matrix used to control auto-recloser
• Arc matrix used to control current and light signals to arc stages and arc
stages to the high-speed outputs

Figure 34 - Blocking matrix and output matrix

Protection stages
Directly
measured Block matrix Output matrix User’s logic
I values n
n START
TRIP I
V Calculate START N
n TRIP P
S, P, Q, U
START
cosφ, tanφ, n TRIP T
BLOCK
symmetric S
INPUT
components BLOCK
etc. INPUT
BLOCK
INPUT OUTPUTS

Virtual
inputs

Digital n
inputs
n Output relays Virtual
optional
DI delay and indicators outputs
n
and
inversion n

Output contacts

NOTE: Blocking matrix can not be used to block the arc flash detection
stages.

5.4.1 Output matrix

There are general-purpose LED indicators – "A", "B", "C" to ”N” – available for
customer-specific indications on the front panel. Their usage is define in a
separate LED matrix.

There are two LED indicators specified for keys F1 and F2. The triggering of the
disturbance recorder (DR) and virtual outputs are configurable in the output
matrix.

A digital output or indicator LED can be configured as latched or non-latched. A

non-latched relay follows the controlling signal. A latched relay remains activated
although the controlling signal releases.

There is a common "release all latches" signal to release all the latched relays.
This release signal resets all the latched digital outputs and indicators. The reset
signal can be given via a digital input, via front panel or remotely through

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communication. For instructions on how to release latches, see 5.5 Releasing

latches.

Trip and alarm relays together with virtual outputs can be assigned in the output
matrix. Also automatic triggering of disturbance recorder is done in the output
matrix.

Figure 35 - Output matrix example view

5.4.2 Blocking matrix

By means of a blocking matrix, the operation of any protection stage (except the
arc flash detection stages) can be blocked. The blocking signal can originate from
the digital inputs or it can be a start or trip signal from a protection stage or an
output signal from the user's programmable logic. In Figure 36, an active blocking
is indicated with a black dot (●) in the crossing point of a blocking signal and the
signal to be blocked.

All protection stages (except Arc stages) can be blocked in the block matrix

Figure 36 - Block matrix view

The Blocked status becomes visible only when the stage is about to activate.

Figure 37 - DI input blocking connection

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Figure 38 - Result for the I> stage when the DI is active and the stage exceeds its
current start value

NOTICE
RISK OF NUISANCE TRIPPING

• The blocking matrix is dynamically controlled by selecting and deselecting

protection stages.
• Activate the protection stages first, then store the settings in a relay. After
that, refresh the blocking matrix before configuring it.

Failure to follow these instructions can result in unwanted shutdown of

the electrical installation.

5.4.3 LED matrix

The LED matrix is used to link digital inputs, virtual inputs, function buttons,
protection stage outputs, object statuses, logic outputs, alarm signals and
GOOSE signals to various LEDs located on the front panel.

In the LED configuration setting view, each LED has three checkboxes with
which the behavior of the LED is configured.

Figure 39 - LED configuration

LEDs are assigned to control signals in the LED matrix setting view. It is not
possible to control LEDs directly with logics.

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Figure 40 - LED matrix

Normal setting

With no checkboxes selected, the assigned LED is active when the control signal
is active. After deactivation, the LED turns off. LED activation and deactivation
delay when controlled is approximately 10 ms.

Latch setting

A latched LED activates when the control signal activates but remains active
when the control signal deactivates. Latched LEDs are released using the
procedure described in 5.5 Releasing latches.

Blink setting

When the Blink setting is selected, the LED blinks when it is active.

Store setting

In the LED configuration setting view, you can configure the latched states of
LEDs to be stored after a restart. In Figure 39, storing has been configured for
LED A (green).

NOTE: To use the Store setting, Latch must also be selected.

Inputs for LEDs

Inputs for LEDs can be assigned in the LED matrix. All 14 LEDs can be assigned
as green or red. The connection can be normal, latched or blink-latched. In
addition to protection stages, there are lots of functions that can be assigned to
output LEDs. See Table 33.

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Table 33 - Inputs for LEDs A-N

Input LED mapping Latch Description Note

LED A–N Normal/ Latched/ Set

Different type of
Detection, Arc and BlinkLatch
green or red detection stages can
program-mable stages
be assigned to LEDs

Digital/Virtual inputs LED A–N Normal/ Latched/ All different type of Set
and function buttons BlinkLatch inputs can be assigned
green or red
to LEDs

Object open/close, LED A–N Normal/ Latched/ Information related to Set

object final trip and BlinkLatch objects and object
green or red
object failure control
information

Local control enabled LED A–N Normal/ Latched/ While remote/local Set
BlinkLatch state is selected as
green or red
local the “local control
enabled” is active

Logic output 1–20 LED A–N Normal/ Latched/ All logic outputs can be Set
BlinkLatch assigned to LEDs at
green or red
the LED matrix

Manual control LED A–N Normal/ Latched/ When the user has Set
indication BlinkLatch controlled the
green or red
objectives

COM 1–5 comm. LED A–N Normal/ Latched/ When the Set
BlinkLatch communication port 1 -
green or red
5 is active

Setting error, seldiag LED A–N Normal/ Latched/ Self diagnostic signal Set
alarm, pwd open and BlinkLatch
green or red
setting change

GOOSE NI1–64 LED A–N Normal/ Latched/ IEC 61850 goose Set
BlinkLatch communication signal
green or red

GOOSEERR1–16 LED A–N Normal/ Latched/ IEC 61850 goose Set

BlinkLatch communication signal
green or red

5.4.4 Object block matrix

The object block matrix is used to link digital inputs, virtual inputs, function
buttons, protection stage outputs, logic outputs, alarm signals and GOOSE
signals to inhibit the control of objects, that is, circuit breakers, isolators and
grounding switches.

Typical signals to inhibit controlling of the objects like circuit breaker are:

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• protection stage activation

• statuses of other objects
• interlocking made with logic
• GOOSE signals

These and other signals are linked to objects in the object block matrix.

There are also event-type signals that do not block objects as they are on only for
a short time, for example "Object1" open and "Object1 close" signals.

5.5 Releasing latches

You can release latches using:
• Easergy Pro
• buttons and local panel display
• F1 or F2 buttons

5.5.1 Releasing latches using Easergy Pro

1. Connect Easergy Pro to the device.

2. From the Easergy Pro toolbar, select Device > Release all latches.

Figure 41 - Releasing all latches

Alternatively, go to Control > Release latches, and click the Release button.

Figure 42 - Release latches

5.5.2 Releasing latches using buttons and local panel display

Prerequisite: You have entered the correct password

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1. Press .

2. Press .

3. Select Release, and press .

All latches are released.

5.5.3 Releasing latches using F1 or F2 buttons

You can use the function buttons F1 or F2 to release all latches after configuring
this function in Easergy Pro. You can make the configuration either under Control
> Release Latches or under Control > Function buttons.

• To configure F1 to release latches under Control > Release latches:

a. In Easergy Pro, go to Control > Release latches.

b. Under Release latches, select F1 from the DI to release latches drop-

down menu.

c. Set 1 s delay for Latch release signal pulse.

Figure 43 - Release latches view

After this, pressing the F1 button on the relay’s front panel releases all
latches.
• To configure F1 to release latches under Control >Function buttons:

a. Under Function buttons, for F1, select PrgFncs from the Selected
control drop down menu.

b. Set 1 s delay for F1 pulse length.

c. Under Programmable functions for F1, select “On” from the Release all
latches drop-down menu.

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Figure 44 - Function buttons view

After this, pressing the F1 button on the relay's front panel releases all
latches.

NOTE: The latch release signal can be activated only if the latched
output is active.

5.6 Controllable objects

The relay allows controlling eight objects, that is, circuit breakers, disconnectors
and grounding switches by the "select before operate" or "direct control" principle.

Controlling is possible in the following ways:

• through the object control buttons

• through front panel and display using single-line diagram
• through the function keys
• through digital input
• through remote communication
• through Easergy Pro setting tool
• through Smart APP

The connection of an object to specific controlling outputs is done via an output

matrix (object 1–8 open output, object 1–8 close output). There is also an output
signal “Object failed” that is activated if the control of an object is not completed.

Object states

Each object has the following states:

Setting Value Description

Object state Undefined (00) Actual state of the object

Open

Close

Undefined (11)

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Basic settings for objects

Each object has the following settings:

Setting Value Description

DI for ‘obj open’ None, any digital input, Open information

virtual input or virtual output
DI for ‘obj close’ Close information

DI for ‘obj ready’ Ready information

Max ctrl pulse length 0.02–600 s Pulse length for open and
close commands. Control
pulse stops once object
changes its state

Completion timeout 0.02–600 s Timeout of ready indication

Object control Open/Close Direct object control

If changing the states takes longer than the time defined by the “Max ctrl pulse
length” setting, the object is inoperative and the “Object failure” matrix signal is
set. Also, an undefined event is generated. “Completion timeout” is only used for
the ready indication. If “DI for ‘obj ready’” is not set, the completion timeout has no
meaning.

Output signals of objects

Each object has two control signals in matrix:

Output signal Description

Object x Open Open control signal for the object

Object x Close Close control signal for the object

These signals send control pulse when an object is controlled by digital input,
remote bus, auto-reclose etc.

5.6.1 Object control with digital inputs

Objects can be controlled with digital inputs, virtual inputs or virtual outputs. There
are four settings for each object:

Setting Active

DI for remote open / close control In remote state

DI for local open / close control In local state

If the relay is in local control state, the remote control inputs are ignored and vice
versa. An object is controlled when a rising edge is detected from the selected
input. The length of digital input pulse should be at least 60 ms.

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5.6.2 Local or remote selection

In local mode, digital outputs can be controlled via the front panel but they cannot
be controlled via a remote serial communication interface.

In remote mode, digital outputs cannot be controlled via a front panel but they can
be controlled via a remote serial communication interface.

The local or remote mode can be selected by using the front panel or via one
selectable digital input. The digital input is normally used to change a whole
station to local or remote mode. You can select the L/R digital input in the Control
> Objects setting view in Easergy Pro.

Table 34 - Local or remote selection

Action Control through Easergy Pro Control through

or SmartApp communication protocol

Local/Remote Local Remote Local Remote

switch status

CB control Yes No No Yes

Setting or Yes Yes Yes Yes

configuration
changes

Communication Yes Yes Yes Yes

configuration

Virtual inputs 27) Yes No No Yes

27) Virtual inputs have a general parameter “Check L/R selection” for disabling the L/R check.

5.6.3 Object control with Close and Trip buttons

The relay also has dedicated control buttons for objects. Close stands for object
closing and Trip controls object open command internally. Control buttons are
configured in the Control > Objects setting view.

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Table 35 - Parameters of function keys

Parameter Value Unit Description Set

Object for Obj1–Obj8 Set

control buttons
Button
closes selected
object if
password is
enabled

Button
opens selected
object if
password is
enabled

Mode for control Selective Control

butons operation needs
Direct
confirmation
(select-execute)

Control
operation is
done without
confirmation

5.6.4 Object control with F1 and F2

Objects can be controlled with the function buttons F1 and F2.

By default, the F1 and F2 buttons are configured to control F1 and F2 variables

that can further be assigned to control objects.

Table 36 - Parameters of F1 and F2

Parameter Value State Pulse Description

length 28)

F1 F1, V1-V20, 0.1 0600 s

controls F1,
ObjCtrl
V1-V20 or
ObjCtrl
parameters.

F2 F2, V1-V20, 0.1 0-600 s

controls F2,
ObjCtrl
V1-V20 and
ObjCtrl
parameters.
28) Pulse length applies to values F1 and F2 only

You can configure the button funtions in the Control > Function buttons setting
view in Easergy Pro.

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Figure 45 - Function buttons view

If ObjCtrl has been selected under Selected control, the selected object is
shown under Selected object. Otherwise, this column is empty.
When selecting ObjCtrl, link the function button to the appropriate object in the
Control > Objects setting view.

Figure 46 - Ctrl object 2 view

5.7 Logic functions

The relay supports customer-defined programmable logic for boolean signals.
User-configurable logic can be used to create something that is not provided by
the relay as a default. You can see and modify the logic in the Control > Logic
setting view in the Easergy Pro setting tool.

Table 37 - Available logic functions and their memory use

Logic functions No. of gates Max. no. of input Max. no. of logic
reserved gates outputs

AND 1
32
OR 1
(An input gate can 20
XOR 1 include any number
of inputs.)
AND+OR 2

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Logic functions No. of gates Max. no. of input Max. no. of logic
reserved gates outputs

CT (Count+Reset) 2

INVAND 2

INVOR 2

OR+AND 2

RS (Reset+Set) 2

RS_D (Set D+Load 4

+Reset)

The consumed memory is dynamically shown on the configuration view in

percentage. The first value indicates the memory consumption of inputs, the
second value the memory consumption of gates and the third value the memory
consumption of outputs.

The logic is operational as long the memory consumption of the inputs, gates or
outputs remains individually below or equal to 100%.

Figure 47 - Logic and memory consumption

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Truth tables

Table 38 - Truth table

Gate Symbol Truth table

AND In Out
A Y
&
A Y

0 0

1 1

A Y In Out
&
A Y

0 1

1 0

A Y In Out
&
A B Y
B
0 1 0

1 0 0

1 1 1

0 0 0

A Y In Out

& A B Y
B
0 1 1

1 0 1

1 1 0

0 0 1

AND+OR A In Out
& Y
>1 A B Y
B
0 0 0

1 1 1

1 0 1

0 1 1

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Gate Symbol Truth table

CT (Count+Reset) A In Out

Count
Y
CT A B Y Y

Reset
B
Cou Rese Setti New
nt t ng

1 3 0

1 3 0

1 3 1

1 3 0

INVAND In Out
A Y
¬& A B Y

B 0 0 0

1 0 1

1 1 0

0 1 0

INVOR A Y In Out

¬>1 A B Y

B 0 0 1

1 1 1

1 0 1

0 1 0

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Gate Symbol Truth table

OR A Y In Out

>1 A B Y
B
0 0 0

1 1 1

1 0 1

0 1 1

A Y In Out
>1
A B Y
B
0 0 1

1 1 0

1 0 0

0 1 0

A In Out
Y
B >1 A B C Y
C
0 0 0 1

1 1 0 1

1 0 0 1

0 1 0 1

1 1 1 1

A In Out
Y
B >1 A B C Y
C
0 0 0 1

1 0 0 0

1 1 0 0

0 1 0 0

1 1 1 0

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Gate Symbol Truth table

OR+AND A In Out
&
Y
>1 A B Y
B
0 0 0

1 1 1

1 0 0

0 1 0

RS (Reset+Set) A In Out

Set
Y
RS A B Y

Reset
B Set Reset Y

1 0 1

0 0 129)

0 0 030)

X 1 031)
29) Output = 1 (latched), if
previous state was 1, 0, 1.
30) Output = 0, if previous state

was X, 1, 0.
31) Output = 0, if RESET = 1

regardless of state of SET.

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Gate Symbol Truth table

RS_D (Set+D+Load+Reset) A B C D Y
A
Set D Loa Re Stat

Reset Load D Set

B R
Y d set e
C S
D D 0 0 0 0 032)

1 X X 0 1

1 X X 1 0

0 1 0 0 0

0 1 1 0 1

0 1 1 1 033)
32) Initial
state
33) Thestate remains 1 until
Reset is set active

X = Any state

If Set or D + Load are high,

the state returns to high if
Reset returns to low.

XOR In Out
A
Y
B =1 A B C Y
C
0 0 0 0

0 0 1 1

0 1 0 1

0 1 1 0

1 0 0 1

1 0 1 0

1 1 0 0

1 1 1 1

29) Output = 1 (latched), if previous state was 1, 0, 1.

30) Output = 0, if previous state was X, 1, 0.
31) Output = 0, if RESET = 1 regardless of state of SET.
32) Initial state
33) The state remains 1 until Reset is set active

Logic element properties

After you have selected the required logic gate in Easergy Pro, you can change
the function of the gate in the Element properties window by clicking the gate.

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Figure 48 - Logic element properties

Table 39 - Settings available for the logical gates depending on the selected
element

Property Description

Element properties

Type Change the logical function of the gate

Inverted Inverts the output state of the logical gate

ON delay Time delay to activate the output after

logical conditions are met

OFF delay Time delay for how long the gate remain
active even the logical condition is reset

Count Setting for counter (CT gate only)

Reverse Use to reverse AND and OR gates (AND

+OR gate only)

Inputs

Normal - / + Use to increase or decrease number of

inputs

Inverting - / + Use to increase or decrease number of

inverted inputs. This setting is visible for
INVAND and INVOR gates only

Count Use to increase or decrease number of

count inputs (CT gate only)

Reset Use to increase or decrease number of

count inputs (CT gate only)

AND Use to increase or decrease number of

inputs for AND gates (AND+OR gate only)

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Property Description

OR Use to increase or decrease number of

inputs for OR gates (AND+OR gate only)

Set Use to increase or decrease number of Set

inputs (RS_D gate only)

D Use to increase or decrease number of

Data inputs (RS_D gate only)

Load Use to increase or decrease number of

Load inputs (RS_D gate only)

Reset Use to increase or decrease number of

Reset inputs (RS_D gate only)

5.8 Local panel

Easergy P3T32 has one LCD matrix display.

All the main menus are located on the left side of the display. To get to a
submenu, move up and down the main menus.

Figure 49 - Local panel's main menu

5.8.1 Mimic view

The mimic view is set as the local panel's main view as default. You can modify
the mimic according to the application or disable it, if it is not needed, via the
Easergy Pro setting tool.

You can modify the mimic in the General > Mimic setting view in Easergy Pro
and disable the mimic view in the General > Local panel conf setting view.

NOTE: The mimic itself or the local mimic settings cannot be modified via the
local panel.

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Figure 50 - Mimic view

C A B F I G H F J

D
E
I

A. To clear an object or drawing, first point an F. The remote/local selection defines whether
empty square (A) with the mouse. Then point the certain actions are granted or not. In remote
object item with the mouse. The color of the object state, it is not possible to locally enable or
item turns red. To clear the whole mimic, click on disable auto-reclosing or to control objects. The
the empty area. remote/local state can be changed in Control >
Objects.
B. Text tool G. Creates auto-reclosing on/off selection to
mimic.
C. To move an existing drawing or object, point it H. Creates virtual input activation on the local
with the mouse. The color turns green. Hold down mimic view.
the left mouse button and move the object.
D. Different type of configurable objects. The I. Describes the relay's location. Text comes
object's number corresponds to the number in from the relay info menu.
Control > Objects.
E. Some predefined drawings. J. Up to six configurable measurements.

Table 40 - Mimic functionality

Parameter Value Unit Description Set

Sublocation Text field Up to 9 Set

characters.
Fixed location.

Object 1–8 1–8 Double-click on Set

top of the object
to change the
control number
between 1 and
8. Number 1
corresponds to
object 1 in
General >
Objects.

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Parameter Value Unit Description Set

Remote/Local L Local / Remote Set

mode control. R
R
stands for
remote. Remote
local state can
be changed in
General >
Objects as well.
Position can be
changed.

Auto reclosing 0 Possible to Set

enable/disable
1
auto-reclosure
localy in local
mode (L) or
remotely in
remote mode
(R). Position
can be
changed.

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Parameter Value Unit Description Set

Measurement IA–IC Up to 6 freely Set

display 1–6 IN selectable
measurements.
VAB, VBC,
VCA, VA, VB,
VC, VN
f, P, Q, S,
P.F.
CosPhi
E+, Eq+, E-,
Eq-
ARStart,
ARFaill,
ARShot1–5
IFLT
Starts, Trips
IN Calc
IA–ICda, IL
Pda, Qda,
Sda
T
fSYNC,
VSYNC
IA-2–IC–2
dIL1–dIL3
dIA–IC
VAI1–VAI5
ExtAI1–634)

Virtual input 1– 0 Change the Set

12 status of virtual
1
inputs while the
password is
enabled.
Position can be
changed.
34) Requires serial communication interface and External IO protocol activated.

Set = Settable.

NOTE: The measurement view's data selection depends on the voltage

measurement mode selected in the General > Scaling setting view.

5.8.2 Local panel configuration

You can modify the local panel configuration in the General > Local panel conf
setting view in Easergy Pro.

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Figure 51 - Local panel configuration view

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Table 41 - Local panel configuration parameters

Parameter Value Unit Description Set35)

Display 1–5 ILA-C 20 (5 x 4) freely Set37)

configurable
IN
measurement
VAB, VBC, VCA, values can be
VA, VB, VC, VN selected

f, P, Q, S, P.F.

CosPhi

E+, Eq+, E-, Eq-

ARStart,
ARFaill,
ARShot1–5

IFLT

Starts, Trips

IN Calc

Phase
currents
IA–Cda
IA–C max
IA–C min
IA–CdaMax
Pda, Qda,
Sda
T
fSYNC,
VSYNC

IA-2–IC-2

dIA–C

VAI1–5

ExtAI1–636)

SetGrp

Display contrast 50–210 Contrast can be Set

changed in the
relay menu as
well.

Display DI1–44, Arc1–3, Activates the Set37)

backlight control ArcF, BI, VI1–4, backlight of the
LED1–14, VO1– display.
6

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Parameter Value Unit Description Set35)

Panel reset Value range: min Configurable Set

timeout 0.0–2000.0 delay for the
front panel to
Default value:
return to the
15.0
default screen
when the front
panel is not
used.

When this value

is zero (0.0),
this timeout
never occurs.

Default screen Value range: Default screen Set

Mimic, Meas for the front
disp1, Meas panel.
disp2, Meas
If the selected
disp3, Meas
screen would
disp4, Meas
result in a blank
disp5
screen, the title
Default value: screen is used
Mimic as the default
screen.

Backlight off 0.0–2000.0 min Configurable Set

timeout delay for
backlight to
turns off when
the relay is not
used. Default
value is 60
minutes. When
value is zero
(0.0) backlight
stays on all the
time.

Enable alarm Selected Pop-up text box Set

screen for events. pop-
Unselected
up events can
be checked
individually by
pressing enter,
but holding the
button for 2
seconds checks
all the events at
once.

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Parameter Value Unit Description Set35)

AR info for Selected Auto reclosure Set

mimic display status visible on
Unselected
top of the local
mimic view.

Sync I info for Selected Synchro-check Set

mimic display status visible on
Unselected
top of the local
mimic view.
Operates
together with
auto-reclosure.

Auto LED Selected Enables Set

release automatix LED
Unselected
release
functionality.

Auto LED 0.1–600 s Default 1.5 s. Set

release enable When new
time LEDs are
latched, the
previous active
latches are
released
automatically if
the set time has
passed.

Fault value PU, Pri Fault values per Set

scaling unit or primary
scsaled.

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Parameter Value Unit Description Set35)

Local MIMIC Selected Enable or Set

disable the local
Unselected
mimic (enabled
as default).

When selected,
the mimic is the
local panel's
default main
view. When
unselected, the
measurement
view is the
default main
view.

Event buffer 50–2000 Event buffer Set38)

size size. Default
setting is 200
events.
35) Set = Settable
36) Requires serial communication interface and External IO protocol activated.
37) Inputs vary according to the relay type.
38) The existing events are lost if the event buffer size is changed.

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6 Protection functions
Each protection stage can independently be enabled or disabled according to the
requirements of the intended application.

NOTE: When protection stages are enabled or disabled, the disturbance

recordings are deleted from the relay's memory. Therefore, before activating
or deactivating stages, store the recordings in your PC.

6.1 Current transformer requirements for overcurrent elements

The current transformer (CT) must be sized according to the rules described here
for definite time (DT) or inverse definite minimum time (IDMT) to avoid saturation
during steady-state short-circuit currents where accuracy is required.

The nominal CT primary and secondary must be selected according to the

maximum short-circuit secondary current to meet the thermal withstand specified
in Table 157.

The condition to be fulfilled by the CT saturation current (Isat) depends on the type
of overcurrent protection operate time.

Table 42 - Condition to be fulfilled by CT saturation current

Time delay Condition to be fulfilled

DT Isat > 1.5 x set point (Is)

IDMT Isat > 1.5 x the curve value which is the smallest of these two values:
• Isc max., maximum installation short-circuit current
• 20 x Is (IDMT curve dynamic range)

Figure 52 - Overcurrent characteristics

A B
t t

I I
Is Isat Is Isat

C D

A. DT C. Minimum (Isc max., 20 Is)

B. IDMT D. 1.5 minimum (Isc max., 20 Is)

The method for calculating the saturation current depends on the CT accuracy
class.

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6.1.1 CT requirements when settings are unknown

If no other information about the settings is available, these characteristics are

suitable for most situations.

Class P accuracy class

Table 43 - CT requirements

Rated Rated burden Accuracy CT Wiring

secondary (VAct) class and secondary resistance
current (Ins) accuracy resistance (Rw)
limit factor (Rct)

1A 2.5 VA 5P20 <3Ω < 0.075 Ω

5A 7.5 VA 5P20 < 0.2 Ω < 0.075 Ω

Class PX accuracy class

Vk / (Rct + Rw) > 30 x Ins

For 1 A: Vk > 30 x (Rct + Rw); for example: 30 x 3.9 = 117 V

For 5 A: Vk > 150 x (Rct + Rw); for example: 150 x 0.53 = 79.5 V

6.1.2 Principle for calculating the saturation current in class P

A class P CT is characterized by:

• Inp: rated primary current (in A)
• Ins: rated secondary current (in A)
• accuracy class, expressed by a percentage, 5P or 10P, followed by the
accuracy limit factor (ALF), whose usual values are 5, 10, 15, 20, 30
• VAct: rated burden, whose usual values are 2.5/5/7.5/10/15/30 VA
• Rct: maximum resistance of the secondary winding (in Ω)

The installation is characterized by the load resistance Rw at the CT secondary

(wiring + protection device). If the CT load complies with the rated burden, that is,
Rw x Ins2 <= VAct, the saturation current is higher than ALF x Inp.

If the resistance Rct is known, it is possible to calculate the actual CT ALF which
takes account of the actual CT load. The saturation current equals the actual ALF
x Inp.

Equation 3

Rct × Ins2 + VAct

Actual ALF = ALF ×
(Rct + Rw) × Ins2

6.1.3 Examples of calculating the saturation current in class P

The saturation current for a CT is calculated with:

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• transformation ratio: 100 A/5 A

• rated burden: 2.5 VA
• accuracy class and accuracy-limit factor: 5P20
• resistance of the secondary winding: 0.1 Ω

To have an ALF of at least 20, that is, a saturation current of 20 x Inp = 2 kA, the
load resistance Rw of the CT must be less than Equation 4.

Equation 4

VAct 2.5
Rw, max = 2 = = 0.1Ω
Ins 52

This represents 12 m (39 ft) of wire with cross-section 2.5 mm² (AWG 14) for a
resistance per unit length of approximately 8 Ω/km (2.4 mΩ/ft). For an installation
with 50 m (164 ft) of wiring with section 2.5 mm² (AWG 14), Rw = 0.4 Ω.

As a result, the actual ALF is as presented in Equation 5.

Equation 5

Rct × Ins2 + VAct 0.1 × 25 + 2.5

Actual ALF = ALF × = 20× =8
(Rct + Rw) × Ins2 (0.1 + 0.4) × 25

Therefore, the saturation current Isat = 8 x Inp = 800 A.

NOTE: The impedance of an Easergy P3 protection device's current inputs

(0.004 Ω) is often negligible compared to the wiring resistance.

6.1.4 Principle for calculating the saturation current in class PX

A class PX CT is characterized by:

• Inp: rated primary current (in A)
• Ins: rated secondary current (in A)
• Vk: rated knee-point voltage (in V)
• Rct: maximum resistance of the secondary winding (in Ω)

The saturation current is calculated by the load resistance Rw at the CT

secondary (wiring + protection device) as shown in Equation 6.

Equation 6

Vk Inp
Isat = ×
Rct + Rw Ins

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6.1.5 Examples of calculating the saturation current in class PX

Table 44 - Examples of calculating the saturation current in class PX

CT Vk Rct Rw Saturation
Transformati current
on ratio

100 A/1 A 90 V 3.5 Ω 0.4 Ω Isat = 90 / (3,5 +

0,4) / 1 x Inp =
23,08 x Inp

100 A/5 A 60 V 0.13 Ω 0.4 Ω Isat = 60 / (0,13

+ 0,4) / 5 x Inp =
22,6 x Inp

6.1.6 CT requirements for REF protection

Two REF schemes are possible: the Low impedance REF and the High
impedance REF.

The Low impedance REF protection should be used with power networks X/R
only up to 15.

The formula for the CT requirements is

Vk > K * ISEC * (RCT + RB), where

ISEC = 1A or 5A, secondary ratio of the CT

‘K’ depends on X/R and the maximum through-fault current (three-phase fault
current) as defined in Table 45.

Table 45 - K factor

K value Fault current (xIn)

<=7 <=10 <=15

X/R <= 10 45 60 70

X/R <= 15 55 70 80

X/R > 15 Not applicable; use the High Z REF.

For power system with an X/R ratio above 15, or when the above CT
requirements cannot be met, the high impedance REF protection shall be used
instead.

The CT requirements for high impedance REF are given in the Application Note
"P3APS17016EN_(HiZ-REF_87N)".

NOTE: The high impedance REF must use a different winding of the primary
CT than the Transformer Differential.

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6.2 Current transformer requirements for generator and

transformer block differential protection
NOTE: These current transformer (CT) requirements are applicable from
firmware version FW30.204 onward.

The CT requirements are based on the following settings:

Table 46 - CT settings

Parameter Value

dI> pickup (Ibias < 0.5 Ign) 20% of In

Slope1 50%

Ibias for start of slope 2 2 x In

Slope2 150%

dI> 2nd harmonics block limit 10%

For maximum sub-synchronous through fault up to 7 In

P3G CT requirements from firmware 30.204 for generator differential protection

apply.

For maximum sub-synchronous through fault above 7 In

Class PX and class P CTs are recommended.

For maximum sub-synchronous through fault above 7 In and below 9 In, K = 25.

For maximum sub-synchronous through fault above 9 In, K = 30.

CT requirements for class PX

The minimum knee point voltage is Vk = K x Isr x (RCT + 2RL + Rr).

Vk = Minimum current transformer knee-point voltage

Isr = Secondary rated current (1A or 5A)

RCT = Resistance of current transformer secondary winding (Ω)

RL = Resistance of a single lead from relay to current transformer (Ω)

Rr = Resistance of all protective relays sharing the current transformer (Ω)

CT requirements for class P CT (5P10 for example)

The minimum rated burden is SVA > ((K / Kalf) x (RCT + Rba) – RCT) x Isr2

where kalf is the CT accuracy limit factor (i.e. 20 for 5P20, i.e. 10 for 5P10)

Rba = Actual burden = 2RL + Rr (Ω)

NOTE: The sub-synchronous value is ip.

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Figure 53 - Fault current

B
C
E F
G D

H IEC 1263/2000

A. Current F. Ip
B. Top envelope G. A
C. d.c. component Id.c. of the short-circuit current H. Bottom envelope
D. 2√2 I’k I. Time
E. 2√2 Ik

6.3 Current transformer requirements for transformer differential

protection
This topic describes the current transformer requirements for transformer
differential protection applicable for star-star and star-delta transformers.

NOTE: These current transformer (CT) requirements are applicable from

firmware version FW30.204 onward.

For accuracy, class PX or class 5P CTs are recommended but TPY or 5PR can
also be used.

The CT requirements are based on the following settings based on the rated
current of the transformer “In”:

Table 47 - CT settings

Parameter Value

dI> pickup (Ibias < 0.5 Ign) 20% of In

Slope1 50%

Ibias for start of slope 2 2 x In

Slope2 150%

dI> 2nd harmonics block limit 10%

The maximum through fault measured by the protection device must be limited to
15 In. Thus, choose the CT ratio carefully to meet this requirement. With a
through fault flowing from both sides, choose the highest one.

Determination of K for star-star transformers

For power network X/R up to 10 and for all the above-listed CT classes, K = 30.

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For power network X/R from 11 to 60:

• For TPX and class P CTs, K = 55
• For TPY and class PR CTs:
◦ For through faults up to 7 In, K = 30
◦ For through faults from 7 In to 15 In, K = 40

Table 48 - Determination of K for star-star transformers

Through fault current (up to)

7 15

X/R up to 10 TPX - 5P 30

TPY - 5PR

X/R up to 60 TPX - 5P 55

TPY - 5PR 30 40

Determination of K for star-delta transformers

For power network X/R up to 10 and for all above CT classes:

• For through fault up to 7 In, K = 30

• For through fault from 7 In to 15 In, K = 33

For power network X/R from 11 to 60,

• For TPX and class P CTs, K = 55

◦ For through fault up to 5 In, K = 55
◦ For through fault from 5 In to 15 In, K = 70
• For TPY and class PR CTs:
◦ For through fault up to 7 In, K = 30
◦ For through fault from 7 In to 15 In, K = 40

Table 49 - Determination of K for star-delta transformers

Through fault current (up to)

5 7 15

X/R up to 10 TPX - 5P 30 33

TPY - 5PR

X/R up to 60 TPX - 5P 55 70

TPY - 5PR 30 40

CT requirements for class PX and PY

K = 20

The minimum knee-point voltage is Vk = K x Isr x (RCT + 2RL + Rr).

Vk = Minimum current transformer knee-point voltage

Isr = Secondary rated current (1A or 5A)

RCT = Resistance of current transformer secondary winding (Ω)

RL = Resistance of a single lead from relay to current transformer (Ω)

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Rr = Resistance of all protective relays sharing the current transformer (Ω)

CT requirements for class P or PR CT ( for example 5P10)

K = 20

The minimum rated burden is SVA > ((K / Kalf) x (RCT + Rba) – RCT) x Isr2

where Kalf is the CT accuracy limit factor (20 for 5P20, 10 for 5P10)

Rba = Actual burden = 2 RL + Rr (Ω)

6.4 Maximum number of protection stages in one application

The relay limits the maximum number of enabled protection stages to about 30.
The exact number depends on the central processing unit's load consumption and
available memory as well as the type of the stages.

The individual protection stage and total load status can be found in the
Protection > Protection stage status setting view in the Easergy Pro setting
tool.

6.5 General features of protection stages

Setting groups

Setting groups are controlled by using digital inputs, function keys or virtual
inputs, via the front panel or custom logic. When none of the assigned inputs are
active, the setting group is defined by the parameter ‘SetGrp no control state’.
When controlled input activates, the corresponding setting group is activated as
well. If the control signal of the setting group is lost, the setting “Keep last” forces
the last active group into use. If multiple inputs are active at the same time, the
active setting group is defined by ‘SetGrp priority’. By using virtual I/O, the active
setting group can be controlled using the local panel display, any communication
protocol or the built-in programmable logic functions. All protection stages have
four setting groups.

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Figure 54 - Setting groups view

Example

Any digital input can be used to control setting groups but in this example, DI1,
DI2, DI3 and DI4 are chosen to control setting groups 1 to 4. This setting is done
with the parameter “Set group x DI control” where x refers to the desired setting
group.

Figure 55 - DI1, DI2, DI3, DI4 configured to control Groups 1 to 4 respectively

Use the 'SetGrp common change' parameter to force all protection stages to
group 1, 2, 3 or 4. The control becomes active if there is no local control in the
protection stage. You can activate this parameter using Easergy Pro.

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“SetGrp priority” is used to give a condition to a situation where two or more

digital inputs, controlling setting groups, are active at the same time. SetGrp
priority could have values “1 to 4” or “4 to 1”.

Figure 56 - SetGrp priority setting in the Valid Protection stages view

Assuming that DI2 and DI3 are active at the same time and SetGrp priority is set
to “1 to 4”, setting group 2 becomes active. If SetGrp priority is reversed, that is,
set to “4 to 1”, the setting group 3 becomes active.

Protection stage statuses

The status of a protection stage can be one of the followings:

• Ok = ‘-‘

The stage is idle and is measuring the analog quantity for the protection. No
power system fault detected.
• Blocked

The stage is detecting a fault but blocked for some reason.

• Start

The stage is counting the operation delay.

• Trip

The stage has tripped and the fault is still on.

The blocking reason may be an active signal via the block matrix from other
stages, the programmable logic or any digital input. Some stages also have built-
in blocking logic. For more details about the block matrix, see 5.4.2 Blocking
matrix.

Protection stage counters

Each protection stage has start and trip counters that are incremented when the
stage starts or trips. The start and trip counters are reset on relay reboot.

Forcing start or trip condition for testing purposes

There is a "Forcing flag" parameter which, when activated, allows forcing the
status of any protection stage to be "start" or "trip" for half a second. By using this
forcing feature, current or voltage injection is not necessary to check the output
matrix configuration, to check the wiring from the digital outputs to the circuit
breaker and also to check that communication protocols are correctly transferring
event information to a SCADA system.

After testing, the forcing flag is automatically reset five minutes after the last local
panel push button activity.

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The force flag also enables forcing the digital outputs and the optional mA
outputs.

The force flag can be found in the Device/Test > Relays setting view.

Figure 57 - Force flag

Start and trip signals

Every protection stage has two internal binary output signals: start and trip. The
start signal is issued when a fault has been detected. The trip signal is issued
after the configured operation delay unless the fault disappears before the end of
the delay time.

The hysteresis, as indicated in the protection stage's characteristics data, means

that the signal is regarded as a fault until the signal drops below the start setting
determined by the hysteresis value.

Figure 58 - Behavior of a greater than comparator (for example, the hysteresis

(dead band) in overvoltage stages)
Hysteresis_GT
hysteresis

Start level

> Start

Output matrix

Using the output matrix, you can connect the internal start and trip signals to the
digital outputs and indicators. For more details, see 5.4.1 Output matrix.

Blocking

Any protection function, except for arc flash detection, can be blocked with
internal and external signals using the block matrix (5.4.2 Blocking matrix).

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Internal signals are for example logic outputs and start and trip signals from other
stages and external signals are for example digital and virtual inputs.

Some protection stages have also built-in blocking functions. For example under-
frequency protection has built-in under-voltage blocking to avoid tripping when the
voltage is off.
When a protection stage is blocked, it does not start if a fault condition is
detected. If blocking is activated during the operation delay, the delay counting is
frozen until the blocking goes off or the start reason, that is the fault condition,
disappears. If the stage is already tripping, the blocking has no effect.

Dependent time operation

The operate time in the dependent time mode is dependent on the magnitude of
the injected signal. The bigger the signal, the faster the stage issues a trip signal
and vice versa. The tripping time calculation resets if the injected quantity drops
below the start level.

Definite time operation

Figure 59 - Dependent time and definite time operation curves

IDMT DT

t (s)

If (A)

The operate time in the definite time mode is fixed by the Operation delay
setting. The timer starts when the protection stage activates and counts until the
set time has elapsed. After that, the stage issues a trip command. Should the
protection stage reset before the definite time operation has elapsed, then the
stage resets.

By default, the definite time delay cannot be set to zero because the value
contains processing time of the function and operate time of the output contact.
This means that the time indicated in the Definite time setting view is the actual
operate time of the function. Use the Accept zero delay setting in the protection
stage setting view to accept the zero setting for definite time function. In this case,
the minimum operate time of the function must be tested separately.

Overshoot time

Overshoot time is the time the protection device needs to notice that a fault has
been cleared during the operate time delay. This parameter is important when
grading the operate time delay settings between devices.

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Figure 60 - Overshoot time

RetardationTime

tFAULT
tRET < 50 ms

DELAY SETTING > tFAULT + tRET

TRIP CONTACTS

If the delay setting would be slightly shorter, an unselective trip might occur (the
dash line pulse).

For example, when there is a big fault in an outgoing feeder, it might start both the
incoming and outgoing feeder relay. However, the fault must be cleared by the
outgoing feeder relay and the incoming feeder relay must not trip. Although the
operating delay setting of the incoming feeder is more than at the outgoing feeder,
the incoming feeder might still trip if the operate time difference is not big enough.
The difference must be more than the overshoot time of the incoming feeder relay
plus the operate time of the outgoing feeder circuit breaker.

Figure 60 shows an overvoltage fault seen by the incoming feeder when the
outgoing feeder clears the fault. If the operation delay setting would be slightly
shorter or if the fault duration would be slightly longer than in the figure, an
unselective trip might happen (the dashed 40 ms pulse in the figure). In Easergy
P3 devices, the overshoot time is less than 50 ms.

Reset time

Figure 61 shows an example of reset time, that is, release delay when the relay is
clearing an overcurrent fault. When the relay’s trip contacts are closed, the circuit
breaker (CB) starts to open. After the CB contacts are open, the fault current still
flows through an arc between the opened contacts. The current is finally cut off
when the arc extinguishes at the next zero crossing of the current. This is the start
moment of the reset delay. After the reset delay the trip contacts and start contact
are opened unless latching is configured. The precise reset time depends on the
fault size; after a big fault, the reset time is longer. The reset time also depends
on the specific protection stage.

The maximum reset time for each stage is specified under the characteristics of
every protection function. For most stages, it is less than 95 ms.

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Figure 61 - Reset time

tSET
tCB
tRESET
TRIP CONTACTS

Reset time is the time it takes the trip or start relay contacts to open after the fault
has been cleared.

Hysteresis or dead band

When comparing a measured value against a start value, some amount of

hysteresis is needed to avoid oscillation near equilibrium situation. With zero
hysteresis, any noise in the measured signal or any noise in the measurement
itself would cause unwanted oscillation between fault-on and fault-off situations.

Figure 62 - Example behavior of an over-protection with hysteresis

Hysteresis_GT
hysteresis

Start level

> Start

Figure 63 - Example behavior of an under-protection with hysteresis

Hysteresis_LT
hysteresis

Start level

< Start

Time grading

When a fault occurs, the protection scheme only needs to trip circuit breakers
whose operation is required to isolate the fault. This selective tripping is also
called discrimination or protection coordination and is typically achived by time
grading. Protection systems in successive zones are arranged to operate in times
that are graded through the sequence of equipment so that upon the occurrence
of a fault, although a number of protections devices respond, only those relevant
to the faulty zone complete the tripping function.

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The recommended discrimination time between two Easergy P3 devices in an MV

network is 170–200 ms. This is based on the following facts:
• Tc: circuit breaker operating time, 60 ms
• Tm: upstream protection overshoot time (retardation time), 50 ms
• δt: time delay tolerance, 25 ms
• m: safety margin, 10 ms
• Δt: discrimination time, 170–200 ms

Figure 64 - Time grading

δt TC m Tm δt

time
Δt

Recorded values of the last eight faults

There is detailed information available on the last eight faults for each protection
stage. The recorded values are specific for the protection stages and can contain
information like time stamp, fault value, elapsed delay, fault current, fault voltage,
phase angle and setting group.

NOTE: The recorded values are lost if the relay power is switched off.

Squelch limit

Current inputs have a squelch limit (noise filter) at 0.005 x IN. When the
measured signal goes below this threshold level, the signal is forced to zero.

NOTE: If ICALC is used to measure the residual current, the squelch limit for
the ICALC signal is same as for the phase currents. The I0 setting range begins
at the level of phase currents' squelch limit. This can cause instability if the
minimum setting is used with the I0 CALC mode.

6.6 Dependent operate time

The dependent operate time – that is, the inverse definite minimum time (IDMT)
type of operation – is available for several protection functions. The common
principle, formula and graphic representations of the available dependent delay
types are described in this chapter.

Dependent delay means that the operate time depends on the measured real
time process values during a fault. For example, with an overcurrent stage using
dependent delay, a bigger a fault current gives faster operation. The alternative to
dependent delay is definite delay. With definite delay, a preset time is used and
the operate time does not depend on the size of a fault.

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Stage-specific dependent delay

Some protection functions have their own specific type of dependent delay.
Details of these dedicated dependent delays are described with the appropriate
protection function.

Operation modes

There are three operation modes to use the dependent time characteristics:

• Standard delays

Using standard delay characteristics by selecting a curve family (IEC, IEEE,

IEEE2, RI) and a delay type (Normal inverse, Very inverse etc). See 6.6.1
Standard dependent delays using IEC, IEEE, IEEE2 and RI curves.
• Standard delay formulae with free parameters

selecting a curve family (IEC, IEEE, IEEE2) and defining one's own
parameters for the selected delay formula. This mode is activated by setting
delay type to ‘Parameters’, and then editing the delay function parameters A –
E. See 6.6.2 Custom curves.
• Fully programmable dependent delay characteristics

Building the characteristics by setting 16 [current, time] points. The relay

interpolates the values between given points with second degree polynomials.
This mode is activated by the setting curve family to ‘PrgN’'. There is a
maximum of three different programmable curves available at the same time.
Each programmed curve can be used by any number of protection stages.
See 6.6.3 Programmable dependent time curves.

CAUTION
HAZARD OF NON-OPERATION

When changing the dependent time (inverse curves) operation mode

settings manually through the device HMI, change both the Curve (Curve
delay family) and Type (Delay type) setting.

Failure to follow these instructions can result in injury or equipment

damage.

Dependent time limitation

The maximum dependent time is limited to 600 seconds.

Local panel graph

The relay shows a graph of the currently used dependent delay on the local panel
display. The up and down keys can be used for zooming. Also the delays at 20 x
ISET, 4 x ISET and 2 x ISET are shown.

Dependent time setting error signal

If there are any errors in the dependent delay configuration, the appropriate
protection stage uses the definite time delay.

There is a signal ‘Setting Error’ available in the output matrix that indicates
different situations:

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1. Settings are currently changed with Easergy Pro or local panel.

2. There is temporarily an illegal combination of curve points. For example, if

previous setting was IEC/NI and then curve family is changed to IEEE, this
causes a setting error because there is no NI type available for IEEE curves.
After changing valid delay type for IEEE mode (for example MI), the ‘Setting
Error’ signal releases.

3. There are errors in formula parameters A – E, and the relay is not able to
build the delay curve.

4. There are errors in the programmable curve configuration, and the relay is not
able to interpolate values between the given points.

Limitations

The maximum measured secondary phase current is 50 x IN and the maximum

directly measured ground fault current is 10 x I0N for ground fault overcurrent
input. The full scope of dependent delay curves goes up to 20 times the setting.
At a high setting, the maximum measurement capability limits the scope of
dependent curves according to Table 50.

Table 50 - Maximum measured secondary currents and settings for phase and
ground fault overcurrent inputs

Current input Maximum measured Maximum secondary

secondary current scaled setting enabling
dependent delay times
up to full 20x setting

IA, IB, IC and IN Calc 250 A 12.5 A

IN1 = 5 A 50 A 2.5 A

IN1 = 1 A 10 A 0.5 A

IN1 = 0.2 A 2A 0.1 A

Example of limitation

CT = 750 / 5

CT0 = 100 / 1 (cable CT is used for ground fault overcurrent)

The CT0 is connected to a 1 A terminals of input IN.

The CT0 is connected to a 1 A terminals of input IN1.

For overcurrent stage 50/51 - 1, Table 50 gives 12.5 A. Thus, the maximum
setting the for 50/51 - 1 stage giving full dependent delay range is 12.5 A / 5 A =
2.5 xIN = 1875 APrimary.

For ground fault stage 50N/51N-1, Table 50 gives 0.5 A. Thus, the maximum
setting for the 50N/51N-1 stage giving full dependent delay range is 0.5 A / 1 A =
0.5 xI0N = 50 APrimary.

1. Example of limitation

CT0 = 100 / 1 (cable CT is used for ground fault overcurrent)

The CT0 is connected to a 1 A terminals of input IN1.

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6.6.1 Standard dependent delays using IEC, IEEE, IEEE2 and RI curves

The available standard dependent delays are divided in four categories called
dependent curve families: IEC, IEEE, IEEE2 and RI. Each category contains a set
of different delay types according to Table 51.

Dependent time setting error signal

The dependent time setting error signal activates if the delay category is changed
and the old delay type does not exist in the new category. See 6.6 Dependent
operate time for more details.

Limitations

The minimum definite time delay starts when the measured value is twenty times
the setting, at the latest. However, there are limitations at high setting values due
to the measurement range. See 6.6 Dependent operate time for more details.

Table 51 - Available standard delay families and the available delay types within
each family

Delay type Curve family

DT IEC IEEE IEEE2 RI

DT Definite X
time

NI Normal X X
inverse

VI Very X X X
inverse

EI Extremely X X X
inverse

LTI Long time X X

inverse

LTEI Long time X

extremely
inverse

LTVI Long time X

very
inverse

MI Moderately X X
inverse

STI Short time X

inverse

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Delay type Curve family

DT IEC IEEE IEEE2 RI

STEI Short time X

extremely
inverse

RI Old ASEA X
type

RXIDG Old ASEA X

type

IEC dependent operate time

The operate time depends on the measured value and other parameters
according to Equation 7. Actually this equation can only be used to draw graphs
or when the measured value I is constant during the fault. A modified version is
implemented in the relay for real time usage.

Equation 7

kA
t= B
 I 
  − 1
 I START 

t = Operation delay in seconds

k = User’s multiplier Inv. time coefficient k

I = Measured value

ISTART = Start setting

A, B = Constants parameters according to Table 52.

There are three different dependent delay types according to IEC 60255-3,
Normal inverse (NI), Extremely inverse (EI), Very inverse (VI) and a VI extension.
In addition, there is a de facto standard Long time inverse (LTI).

Table 52 - Constants for IEC dependent delay equation

Parameter
Delay type
A B

NI Normal inverse 0.14 0.02

EI Extremely inverse 80 2

VI Very inverse 13.5 1

LTI Long time inverse 120 1

Example of the delay type "Normal inverse (NI)":

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k = 0.50

I = 4 pu (constant current)

IPICKUP = 2 pu

A = 0.14

B = 0.02

Equation 8

0.50 ⋅ 0.14
t= 0.02
= 5. 0
4
  −1
2

The operate time in this example is five seconds. The same result can be read
from Figure 65.

Figure 65 - IEC normal inverse delay

IEC NI

B inverseDelayIEC_NI

A. Delay (s) B. I / Iset

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Figure 66 - IEC extremely inverse delay

IEC EI

B inverseDelayIEC_EI

A. Delay (s) B. I / Iset

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Figure 67 - IEC very inverse delay

IEC VI

B inverseDelayIEC_VI

A. Delay (s) B. I / Iset

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Figure 68 - IEC long time inverse delay

IEC LTI

B inverseDelayIEC_LTI

A. Delay (s) B. I / Iset

IEEE/ANSI dependent operate time

There are three different delay types according to IEEE Std C37.112-1996 (MI, VI,
EI) and many de facto versions according to Table 53. The IEEE standard defines
dependent delay for both trip and release operations. However, in the Easergy P3
relay only the trip time is dependent according to the standard but the reset time
is constant.

The operate delay depends on the measured value and other parameters
according to Equation 9. Actually, this equation can only be used to draw graphs
or when the measured value I is constant during the fault. A modified version is
implemented in the relay for real-time usage.

Equation 9

 
 
 A 
t=k  C
+ B
  I  − 1 
  I START  
 

t = Operation delay in seconds

k = User’s multiplier

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I = Measured value

ISTART = Start setting

A,B,C = Constant parameter according to Table 53

Table 53 - Constants for IEEE/ANSI inverse delay equation

Delay type Parameter

A B C

LTI Long time 0.086 0.185 0.02

inverse

LTVI Long time very 28.55 0.712 2

inverse

LTEI Long time 64.07 0.250 2

extremely
inverse

MI Moderately 0.0515 0.1140 0.02

inverse

VI Very inverse 19.61 0.491 2

EI Extremely 28.2 0.1217 2

inverse

STI Short time 0.16758 0.11858 0.02

inverse

STEI Short time 1.281 0.005 2

extremely
inverse

Example of the delay type "Moderately inverse (MI)":

k = 0.50

I = 4 pu

IPICKUP = 2 pu

A = 0.0515

B = 0.114

C = 0.02

Equation 10

 
 
t = 0.50 ⋅  0.0515
+ 0.1140 = 1.9
  4  0.02 
  −1 
  2  

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The operate time in this example is 1.9 seconds. The same result can be read
from Figure 72.

Figure 69 - ANSI/IEEE long time inverse delay

IEEE LTI

B inverseDelayIEEE1_LTI

A. Delay (s) B. I / Iset

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Figure 70 - ANSI/IEEE long time very inverse delay

IEEE LTVI

B inverseDelayIEEE1_LTVI

A. Delay (s) B. I / Iset

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Figure 71 - ANSI/IEEE long time extremely inverse delay

IEEE LTEI

B inverseDelayIEEE1_LTEI

A. Delay (s) B. I / Iset

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Figure 72 - ANSI/IEEE moderately inverse delay

IEEE MI

B inverseDelayIEEE1_MI

A. Delay (s) B. I / Iset

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Figure 73 - ANSI/IEEE short time inverse delay

IEEE STI

B inverseDelayIEEE1 STI

A. Delay (s) B. I / Iset

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Figure 74 - ANSI/IEEE short time extremely inverse delay

IEEE STEI

B inverseDelayIEEE1 STEI

A. Delay (s) B. I / Iset

IEEE2 dependent operate time

Before the year 1996 and ANSI standard C37.112 microprocessor relays were
using equations approximating the behavior of various induction disc type relays.
A quite popular approximation is Equation 11 which in Easergy P3 relays is called
IEEE2. Another name could be IAC because the old General Electric IAC relays
have been modeled using the same equation.

There are four different delay types according to Table 54. The old
electromechanical induction disc relays have dependent delay for both trip and
release operations. However, in Easergy P3 relays, only the trip time is
dependent and the reset time is constant.

The operate delay depends on the measured value and other parameters
according to Equation 11. Actually, this equation can only be used to draw graphs
or when the measured value I is constant during the fault. A modified version is
implemented in the relay for real-time usage.

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Equation 11

 
 
 B D E 
t = k A + + + 3
 I  2
  − C   I − C   I − C  

  I START   I START 

I
 START
 
 

t = Operation delay in seconds

k = User’s multiplier

I = Measured value

ISTART = User’s start setting

A, B, C, D = Constant parameter according to Table 54.

Table 54 - Constants for IEEE2 inverse delay equation

Parameter
Delay type
A B C D E

MI Moderately 0.1735 0.6791 0.8 -0.08 0.1271

inverse

NI Normally 0.0274 2.2614 0.3 -4.1899 9.1272

inverse

VI Very 0.0615 0.7989 0.34 -0.284 4.0505

inverse

EI Extremely 0.0399 0.2294 0.5 3.0094 0.7222

inverse

Example of the delay type "Moderately inverse (MI)":

k = 0.50

I = 4 pu

ISTART = 2 pu

A = 0.1735

B = 0.6791

C = 0.8

D = -0.08

E = 0.127

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Equation 12

 
 
0.6791 − 0.08 0.127 
t = 0.5 ⋅ 0.1735 + + + = 0.38
 4  4 
2
 4 
3

  − 0.8   − 0.8   − 0.8  
 2  2  2  

The operate time in this example is 0.38 seconds. The same result can be read
from Figure 75.

Figure 75 - IEEE2 moderately inverse delay

IEEE2 MI

B inverseDelayIEEE2_MI

A. Delay (s) B. I / Iset

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Figure 76 - IEEE2 normal inverse delay

IEEE2 NI

B inverseDelayIEEE2_NI

A. Delay (s) B. I / Iset

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Figure 77 - IEEE2 very inverse delay

IEEE2 VI

B inverseDelayIEEE2_VI

A. Delay (s) B. I / Iset

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Figure 78 - IEEE2 extremely inverse delay

IEEE2 EI

B inverseDelayIEEE2_EI

A. Delay (s) B. I / Iset

RI and RXIDG type dependent operate time

These two dependent delay types have their origin in old ASEA (nowadays ABB)
ground fault relays.
The operate delay of types RI and RXIDG depends on the measured value and
other parameters according to Equation 13 and Equation 14. Actually, these
equations can only be used to draw graphs or when the measured value I is
constant during the fault. Modified versions are implemented in the relay for real-
time usage.

Equation 13 Equation 14

k I
t RI = t RXIDG = 5.8 − 1.35 ln
0.236 k I START
0.339 −
 I 
 
 I START 

t = Operate delay in seconds

k = User’s multiplier

I = Measured value

ISTART = Start setting

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Example of the delay type RI

k = 0.50

I = 4 pu

ISTART = 2 pu

Equation 15

0.5
t RI = = 2.3
0.236
0.339 −
4
 
2

The operate time in this example is 2.3 seconds. The same result can be read
from Figure 79.

Example of the delay type RXIDG

k = 0.50

I = 4 pu

ISTART = 2 pu

Equation 16

4
t RXIDG = 5.8 − 1.35 ln = 3.9
0.5 ⋅ 2

The operate time in this example is 3.9 seconds. The same result can be read
from Figure 80.

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Figure 79 - RI dependent delay

RI

B inverseDelayRI

A. Delay (s) B. I / Iset

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Figure 80 - RXIDG dependent delay

A. Delay (s) B. I / Iset

6.6.2 Custom curves

This mode is activated by the setting delay type to ‘Parameters’, and then editing
the delay function constants, that is, the parameters A – E. The idea is to use the
standard equations with one’s own constants instead of the standardized
constants as in the previous chapter.

Example of the GE-IAC51 delay type:

k = 0.50

I = 4 pu

ISTART = 2 pu

A = 0.2078

B = 0.8630

C = 0.8000

D = - 0.4180

E = 0.1947

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Equation 17

 
 
 0.8630 − 0.4180 0.1947 
t = 0.5 ⋅ 0.2078 + + + = 0.37
 4  4 
2
 4 
3

  − 0.8   − 0.8   − 0.8  
 2  2  2  

The operate time in this example is 0.37 seconds.

The resulting time/current characteristic of this example matches quite well the
characteristic of the old electromechanical IAC51 induction disc relay.

Dependent time setting error signal

The dependent time setting error signal actives if interpolation with the given
parameters is not possible. See 6.6 Dependent operate time for more details.

Limitations

The minimum definite time delay starts at the latest when the measured value is
twenty times the setting. However, there are limitations at high setting values due
to the measurement range. See 6.6 Dependent operate time for more details.

6.6.3 Programmable dependent time curves

Programming dependent time curves requires Easergy Pro setting tool and
rebooting the unit.

The [current, time] curve points are programmed using Easergy Pro PC program.
There are some rules for defining the curve points:
• the configuration must begin from the topmost line
• the line order must be as follows: the smallest current (longest operate time)
on the top and the largest current (shortest operate time) on the bottom
• all unused lines (on the bottom) should be filled with [1.00 0.00s]

Here is an example configuration of curve points:

Point Current I/ISTART Operate delay

1 1.00 10.00 s

2 2.00 6.50 s

3 5.00 4.00 s

4 10.00 3.00 s

5 20.00 2.00 s

6 40.00 1.00 s

7 1.00 0.00 s

8 1.00 0.00 s

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Point Current I/ISTART Operate delay

9 1.00 0.00 s

10 1.00 0.00 s

11 1.00 0.00 s

12 1.00 0.00 s

13 1.00 0.00 s

14 1.00 0.00 s

15 1.00 0.00 s

16 1.00 0.00 s

Dependent time setting error signal

The dependent time setting error signal activates if interpolation with the given
points fails. See 6.6 Dependent operate time for more details.

Limitations

The minimum definite time delay starts at the latest when the measured value is
twenty times the setting. However, there are limitations at high setting values due
to the measurement range. See 6.6 Dependent operate time for more details.

6.7 Volts/hertz overexcitation protection (ANSI 24)

The saturation of any inductive network components like transformers, inductors,
motors and generators depends on the voltage and frequency. The lower the
frequency, the lower is the voltage at which the saturation begins.

The volts/hertz overexcitation protection stage is sensitive to the voltage/

frequency ratio instead of voltage only. Figure 81 shows the difference between
volts/hertz and a standard overvoltage function. The highest of the three line-to-
line voltages is used regardless of the voltage measurement mode (10.8 Voltage
system configuration). By using line-to-line voltages, any line-to-neutral
overvoltages during ground faults have no effect. (The ground fault protection
functions take care of ground faults.)

The used net frequency is automatically adopted according to the local network
frequency.

Overexcitation protection is needed for generators that are excitated even during
startup and shutdown. If such a generator is connected to a unit transformer, also
the unit transformer needs volts/hertz overexcitation protection. Another
application is sensitive overvoltage protection of modern transformers with no flux
density margin in networks with unstable frequency.

This figure shows the difference between volts/hertz and normal overvoltage
protection. The volts/hertz characteristics on the left depend on the frequency,
while the standard overvoltage function on the right is insensitive to frequency.
The network frequency, 50 Hz or 60 Hz, is automatically adopted by the relay.

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Figure 81 - Difference between volts/hertz and normal overvoltage protection

%
V f> set t in g V f> set t in g 0
18
2.0 2.0

1.8 1.8
0%

Measured voltage (PU)

Measured voltage (PU)

TRIP AREA
1.6 1.6 14
140 % EA
1.4 1.4 AR
IP
1.2 1.2 TR 0%
10
100 %
1.0 1.0
0.8 0.8
ok area
0.6 0.6
0.4 0.4 r ea
ok a
0.2 0.2

30 35 40 45 50 55 60 65 30 35 40 45 50 55 60 65
30 36 42 48 54 60 66 72 30 36 42 48 54 60 66 72
OverVoltFreqChar VoltPerHerz
Frequency (Hz ) Frequency (Hz )

Setting groups

There are four setting groups available for each stage.

Characteristics

Table 55 - Volts/hertz over-excitation protection 24–1

Start setting range 100–200%

Operating time 0.3–300.0 s

Start time Typically 200 ms

Reset time < 450 ms

Reset ratio 0.995

Inaccuracy:

- Starting V< 0.5% unit

f < 0.05 Hz

- Operating time at definite time function ±1% or ±150 ms

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6.8 Synchronism check (ANSI 25)

Description

The relay includes a function that checks the synchronism before giving or
enabling the circuit breaker close command. The function monitors the voltage
amplitude, frequency and phase angle difference between two voltages. Since
there are two stages available, it is possible to monitor three voltages. The
voltages can be busbar and line or busbar and busbar (bus coupler).

Figure 82 - Synchronism check function

Close
Request
cmd

Side 1 V1= V2 & Sync fail

Side 2 f1 = f2
φ1 = φ2 & & CB close

Register
V1 event
V2 & ≥1 Sync OK

Timeout Settings Sync Voltage Bypass

mode mode

The synchronism check stage includes two separate synchronism criteria that can
be used separately or combined:

• voltage only
• voltage, frequency, and phase

The voltage check simply compares voltage conditions of the supervised objects.
The supervised object is considered dead (not energized) when the measured
voltage is below the Vdead setting limit. Similarly, the supervised object is
considered live (energized) when the measured voltage is above the Vlive setting
limit. Based on the measured voltage conditions and the selected voltage check
criteria, synchronism is declared.

When the network sections to be connected are part of the same network, the
frequency and phase are the same. Therefore, the voltage check criteria is safe to
use without frequency and phase check.

The frequency and phase check compares the voltages, frequency and phase of
the supervised objects. Synchronism is declared if the voltages are above the
Vlive limit and all three difference criteria are within the given limits. This
synchronism check is dynamic by nature, and the object close command is given
at a certain moment of time, depending on the selected mode of operation.

When two networks are running at slightly different frequencies, there is also a
phase difference between these two networks. Because of the different frequency,
the phase angle tends to rotate. The time for one cycle depends on the frequency
difference. The stress for electrical components is lowest when two networks are
connected at zero phase difference.

In the “Sync” mode, the circuit breaker closing is aimed at the moment of zero
phase difference. Therefore, the close command is advanced by the time defined
by the CB close time setting. In the “Async” mode, the circuit breaker closing is

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aimed at the moment when the synchronism conditions are met, that is, when the
phase difference is within the given phase difference limit.
When two network sections to be connected are from different sources or
generators, the voltage criteria alone is not safe, so also frequency and phase
check must be used.

When two networks with different frequencies are to be connected, the request
timeout setting must be long enough to allow the synchronism criteria to be met.
For example, if the frequency difference is 0.1 Hz, the synchronism criteria is met
only once in ten seconds.

The synchronism check stage starts from an object close command that
generates a request to close the selected circuit breaker (as per CONTROL
SETTINGS view) when the synchronism conditions are met. The synchronism
check stage provides a "request" signal that is active from the stage start until the
synchronism conditions are met or the request timeout has elapsed. When the
synchronism conditions are not met within the request timeout, a “fail” pulse is
generated. The fail pulse has a fixed length of 200 ms. When the synchronism
conditions are met in a timely manner, the object close command is initiated for
the selected object. This signal is purely internal and not available outside the
synchronism check stage. When the synchronism conditions are met, the “OK”
signal is always active. The activation of the bypass input bybasses the
synchronism check and declares synchronism at all times.

The request, OK, and fail signals are available in the output matrix.

The synchronized circuit breaker close execution order is shown in Figure 83.

Figure 83 - Synchronism check execution order

1 2 3
A B C
4 5

A. Synchronism check stage

B. Object
C. Circuit breaker (physical) as selected in the CB Object 1 or CB Object 2 setting in the
CONTROL SETTINGS view of the synchro-check stage.

NOTE: A synchronisim check is made only if a CB is selected in the

CONTROL SETTING view.
1. Object close command from mimic, digital inputs or communication protocol

2. Synchronism declared

3. Circuit breaker close command

4. Sync fail signal if request timeout elapsed before synchronism conditions met

5. Object fail signal if CB failed to operate

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Figure 84 - Synchronism check function principle

A B
1

C D

1. Sync request

2. Sync OK

3. Object close command

A. The object close command given (mimic or bus) actually only makes a sync request.
B. The sync request ends when the synchronism conditions are met and CB command is given or
if the request timeout elapsed.
C. If the request timeout elapsed before synchronism conditions are met, sync fail pulse is
generated.
D. Normal object close operation

The synchronism check function is available when one of the following analog
measurement modules and a suitable measuring mode are in use:

Table 56 - Voltage measuring modes

Voltage measuring mode Number of synchrocheck stages

3LN+LLy 1

3LN+LNy 1

2LL+VN+LLy 1

2LL+VN+LNy 1

LL+VN+LLy+LLz 2

LN+VN+LNy+LNz 2

Connections for synchronism check

The voltage used for checking the synchronism is always line-to-line voltage VAB
even when VA is measured. The sychronism check stage 1 always compares VAB
with VABy. The compared voltages for the stage 2 can be selected (VAB/VABy,
VAB/VABz, VABy/VABz). See 10.8 Voltage system configuration.

NOTE: To perform its operation, the synchronism check stage 2 converts the
voltages LNy and LNz to line-to-line voltage VAB. As such, the measured
voltage for LNy and LNz must be VA-N.

NOTE: The wiring of the secondary circuits of voltage transformers to the

relay terminal depends on the selected voltage measuring mode.

See the synchronism check stage's connection diagrams in See 10.8 Voltage
system configuration.

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Characteristics

Table 57 - Synchronism check function (25)

Input signal V1 – V4

Synchronism check mode (SMODE) Off; Async; Sync 39) 40) 41)

Voltage check mode (VMODE) DD; DL; LD; DD/DL; DD/LD; DL/LD;
DD/DL/LD 42) 43) 44) 45)

CB closing time 0.04–0.6 s

VDEAD limit setting 10–120% VN

VLIVE limit setting 10–120% VN

Frequency difference 0.01–1.00 Hz

Voltage difference 1–60% VN

Phase angle difference 2°–90°

Request timeout 0.1–600.0 s

Stage operation range 46.0–64.0 Hz

Reset ratio (V) 0.97

Inaccuracy:

- voltage ±3% VN

- frequency ±20 mHz

- phase angle ±2° (when Δf < 0.2 Hz, else ±5°)

- operate time ±1% or ±30 ms

39) Off – Frequency and phase criteria not in use
40) Async – dF, dU and d angle criteria are used. Circuit breaker close is aimed at the moment when
the phase angle is within phase angle difference limit. Slip frequency dF determines how much the
close command needs to be advanced to make the actual connection at the moment when the phase
angle is within the phase angle limit
41) Sync mode – d , d and d angle criteria are used. Circuit breaker close is aimed at the moment
F U
when the phase angle becomes zero. Slip frequency dF determines how much the close command
needs to be advanced to make the actual connection at zero phase angle.
42) The first letter refers to the reference voltage and the second letter to the comparison voltage.
43) D means that the side must be “dead” when closing (dead = The voltage is below the dead voltage

limit setting).
44) L means that the side must be “live” when closing (live = The voltage is higher than the live voltage

limit setting).
45) Example: DL mode for stage 1: The U12 side must be “dead” and the U12y side must be “live”.

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6.9 Undervoltage (ANSI 27)

Description

Undervoltage protection is used to detect voltage dips or sense abnormally low

voltages to trip or trigger load shedding or load transfer. The function measures
the three line-to-line voltages, and whenever the smallest of them drops below the
start setting of a particular stage, this stage starts and a start signal is issued. If
the fault situation remains on longer than the operate time delay setting, a trip
signal is issued.

Blocking during voltage transformer fuse failure

As all the protection stages, the undervoltage function can be blocked with any
internal or external signal using the block matrix. For example if the secondary
voltage of one of the measuring transformers disappears because of a fuse failure
(See the voltage transformer supervision function in 7.8 Voltage transformer
supervision (ANSI 60FL)). The blocking signal can also be a signal from the
custom logic (see 5.7 Logic functions).

Low-voltage self blocking

The stages can be blocked with a separate low-limit setting. With this setting, the
particular stage is blocked when the biggest of the three line-to-line voltages
drops below the given limit. The idea is to avoid unwanted tripping when the
voltage is switched off. If the operate time is less than 0.08 s, the blocking level
setting should not be less than 15% for the blocking action to be fast enough. The
self blocking can be disabled by setting the low-voltage block limit equal to zero.

Figure 85 - Example of low-voltage self blocking

A
K K K
I
B
C
J J
H J

D
G
L L F

A. VLLmax = max (VAB, VBC, VCA)

B. Deadband
C. V< setting
D. Block limit
E. V< undervoltage state
F. Time
G. The maximum of the three line-to-line voltages VLLmax is below the block limit. This is not
regarded as an undervoltage situation.
H. The voltage VLLmax is above the block limit but below the start level. This is an undervoltage
situation.
I. The voltage is OK because it is above the start limit.

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J. This is an undervoltage situation.

K. The voltage is OK.
L. The voltage VLLmax is under the block limit and this is not regarded as an undervoltage situation.

Three independent stages

There are three separately adjustable stages: 27-1, 27-2 and 27-3. All these
stages can be configured for the definite time (DT) operation characteristic.

Setting groups

There are four setting groups available for all stages.

Characteristics

Table 58 - Undervoltage (27–1)

Input signal VA – VC

Start value 20–120% VN (step 1%)

Definite time characteristic:

- Operate time 0.0846) – 300.00 s (step 0.02)

Hysteresis (reset ratio) 1.001–1.200 (0.1–20.0%, step 0.1%)

Self-blocking value of the undervoltage 0–80% VN

Start time Typically 60 ms

Release delay 0.06–300.00 s (step 0.02 s)

Reset time < 95 ms

Overshoot time < 50 ms

Reset ratio (Block limit) 0.5 V or 1.03 (3%)

Reset ratio 1.03 (depends on the hysteresis setting)

Inaccuracy:

- Starting ±3% of the set value

- Blocking ±3% of set value or ±0.5 V

- Operate time ±1% or ±30 ms

46) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.

Table 59 - Undervoltage (27–2)

Input signal VA – VC

Start value 20–120% VN (step 1%)

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Definite time characteristic:

- Operate time 0.0647) – 300.00 s (step 0.02)

Hysteresis (reset ratio) 1.001–1.200 (0.1–20.0%, step 0.1%)

Self-blocking value of the undervoltage 0–80% VN

Start time Typically 60 ms

Reset time < 95 ms

Overshoot time < 50 ms

Reset ratio (Block limit) 0.5 V or 1.03 (3%)

Reset ratio 1.03 (depends on the hysteresis setting)

Inaccuracy:

- Starting ±3% of the set value

- Blocking ±3% of set value or ±0.5 V

- Operate time ±1% or ±30 ms

47) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.

Table 60 - Undervoltage (27–3)

Input signal VA – VC

Start value 20–120% VN (step 1%)

Definite time characteristic:

- Operate time 0.0448) – 300.00 s (step 0.01)

Hysteresis (reset ratio) 1.001–1.200 (0.1–20.0%, step 0.1%)

Self-blocking value of the undervoltage 0–80% VN

Start time Typically 30 ms

Reset time < 95 ms

Overshoot time < 50 ms

Reset ratio (Block limit) 0.5 V or 1.03 (3%)

Reset ratio 1.03 (depends on the hysteresis setting)

Inaccuracy:

- Starting ±3% of the set value

- Blocking ±3% of set value or ±0.5 V
- Operate time ±1% or ±25 ms
48) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.

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6.10 Negative sequence overcurrent (ANSI 46)

Description

Negative sequence overcurrent protects against unbalanced phase currents and

single phasing. The protection is based on the negative sequence current. Both
definite time and dependent time characteristics are available. The dependent
delay is based on Equation 18. Only the base frequency components of the
phase currents are used to calculate the negative sequence value I2.

The negative sequence overcurrent protection is based on the negative sequence

of the base frequency phase currents. Both definite time and dependent time
characteristics are available.

Dependent time delay

The dependent time delay is based on the following equation:

Equation 18

K1
T= 2
 
 I 2  − K 22
I 
 TN 

T = Operate time

K1 = Delay multiplier

I2 = Measured and calculated negative sequence phase current of fundamental

frequency

ITN = Rated current of the transformer

K2 = Start setting I2 > in pu. The maximum allowed degree of unbalance.

Example

K1 = 15 s

I2 = 22.9 % = 0.229 x ITN

K2 = 5 % = 0.05 x ITN

15
t= 2
= 300.4
 0.229 
  − 0.05
2

 1 
The operate time in this example is five minutes.

More stages (definite time delay only)

If more than one definite time delay stages are needed for negative sequence
overcurrent protection, the freely programmable stages can be used (6.32
Programmable stages (ANSI 99)).

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Figure 86 - Dependent operation delay of negative sequence overcurrent I2 >

(ANSI 46). The longest delay is limited to 1000 seconds (=16min 40s).
CurrentUnbalanceChar
2000
1000

500 K2 = 2 % K 2 = 40 % K 2 = 70 %

200
100 K1 = 50 s

A 50

K2 = 2 % K 2 = 40 % K 2 = 70 %
20
10

5
K1 = 1 s
2
1
0 20 40 60 80 100
B

A. Operate time (s) B. Negative sequence current I2%

Setting groups

There are four setting groups available.

Characteristics

Table 61 - Negative sequence overcurrent I2 > 46–1

Input signal IA – IC

Start value 2–70% (step 1%)

Definite time characteristic:

- Operate time 1.0–600.0 s (step 0.1 s)

Dependent time characteristic:

- 1 characteristic curve Inv

- Time multiplier 1–50 s (step 1)

- Upper limit for dependent time 1000 s

Start time Typically 300 ms

Reset time < 450 ms

Reset ratio 0.95

Inaccuracy:

- Starting ±1% - unit

- Operate time ±5% or ±200 ms

NOTE: The stage is operational when all secondary currents are above 250
mA.

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6.11 Negative sequence overvoltage protection (ANSI 47)

Description

This protection stage can be used to detect voltage unbalance and phase
reversal situations. It calculates the fundamental frequency value of the negative
sequence component V2 based on the measured voltages (for calculation of V2,
see 4.11 Symmetrical components).

Whenever the negative sequence voltage V2 raises above the user's start setting
of a particular stage, this stage starts, and a start signal is issued. If the fault
situation remains on longer than the user's operate time delay setting, a trip signal
is issued.

Blocking during VT fuse failure

Like all the protection stages, the negative sequence overvoltage can be blocked
with any internal or external signal using the block matrix, for example, if the
secondary voltage of one of the measuring transformers disappears because of a
fuse failure (See VT supervision function in 7.8 Voltage transformer supervision
(ANSI 60FL)).

The blocking signal can also be a signal from the user's logic (see 5.7 Logic
functions).

Three independent stages

There are three separately adjustable stages: 47-1, 47-2, and 47-3. Both stages
can be configured for the definite time (DT) operation characteristic.

Setting groups

There are four settings groups available for all stages. Switching between setting
groups can be controlled by digital inputs, virtual inputs (mimic display,
communication, logic) and manually.

Characteristics

Table 62 - Negative sequence overvoltage protection (47)

Start value: 47-1, 47-2, 47-3 2–120%

Operate time 0.08–300 s

Reset ratio 0.95

Inaccuracy:

- Starting ±1% - unit

- Operate time ±5% or ±200 ms

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6.12 Thermal overload (ANSI 49 RMS)

Description

The thermal overload function protects the transformer against excessive

temperatures.

Thermal model

The temperature is calculated using RMS values of phase currents and a thermal
model according IEC60255-149. The RMS values are calculated using harmonic
components up to the 15th.

Trip time:

I2 − I
2
t = τ ⋅ ln 2 P2
I −a
Alarm (alarm 60% = 0.6):

a = k ⋅ kΘ ⋅ I TN ⋅ alarm

Trip:

a = k ⋅ kΘ ⋅ I TN

Reset time:
2
IP
t = τ ⋅ Cτ ⋅ ln
a − I2
2

Trip release:

a = 0.95 × k × I TN

Start release (alarm 60% = 0.6):

a = 0.95 × k × I TN × alarm

T = Operate time

= Thermal time constant tau (setting value). Unit: minute

ln = Natural logarithm function

I =Measured RMS phase current (the max. value of three phase currents)

k = Overload factor (Maximum continuous current), i.e. service factor (setting

value).

kΘ = Ambient temperature factor (permitted current due to tamb).

Ip = Preload current, I P = θ × k × I TN (If temperature rise is 120% -> θ = 1.2). This

parameter is the memory of the algorithm and corresponds to the actual
temperature rise.

ITN = The rated current of the transformer

Cτ = Relay cooling time constant (setting value)

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Time constant for cooling situation

If the transformer's fan is stopped, the cooling will be slower than with an active
fan. Therefore there is a coefficient Cτ for thermal constant available to be used
as cooling time constant, when current is less than 0.3 x ITN.

Heat capacitance, service factor and ambient temperature

The trip level is determined by the maximum allowed continuous current IMAX
corresponding to the 100% temperature rise ΘTRIP for example the heat
capacitance of the transformer. IMAX depends of the given service factor k and
ambient temperature ΘAMB and settings IMAX40 and IMAX70 according the following
equation.

I MAX = k ⋅ k Θ ⋅ I TN

The value of ambient temperature compensation factor kΘ depends on the

ambient temperature ΘAMB and settings IMAX40 and IMAX70. See Figure 87.
Ambient temperature is not in use when kΘ = 1. This is true when
• IMAX40 is 1.0
• Samb is “n/a” (no ambient temperature sensor)
• ΘAMB is +40 °C.

Figure 87 - Ambient temperature correction of the overload stage T>

k
1.2

IMAX40
1.0

0.8 IMAX70

0.6

10 20 30 40 50 60 70 80 (°C)
AMB

50 68 86 104 122 140 158 176 (°F)

Example of the thermal model behavior

Figure 87 shows an example of the thermal model behavior. In this example, =

30 minutes, k = 1.06 and kΘ = 1 and the current has been zero for a long time
and thus the initial temperature rise is 0%. At time = 50 minutes, the current
changes to 0.85 x ITN and the temperature rise starts to approach value
(0.85/1.06)2 = 64% according to the time constant. At time = 300 min, the
temperature is nearly stable, and the current increases to 5% over the maximum
defined by the rated current and the service factor k. The temperature rise starts
to approach value 110%. At about 340 minutes, the temperature rise is 100% and
a trip follows.

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Initial temperature rise after restart

When the relay is switched on, an initial temperature rise of 70% is used.
Depending on the actual current, the calculated temperature rise then starts to
approach the final value.

Alarm function

The thermal overload stage is provided with a separately settable alarm function.
When the alarm limit is reached, the stage activates its start signal.

Figure 88 - Example of the thermal model behavior

thermbeh
Temperature rise

Θoverload
Θmax
Θalarm
Reset ratio=95%

Θp

Settings:
τ = 30 minutes
k = 1.06
Θalarm = 90%

Alarm
Trip

I/IN 1.6 min

IMAX = k*IN IOVERLOAD = 1.05*IMAX

45 min
IP = 0.85*IN

Time
100 min 200 min 300 min 400 min 500 min

Setting groups

This stage has one setting group.

Characteristics

Table 63 - Thermal overload (49T)

Input signal IA – IC

Maximum continuous current 0.1–2.40 x ITN

Alarm setting range 60–99% (step 1%)

Time constant τ 2–180 min (step 1)

Cooling time coefficient 1.0–10.0 x τ (step 0.1)

Max. overload at +40°C 70–120 %ITN (step 1)

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Max. overload at +70°C 50–100 %ITN (step 1)

Ambient temperature -55 – 125°C (step 1°)

Reset ratio (Start & trip) 0.95

Operate time inaccuracy Relative inaccuracy ±5% or absolute

inaccuracy 1 s of the theoretical value

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6.13 Breaker failure (ANSI 50BF)

Description

The circuit breaker failure protection stage (CBFP) can be used to operate any
upstream circuit breaker (CB) if the programmed output matrix signals, selected
to control the main breaker, have not disappeared within a given time after the
initial command. The supervised output contact is defined by the “Monitored Trip
Relay” setting. An alternative output contact of the relay must be used for this
backup control selected in the Output matrix setting view.

The CBFP operation is based on the supervision of the signal to the selected
output contact and the time. The following output matrix signals, when
programmed into use, start the CBFP function:
• protection functions
• control functions
• supporting functions
• GOOSE signals (through communication)

If the signal is longer than the CBFP stage’s operate time, the stage activates
another output contact defined in the Output matrix setting view. The output
contact remains activated until the signal resets. The CBFP stage supervises all
the signals assigned to the same selected output contact.

In Figure 89, both the trip and CBFP start signals activate simultaneously (left
picture). If T> trip fails to control the CB through T1, the CBFP activates T3 after
the breaker failure operate time.

Figure 89 - Trip and CBFP start signals in the Output matrix view

NOTE: For the CBFP, always select the ”Connected” crossing symbol in the
Output matrix setting view.

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Characteristics

Table 64 - Breaker failure (50BF)

Relay to be supervised T1–T4 (depending on the order code)

Definite time function:

- Operate time 0.1–10.0 s (step 0.1 s)

Inaccuracy:

- Operate time ±20 ms

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6.14 Breaker failure 1 and 2 (ANSI 50BF)

Easergy P3 has two identical Breaker failure 1 (ANSI 50BF) and Breaker failure 2
(ANSI 50BF) stages.

Description

Power system protection should always have some sort of backup protection
available. Backup protection is intended to operate when a power system fault is
not cleared or an abnormal condition is not detected in the required time because
of a failure or the inability of the primary protection to operate or failure of the
appropriate circuit breakers to trip. Backup protection may be local or remote.

Circuit breaker failure protection (CBFP) is part of the local backup protection.
CBFP provides a backup trip signal to an upstream circuit breaker (CB) when the
CB nearest to fault fails to clear fault current. The CB may fail to operate for
several reasons, for example burnt open coil or a flashover in the CB.

Figure 90 - CBFP implementation

A. CBFP trip C. Re-trip

B. Normal trip

Two separate stages are provided to enable re-trip and CBFP trip commands.
The first stage can be used to give re-trip command (for example to control
second/backup open coil of the main CB) while the second stage can give
dedicated CBFP trip command to an upstream circuit breaker. Select the required
outputs for re-trip and CBFP trip through the output matrix.

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Block diagram

Figure 91 - Breaker failure 2 operation

A I
IA
IB Imax > &
IC
& J

I0 > & ≥ t K
B

C & & J

D
&
E

F G H

A. Condition 1 G. Delay setting

B. Condition 2 H. Enable events setting
C. Condition 3 I. Start
D. Condition 4 J. Event register
E. Block K. Trip
F. Zero-current setting

CBFP operation

The CBFP function can be enabled and disabled with the Enable for BF2
selection. The CBFP function activates when any of the selected start signals
becomes and stays active.

The CBFP operation can be temporarily blocked by the stage block signal from
the block matrix. When the stage is blocked by the block signal, the stage timer
stops but it does not reset. The stage timer continues its operation when the block
signal is disabled. When the block signal is active, the stage output signals are
disabled.

The CBFP stage provides the following events:

• start on
• start off
• trip on
• trip off

Events can be activated via the Enable events setting view.

Condition selectors

The CBFP function has four condition selectors that can be used separately or all
together to activate and reset the CBFP function.

The four condition selectors are almost identical. The only difference is that
condition selectors 1 and 2 are for all protection functions that benefit from zero-
current detection for resetting the CBFP as described in section Zero-current
detector, and selectors 3 and 4 are for all the protection functions that do not
benefit from zero-current detection for CBFP.

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Condition selector 4 can be used to support selectors 1, 2 and 3. For example, if

there are too many stages to be monitored in condition set 1, condition selector 4
can be used to monitor the output contacts. Monitoring digital inputs is also
possible if the backup protection is based on external current relay, for example.
The only CBFP reset criteria for condition set 4 are the monitored input and
output signals.

Figure 92 - Start signal and reset condition setting view for Condition 1

Separate zero-current detection with dedicated start settings exists for phase
overcurrent and ground fault overcurrent signals. Zero-current detection is
independent of the protection stages.
The condition criteria, available signals and reset conditions are listed in Table 65.
NOTE: The start signal can be selected for each condition in advance from
the pull-down menu even if the concerned stage is not enabled. For the CBFP
activation, the concerned stage must be enabled from the protection stage
menu and the stage has to start to activate the CBFP start signal.

Table 65 - CBFP condition selectors

Criteria Start signal Reset condition

Condition 1 50/51-1, 50/51-2, 50/51-3, Reset by CB status: DI1 –

37, 46, 87M-1, 87M-2, 67-1, DIx (1, F1, F2, VI1-20,
67-2, 67-3, 67-4, 49RMS, VO1–20, GOOSE_NI1–64,
68F2, 21/40-1, 21/40-2, POC1–16, Obj1-8Op
68F5, SOTF
Monitored stage: On/Off

Condition 2 50N/51N-1, 50N/51N-2, Zero-current detection:

50N/51N-3, 50N/51N-4, On/Off
50N/51N-5, 67N-1, 67N-2,
67N-3

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Criteria Start signal Reset condition

Condition 3 64S, 59-1, 59-2, 59-3, 27-1, Reset by CB status: DI1 –

27-2, 27-3, 27P-1, 27P-2, DIx (1, F1, F2, VI1-20,
59N-1, 59N-2, 32-1, 32-2, VO1–20, GOOSE_NI1–64,
40, 21G-1, 21G-2,Pgr1-8, POC1–16, Obj1-8Op
81U-1, 81U-2, 81-1,81-2,
Monitored stage: On/Off
81R, 24, Pslip

Condition 4 Outputs: A1, T1-Tx (1

Inputs: DI1 – DIx (1, F1, F2,

VI1-20, VO1 – 20,
GOOSE_NI1 – 64, POC1 –
16

Arc sensor 3- 10, ArcStg1-8,

I>int, Io>int

In addition to the selection of the start signal, the CBFP reset condition needs to
be selected.

If no reset conditions are selected, the stage uses Reset by monitored stage as
the reset condition. This prevents a situation where the stage never releases.

The reset condition Reset by CB status is useful if the current is already zero
when the CB is opened (for example unloaded CB).

When more than one selection criteria are selected, AND condition is used, for
example “zero current detection” AND “object open”. See Figure 91 for details.

Stage timer

The operate delay timer is started by a signal activated by the monitored stages
(condition selectors). The operate time delay is a settable parameter. When the
given time delay has elapsed, the stage provides a trip signal through the output
matrix and the event codes.

The timer delay can be set between 40 and 200 ms.

Zero-current detector

The zero-current detector is an undercurrent condition to reset the CBFP function

when all phase currents are below the start (pick-up) setting value. This separate
undercurrent condition is needed to properly detect successful CB operation. For
example, in a CB failure condition where one or more CB poles are partly
conducting when the CB is open, the fault current can be small enough to reset
the primary protection stage (for example overcurrent stage), in which case the
CBFP does not operate. When a separate undercurrent limit is used, CBFP reset
can be performed only when the fault current really is zero or near zero instead of
relying on the protection stage reset.

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Figure 93 - Zero-current detector setting view

The setting range of the zero-current detector is always associated with the CT
nominal value, even in case of motor and transformer protection. The setting
range minimum depends on the relay accuracy. Instead of zero, a small minimum
value can be accepted. See Table 66.

CBFP coordination

The CBFP delay setting has to be coordinated according to the CB operation time
and the reset time of protection stages monitored by the CBFP function as
described in Figure 94.

Figure 94 - CBFP coordination

B
C E F

D G
A
H I

A. Fault occurrence F. Protection stage reset time + safety margin

B. Normal fault clearing time G. CBFP trip
C. Protection delay H. CBFP stage operate delay (CB operate time + protection stage
reset time + safety margin)
D. CBFP stage start I. CB operate time
E. CB operate time J. Total fault clearing time in case of failed CB operation but
successful CBFP operation

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Characteristics

Table 66 - Breaker failure 2 (ANSI 50BF)

Zero-current detection:

- Phase overcurrent 0.05–0.2 x In

- Ground fault overcurrent

Definite time function:

- Operate time 0.04–0.2 s

Inaccuracy:

- Operate time ±20 ms

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6.15 Switch-on-to-fault (ANSI 50HS)

Description

The switch-on-to-fault (SOTF) protection function offers fast protection when the
circuit breaker (CB) is closed manually against a faulty line. Overcurrent-based
protection does not clear the fault until the intended time delay has elapsed.
SOTF gives a trip signal without additional time delay if the CB is closed and a
fault is detected after closing the CB.

Figure 95 - Switch-on-to-fault function operates when the CB has detected open

and the fault current reaches start setting value

E
A
G
B
C
F
D

A. Start setting
B. Maximum of IA, IB, IC
C. Low limit 0.02 x IN
D. SOTF trip
E. Switch-on-to-fault does not activate if the CB has not been in open position before the fault.
Open CB detection is noticed from the highest phase current value which has to be under a fixed
low-limit threshold (0.02 x IN). Opening of the CB can be detected also with digital inputs (Dead
line detection input = DI1 – DIx, VI1 – VIx). The default detection input is based on the current
threshold, so the dead line detection input parameter has value “–“.
F. Dead line detection delay defines how long the CB has to be open so that the SOTF function is
active. If the set time delay is not fulfilled and the highest phase current value (maximum of IA, IB,
IC) rises over the start setting, the SOTF does not operate.
G.If the highest phase current value of IA, IB, IC goes successfully under the low limit and rises to a
value between the low limit and the start value, then if the highest phase current value rises over
the start setting value before the set SOTF active after CB closure time delay has elapsed, the
SOTF trips. If this time delay is exceeded, the SOTF does not trip even if the start setting value is
exceeded.

Setting groups

This stage has one setting group.

Characteristics

Table 67 - Switch-on-to-fault SOTF (50HS)

Current input IL or I’L

Start value 1.00–3.00 x IN (step 0.01)

Dead line detection delay 0.00–60.00 s (step 0.01)

SOTF active after CB closure 0.10–60.00 s (step 0.01)

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Operate time < 30 ms (When IM/ISET ratio > 1.5)

Reset time < 95 ms

Reset ratio 0.97

Inaccuracy ±3% of the set value or 5 mA secondary

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6.16 Phase overcurrent (ANSI 50/51)

Description

Phase overcurrent protection is used against short-circuit faults and heavy

overloads.

The overcurrent function measures the fundamental frequency component of the

phase currents. The protection is sensitive to the highest of the three phase
currents. Whenever this value exceeds the user's start setting of a particular
stage, this stage starts and a start signal is issued. If the fault situation remains on
longer than the operation delay setting, a trip signal is issued.

Block diagram

Figure 96 - Block diagram of the three-phase overcurrent stage 50/51-1

3vlsblock

Im1
Im2 MAX > ts tr
& H
Im3
& I
A t

>1 J

& I

B C D E F G

A. Block F. Multiplier
B. Setting I>s G. Enable events
C. Delay H. Start
D. Definite / dependent time I. Register event
E. Dependent time characteristics J. Trip

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Figure 97 - Block diagram of the three-phase overcurrent stage 50/51-2 and

50/51-3

3vIssblock

Im1
Im2 MAX > & E
Im3 ts tr

& F
A

t
G

& F

B C D

A. Block E. Start
B. Setting I>>s F. Register event
C. Delay G. Trip
D. Enable events

Three independent stages

There are three separately adjustable overcurrent stages: 50/51-1, 50/51-2 and
50/51-3. The first stage 50/51-1 can be configured for definite time (DT) or
dependent operate time (IDMT) characteristic. The stages 50/51-2 and 50/51-3
have definite time operation characteristic. By using the definite delay type and
setting the delay to its minimum, an instantaneous (ANSI 50) operation is
obtained.

Figure 96 shows a functional block diagram of the 50/51-1 overcurrent stage with
definite time and dependent time operate time. Figure 97 shows a functional block
diagram of the 50/51-2 and 50/51-3 overcurrent stages with definite time
operation delay.

Dependent operate time

Dependent operate time means that the operate time depends on the amount the
measured current exceeds the start setting. The bigger the fault current is, the
faster is the operation. The dependent time delay types are described in 6.6
Dependent operate time. The relay shows the currently used dependent operate
time curve graph on the local panel display.

Dependent time limitation

The maximum measured secondary current is 50 x IN. This limits the scope of
dependent curves with high start settings. See 6.6 Dependent operate time for
more information.

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Include harmonics setting

The 50/51-1 and 50/51-2 (50/51) overcurrent protection stages have a setting
parameter to include harmonics. When this setting is activated, the overcurrent
stage calculates the sum of the base frequency and all measured harmonics. This
feature is used to determine the signal's true root mean square value to detect the
signal's real heating factor. The operate time is 5 ms more when harmonics are
included in the measurement. Activate the "Include harmonics" setting if the
overcurrent protection is used for thermal protection and the content of the
harmonics is known to exist in the power system.

Cold load and inrush current handling

See 7.3 Cold load start and magnetizing inrush.

Setting groups

There are four setting groups available for each stage.

Characteristics

Table 68 - Phase overcurrent stage 50/51-1 (50/51)

Input signal IA – IC

Start value 0.05–5.00 x ITN (step 0.01)

Definite time function: DT49)

- Operate time 0.04–300.00 s (step 0.01 s)

IDMT function:

- Delay curve family (DT), IEC, IEEE, RI Prg

- Curve type EI, VI, NI, LTI, MI…, depends on the

- Inv. time coefficient k family50)

- RI curve 0.025–20.0

0.025–20.0

Start time 40 ms at 2 * Is pick-up value

Reset time < 95 ms

Overshoot time < 50 ms

Reset ratio 0.97

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Transient overreach, any τ < 10%

Inaccuracy:

- Starting ±3% of the set value or 5 mA secondary

- Operate time at definite time function ±1% or ±25 ms

- Operate time at IDMT function ±5% or at least ±25ms

49) This is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
50) EI = Extremely Inverse, NI = Normal Inverse, VI = Very Inverse, LTI = Long Time Inverse, MI=

Moderately Inverse

Table 69 - Phase overcurrent stage 50/51-2 (50/51)

Input signal IA – IC

Start value 0.10 – 20.00 x ITN (step 0.01)

Definite time function: DT51)

- Operate time 0.04 – 1800.00 s (step 0.01 s)

Start time 35 ms at 2 * Is pick-up value

Reset time < 95 ms

Overshoot time < 50 ms

Reset ratio 0.97

Transient overreach, any τ < 10%

Inaccuracy:
±3% of the set value or 5 mA secondary
- Starting
±1% or ±25 ms
- operate time
51) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.

Table 70 - Phase overcurrent stage 50/51-3 (50/51)

Input signal IA – IC

Start value 0.10–40.00 x ITN (step 0.01)

Definite time function: DT52)

- Operate time 0.03–300.00 s (step 0.01 s)

Instant operate time:

IM / ISET ratio > 1.5 <30 ms

IM / ISET ratio 1.03 – 1.5 < 50 ms

Start time 20 ms at 2 * Is pick-up value

Reset time < 95 ms

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Overshoot time < 50 ms

Reset ratio 0.97

Inaccuracy:

- Starting ±3% of the set value or 5 mA secondary

- Operate time DT (IM/ISET ratio > 1.5) ±1% or ±15 ms

- Operate time DT (IM/ISET ratio 1.03 – 1.5) ±1% or ±25 ms

52) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.

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6.17 Ground fault overcurrent (ANSI 50N/51N)

Description

The purpose of the nondirectional ground fault overcurrent protection is to detect

ground faults in low-impedance grounded networks. In high-impedance grounded
networks, compensated networks and isolated networks, nondirectional ground
fault overcurrent can be used as backup protection.

The nondirectional ground fault overcurrent function is sensitive to the

fundamental frequency component of the ground fault overcurrent 3IN. The
attenuation of the third harmonic is more than 60 dB. Whenever this fundamental
value exceeds the start setting of a particular stage, this stage starts and a start
signal is issued. If the fault situation remains on longer than the operate time
delay setting, a trip signal is issued.

Block diagram

Figure 98 - Block diagram of the ground fault stage overcurrent 50N/51N-1

i0s1

A > ts tr
& I

& J
B t

>1 K

& J

C D E F G H

A. I0 G. Multiplier
B. Block H. Enable events
C. Setting I0>s I. Start
D. Delay J. Register event
E. Definite / inverse time K. Trip
F. Inverse time characteristics

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Figure 99 - Block diagram of the ground fault stages overcurrent 50N/51N-2, 50N/
51N-3, 50N/51N-4

I0ssblock

A > ts tr
& F

& G
B

t
H

& G

C D E

A. I0 E. Enable events
B. Block F. Start
C. Setting I0>>s G. Register event
D. Delay H. Trip

Input signal selection

Each stage can be connected to supervise any of the following inputs and signals:
• Input IN1 for all networks other than solidly grounded.
• Input IN2 for all networks other than solidly grounded.
• Calculated signal IN Calc for solidly and low-impedance grounded networks. IN
Calc = IA + IB + IC.

Four or six independent nondirectional ground fault overcurrent stages

There are four separately adjustable ground fault overcurrent stages: 50N/51N-1,
50N/51N-2, 50N/51N-3, and 50N/51N-4. The first stage 50N/51N-1 can be
configured for definite time (DT) or dependent time operation characteristic
(IDMT). The other stages have definite time operation characteristic. By using the
definite delay type and setting the delay to its minimum, an instantaneous (ANSI
50N) operation is obtained.

Dependent time limitation

The maximum measured secondary ground fault overcurrent is 10 x I0N and the
maximum measured phase current is 50 x IN. This limits the scope of dependent
curves with high start settings.

Setting groups

There are four setting groups available for each stage.

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Characteristics

Table 71 - Ground fault overcurrent 50N/51N-1 (50N/51N)

Input signal IN1, IN2

IN Calc = (IA + IB + IC)

Definite time function: DT53)

- Operate time 0.0453) –300.00 s (step 0.01 s)

IDMT function:

- Delay curve family (DT), IEC, IEEE, RI Prg

- Curve type EI, VI, NI, LTI, MI..., depends on the

- Inv. time coefficient k family54)

0.025–20.0, except

0.50–20.0 for RXIDG, IEEE and IEEE2

Start time 45 ms at 2 * Is pick-up value

Reset time < 95 ms

Reset ratio 0.95

Inaccuracy:

- Starting ±2% of the set value or ±0.3% of the rated

value
- Starting (Peak mode)
±5% of the set value or ±2% of the rated
value (Sine wave <65 Hz)
- Operate time at definite time function
±1% or ±25 ms
- Operate time at IDMT function
±5% or at least ±25 ms 53)
53) This is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
54) EI = Extremely Inverse, NI = Normal Inverse, VI = Very Inverse, LTI = Long Time Inverse, MI=

Moderately Inverse

Table 72 - Ground fault overcurrent 50N/51N-2, 50N/51N-3, 50N/51N-4, 50N/

51N-5 (50N/51N)
Input signal IN1, IN2

IN Calc = (IA + IB + IC)

Definite time function:

- Operate time 0.04 55) – 300.00 s (step 0.01 s)

Start time Typically 45 ms (50N/51N-2, 50N/51N-3,

50N/51N-4)

30 ms at 2 * Is pick-up value (50N/51N-5)

Reset time <95 ms

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Reset ratio 0.95

Inaccuracy:

- Starting ±2% of the set value or ±0.3% of the rated

value
- Starting (Peak mode)
±5% of the set value or ±2% of the rated
value (Sine wave <65 Hz)
- Operate time
±1% or ±25 ms
55) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.

6.17.1 Ground fault phase detection

The ground fault overcurrent stage (ANSI 50N/51N) and directional ground fault
overcurrent stage (ANSI 67N) have an inbuilt detection algorithm to detect a faulty
phase. This algorithm is meant to be used in radial-operated distribution
networks. The faulty phase detection can be used in solidly-grounded,
impedance-grounded or resonant-grounded networks.

Operation

The faulty phase detection starts from the ground fault stage trip. At the moment
of stage start, the phase currents measured prior to start are registered and
stored as prior-to-fault currents. At the moment of trip, phase currents are
registered again. Finally, faulty phase detection algorithm is performed by
comparing prior-to-fault currents to fault currents. The algorithm also uses positive
sequence current and negative sequence current to detect faulty phase.

The detection algorithm can be enabled and disabled by selecting or unselecting

a checkbox in the protection stage settings. Correct network grounding
configuration must be selected in the stage settings, too. In the ground fault
overcurrent stage settings, you can select between RES and CAP network
grounding configuration. This selection has no effect on the protection itself, only
on the faulty phase detection. In the directional ground fault overcurrent stage
settings, the detection algorithm uses the same network grounding type as
selected for protection. RES is used for solidly-grounded, impedance-grounded
and resonant-grounded networks. CAP is only used for isolated networks.

The detected faulty phase is registered in the protection stage fault log (and also
in the event list and alarm screen). Faulty phase is also indicated by a line alarm
and line fault signals in the output matrix.

Possible detections of faulty phases are A-N, B-N, C-N, AB-N, AC-N, BC-N, ABC-
N, and REV. If the relay protection coordination is incorrect, REV indication is
given in case of a relay sympathetic trip to a reverse fault.

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6.18 Capacitor bank unbalance (ANSI 51C)

NOTE: Configure the capacitor bank unbalance protection through the ground
fault overcurrent stages 50N/51N-3 and 50N/51N-4.

Description

The relay enables capacitor, filter and reactor bank protection with its five current
measurement inputs. The fifth input is typically useful for unbalance current
measurement of a double-wye connected ungrounded bank.

The unbalance protection is highly sensitive to internal faults of a bank because of

the sophisticated natural unbalance compensation. The location method enables
easy maintenance monitoring for a bank.

This protection scheme is specially used in double-wye-connected capacitor

banks. The unbalance current is measured with a dedicated current transformer
(like 5A/5A) between two starpoints of the bank.

As the capacitor elements are not identical and have acceptable tolerances, there
is a natural unbalance current between the starpoints of the capacitor banks. This
natural unbalance current can be compensated to tune the protection sensitive
against real faults inside the capacitor banks.

Figure 100 - Typical capacitor bank protection application with Easergy P3 relays
P3x3x_Capbank

8/E/1:1
IA 5A
8/E/1:2
8/E/1:3
IB 5A
8/E/1:4
8/E/1:5
IC 5A
8/E/1:6
8/E/1:7 I01 5A
8/E/1:8
I01 1A
8/E/1:9
8/E/1:10 I02 1A
8/E/1:11
I02 0,2A
8/E/1:12

Compensation method

The method of unbalance protection is to compensate for the natural unbalance

current. The compensation is triggered manually when commissioning. The
phasors of the unbalance current and one phase current are then recorded. This
is because one polarizing measurement is needed. When the phasor of the
unbalance current is always related to IA, the frequency changes or deviations
have no effect on the protection. After the recording, the measured unbalance
current corresponds to the zero-level and therefore, the setting of the stage can
be very sensitive.

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Compensation and location

The most sophisticated method is to use the compensation method described

above with an add-on feature that locates the branch of each faulty element (the
broken fuse).

This feature is implemented to the stage 50N/51N-4, while the other stage 50N/
51N-3 can still function as normal unbalance protection stage with the
compensation method. Normally, the 50N/51N-4 could be set as an alarming
stage while stage 50N/51N-3 trips the circuit breaker.

The stage 50N/51N-4 should be set based on the calculated unbalance current
change of one faulty element. You can calculate this using the following formula:

Equation 19

V L− N V L− N
−
(2 ⋅ π ⋅ f ⋅ C1 ) −1 (2 ⋅ π ⋅ f ⋅ C2 ) −1
3I 0 =
3

C1 = Capacitor unit capacitance (μF)

C2 = Capacitor unit capacitance, after one element fails (μF)

However, the setting must be 10% smaller than the calculated value, since there
are some tolerances in the primary equipment as well as in the relay
measurement circuit. Then, the time setting of 50N/51N-4 is not used for tripping
purposes. The time setting specifies, how long the relay must wait until it is
certain that there is a faulty element in the bank. After this time has elapsed, the
stage 50N/51N-4 makes a new compensation automatically, and the measured
unbalance current for this stage is now zero. Note, the automatic compensation
does not affect the measured unbalance current of stage 50N/51N-3.

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Figure 101 - Natural unbalance compensation and a single capacitor fault

90
3I0

A
180 0

B
270

A. The natural unbalance is compensated for.

B. When the IN current increases above the set start value (normally 90% of a single capacitor
unit) according to the angle ratio between IN and IA, it is decided in which branch and phase the
fault occurred. The fault is memorised and compensation is completed automatically. After the set
amount of faults, the stage trips.

If there is an element failure in the bank, the algorithm checks the phase angle of
the unbalance current related to the phase angle of the phase current IA. Based
on this angle, the algorithm can increase the corresponding faulty elements
counter (there are six counters).

Figure 102 - How a failure in different branches of the bank affects the IN
measurement

Easergy P3 H I
G C
A B

F D
E

A. Branch 1 F. Phase 2 fault in branch 1

B. Branch 2 G. Phase 1 fault in branch 2
C. IA as reference H. Phase 3 fault in branch 1
D. Phase 1 fault in branch 1 I. Phase 2 fault in branch 2
E. Phase 3 fault in branch 2

You can set for the stage 50N/51N-4 the allowed number of faulty elements. For
example, if set to three elements, the fourth fault element will issue the trip signal.

The fault location is used with internal fused capacitor and filter banks. There is
no need to use it with fuseless or external fused capacitor and filter banks, nor
with the reactor banks.

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Application example

An application example is presented below. Each capacitor unit has 12 elements

in parallel and four elements in series.

Figure 103 - 131.43 μF Y-Y connected capacitor bank with internal fuses

12kV A

I B

I0

A. 12 in parallel B. Four in series

Characteristics

Table 73 - Capacitor bank unbalance50N/51N-3 and 50N/51N-4 (51C)

Operate time 0.04‑300 s (step 0.01)

Start time Typically 30 ms

Reset time <95 ms

Reset ratio 0.95

Inaccuracy:

- Starting ±2% of the set value or ±0.3% of the rated

value
- Operate time
±1% or ±25 ms

6.18.1 Taking unbalance protection into use

1. To enable the capacitor bank protection:

– in Easergy Pro, in the Protection > 50N/51N-4 Unbalance setting view,

select Location for Compensation mode.

Figure 104 - Enabling unbalance protection

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– via the Easergy P3 device's front panel: go to the 50N/51N-4 menu, scroll
right to 1 SET 50N/51N, and select Location for CMode.

2. To save the natural unbalance:

– in Easergy Pro, in the Protection > 50N/51N-4 Unbalance setting view,
select Get for Save unbalance current.

Figure 105 - Saving the unbalance current

– via the device's front panel: go to the 50N/51N-4 menu, scroll right to
SET2 50N/51N, and select Get for SaveBal.

NOTE: CMode has to be selected as Location before proceeding to

this step.

3. Set the start value for both branches.

Total capacitance of the bank is 131.43 μF. In each phase, there are three
capacitor units (1+2), so the capacitance of one unit is 43.81 μF. Failure of
one element inside the capacitor unit makes the total capacitance decrease to
41.92 μF (Ohm’s law). This value is important when calculating the start
value.

Equation 20

V L− N V L− N
−
(2 ⋅ π ⋅ f ⋅ C1 ) −1
(2 ⋅ π ⋅ f ⋅ C 2 ) −1
3I 0 =
3
6928 6928
−
(2 ⋅ π ⋅ 50 ⋅ 43.81 ⋅ 10 −6 ) −1 (2 ⋅ π ⋅ 50 ⋅ 43.81 ⋅ 10 −6 ) −1
3I 0 =
3

3I 0 = 1.37 A

Failure of one element inside the bank on the left branch causes
approximately 1.37 ampere unbalance current at the star point. On the right
branch, there are two capacitor units in parallel, and therefore, a failure of one
element causes only 0.69 ampere unbalance. A different start value for each
branch is necessary. Set the start value to 80% of the calculated value.

4. Test the operation of the unbalance protection.

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Figure 106 - Testing the operation of the unbalance protection

0.80

0.60

0.40

0.20

0.00

A. Phase 2 fault in branch 2 C. Set operation delay

B. IA as reference

Conduct testing by injecting current to channels IA and IN1 of the relay. In the
example above, 0.69 A primary current is injected to the IN1 channel. IN1 is
leading the phase current IA by 60 degrees. This means the fault has to be on
the right branch and in phase 2. Compensation happens automatically after
the set operate time until the allowed total amount of failed units is exceeded
(Max. allowed faults). In this application, the fourth failed element would cause
the stage to trip.

NOTE: If branch 1 faults occur in branch 2, change the polarity of the IN

input. Clear the location counters when the commissioning of the relay
has been completed.

5. Clear the location counters by clicking the Clear button.

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Figure 107 - Clearing location counters

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6.19 Overvoltage (ANSI 59)

Description

Overvoltage protection is used to detect too high system voltages or to check that
there is sufficient voltage to authorize a source transfer.

The overvoltage function measures the fundamental frequency component of the

line-to-line voltages regardless of the voltage measurement mode (see 10.8
Voltage system configuration). By using line-to-line voltages any line-to-neutral
over-voltages during ground faults have no effect. (The ground fault protection
functions take care of ground faults.) Whenever any of these three line-to-line
voltages exceeds the start setting of a particular stage, this stage starts and a
start signal is issued. If the fault situation remains on longer than the operate time
delay setting, a trip signal is issued.

In solidly grounded, four-wire networks with loads between phase and neutral
voltages, overvoltage protection may be needed for line-to-neutral voltages, too.
In such applications, the programmable stages can be used. 6.32 Programmable
stages (ANSI 99).

Three independent stages

There are three separately adjustable stages: 59-1, 59-2, and 59-3. All the stages
can be configured for the definite time (DT) operation characteristic.

Configurable release delay

The 59–1 stage has a settable reset delay that enables detecting intermittent
faults. This means that the time counter of the protection function does not reset
immediately after the fault is cleared, but resets after the release delay has
elapsed. If the fault appears again before the release delay time has elapsed, the
delay counter continues from the previous value. This means that the function
eventually trips if faults are occurring often enough.

Configurable hysteresis

The dead band is 3% by default. This means that an overvoltage fault is regarded
as a fault until the voltage drops below 97% of the start setting. In a sensitive
alarm application, a smaller hysteresis is needed. For example, if the start setting
is about only 2% above the normal voltage level, the hysteresis must be less than
2%. Otherwise, the stage does not release after fault.

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Block diagram

Figure 108 - Block diagram of the three-phase overvoltage stages 59-1, 59-2, and
59-3

3vus

VmA
VmB MAX > & G
ts tr
VmC
& H
A

t
I

& H

B C D E F

A. Blocking F. Enable events

B. Setting U>s G. Start
C. Hysteresis H. Event register
D. Release delay I. Trip
E. Delay

Setting groups

There are four setting groups available for each stage.

Characteristics

Table 74 - Overvoltage stage 59–1 (59)

Input signal VA – VC

Start value 50–150% VN (step 1%)

Definite time characteristic:

- operate time 0.0856)– 300.00 s (step 0.02)

Hysteresis 0.99–0.800 (0.1 – 20.0%, step 0.1%)

Start time Typically 60 ms

Release delay 0.06–300.00 s (step 0.02)

Reset time < 95 ms

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Overshoot time < 50 ms

Inaccuracy:

- Starting ±3% of the set value

- operate time ±1% or ±30 ms

56) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.

Table 75 - Overvoltage stage 59–2 (59)

Input signal VA – VC

Start value 50–150% VN (step 1%)

The measurement range is up to 160 V.

This limit is the maximum usable setting
when rated VT secondary is more than 100
V.

Definite time characteristic:

- Operate time 0.0657) – 300.00 s (step 0.02)

Hysteresis 0.99–0.800 (0.1–20.0%, step 0.1%)

Start time Typically 60 ms

Reset time < 95 ms

Overshoot time < 50 ms

Inaccuracy:

- Starting ±3% of the set value

- Operate time ±1% or ±30 ms

57) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.

Table 76 - Overvoltage stage 59–3 (59)

Input signal VA – VC

Start value 50–160% VN (step 1%)

The measurement range is up to 160 V.

This limit is the maximum usable setting
when rated VT secondary is more than 100
V.

Definite time characteristic:

- Operate time 0.0458) – 300.00 s (step 0.01)

Hysteresis 0.99–0.800 (0.1–20.0%, step 0.1%)

Start time Typically 50 ms

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Reset time < 95 ms

Overshoot time < 50 ms

Inaccuracy:

- Starting ±3% of the set value

- Operate time ±1% or ±25 ms

58) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.

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6.20 Neutral overvoltage (ANSI 59N)

Description

The neutral overvoltage protection is used as unselective backup for ground faults
and also for selective ground fault protections for motors having a unit transformer
between the motor and the busbar.

This function is sensitive to the fundamental frequency component of the neutral

overvoltage. The attenuation of the third harmonic is more than 60 dB. This is
essential because third harmonics exist between the neutral point and ground
also when there is no ground fault.

Whenever the measured value exceeds the start setting of a particular stage, this
stage starts and a start signal is issued. If the fault situation remains on longer
than the operate time delay setting, a trip signal is issued.

Measuring the neutral overvoltage

The neutral overvoltage is either measured with three voltage transformers (for
example broken delta connection), one voltage transformer between the motor's
neutral point and ground or calculated from the measured phase-to-neutral
voltages according to the selected voltage measurement mode (see 10.8 Voltage
system configuration):

• When the voltage measurement mode is 3LN: the neutral displacement

voltage is calculated from the line-to-line voltages and therefore a separate
neutral displacement voltage transformer is not needed. The setting values
are relative to the configured voltage transformer (VT) voltage/√3
• When the voltage measurement mode contains "+VN": The neutral
displacement voltage is measured with voltage transformer(s) for example
using a broken delta connection. The setting values are relative to the VTN
secondary voltage defined in configuration.
• Connect the VN signal according to the connection diagram to achieve correct
polarization.

Two independent stages

There are two separately adjustable stages: 59N-1 and 59N-2. Both stages can
be configured for the definite time (DT) operation characteristic.

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Block diagram

Figure 109 - Block diagram of the neutral overvoltage stages 59N-1, 59N-2

U0sblock

A > ts tr
& G

& H
B

t
I

& H

C D E F

A. U0 F. Enable events
B. Blocking G. Start
C. Setting U0>s H. Register event
D. Release delay I. Trip
E. Delay

Setting groups

There are four setting groups available for both stages.

Characteristics

Table 77 - Neutral overvoltage stage 59N-1 (59N)

Input signal VN

VN Calc = (VA + VB + VC)

Start value 1–60% V0N (step 1%)

Definite time function:

- Operate time 0.3–300.0 s (step 0.1 s)

Start time Typically 200 ms

Reset time < 450 ms

Reset ratio 0.97

Inaccuracy:

- Starting ±2% of the set value or ±0.3% of the rated

value
- Starting VN Calc (3LN mode)
±1 V
- Operate time
±1% or ±150 ms

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Table 78 - Neutral overvoltage stage 59N-2 (59N)

Input signal VN

VN Calc = (VA + VB + VC)

Start value 1–60% V0N (step 1%)

Definite time function:

- Operate time 0.08–300.0 s (step 0.02 s)

Start time Typically 60 ms

Reset time <95 ms

Reset ratio 0.97

Inaccuracy:

- Starting ±2% of the set value or ±0.3% of the rated

value
- Starting VN Calc (3LN mode)
±1 V
- Operate time
±1% or ±30 ms

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6.21 Restricted high-impedance ground fault (ANSI 64REF,

64BEF)
The high-impedance REF/BEF protection function is based on an external
connection of a stabilizing resistor and a voltage limiting varistor connection to the
I0 input of Easergy P3 devices. The CT requirement, stabilizing resistor and
voltage limiting varistor calculations are explained in a separate Application Note
(P3APS17016EN).

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6.22 Restricted ground fault (ANSI 64REF)

Description

The restricted ground fault (REF) protection function is used to detect ground
faults in solidly-grounded or impedance-grounded power transformers, grounding
transformers and shunt reactors. REF protection can also be used to protect
rotating machines if the machine’s neutral point is grounded.

A traditional REF protection scheme is based on a high-impedance REF

protection principle. For implementation details, see separate document
“P3APS17016EN Restricted earth fault protection using an I0 input of an Easergy
P3 relay”. Modern REF protection operation is based on a low-impedance
principle that overcomes some drawbacks of the high-impedance REF principle.
Figure 110 to Figure 113 describe the basic low-impedance REF protection
schemes.

Figure 110 - Restricted ground fault protection of a solidly-grounded transformer

A A
B B
C C

A (S2) C (S1) B (S1) A (S1)

B (S2)
C (S2)

IN3 (S2) 64REF

IN3 (S1)

Figure 111 - Restricted ground fault protection of a transformer and neutral point
reactor

A A
B B
C C

A (S2) C (S1) B (S1) A (S1)

B (S2)
C (S2)

I 3 (S2)
N 64REF
I 3 (S1)
N

Figure 112 - Restricted ground fault protection of a shunt reactor

A A
B B
C C

A (S2) C (S1) B (S1) A (S1)

B (S2)
C (S2)

IN3 (S2) 64REF

IN3 (S1)

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Figure 113 - Restricted ground fault protection of a rotating machine

A
B
C

A (S2) C (S1) B (S1) A (S1)

B (S2)
C (S2)

IN3 (S2) 64REF

IN3 (S1)

The REF protection principle has several advantages. It is very selective because
the protection zone is limited between the current transformers that are used for
the REF protection. Because of its selectivity, the REF protection requires no
additional time delay for protection coordination. Therefore, REF protection is
especially suitable for the protection of transformers and rotating machines
against internal ground faults. Because of the differential protection principle, it is
also very sensitive which makes it suitable for detecting faults located near the
neutral point of transformers and rotating machines.

Restricted ground fault protection principle

The REF protection function is based on the differential protection principle and is
sensitive to the fundamental frequency component of the measured currents.
Figure 114 depicts the differential protection principle applied to REF protection.

The protection zone is determined by the location of current transformers. The

direction of currents in REF protection are defined so that currents entering the
protection zone have positive direction and currents leaving the zone have
negative direction.

Figure 114 - Differential protection principle applied to REF protection

A
C C
I B I

64REF
IN Meas IN Calc = IA + IB + IC

A. Protection zone C Positive direction

B Protected object

The function is based on the difference of the current measured at the neutral
point (IN Meas) and the calculated residual current (IN Calc). The function calculates
the differential current ID according to Equation 21. So the function is based on
the absolute value of ID that is a sum of the current vectors IN Meas and IN Calc.

NOTE: Nominal current of the IN Meas and IN Calc are current transformer
ratings.

Equation 21

ID = |IN Meas + IN Calc|

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During healthy conditions, the neutral point current (IN Meas) is near or equal to
zero and the same is true for the residual current or the calculated sum of the
phase currents IN Calc = 3I0 = IA+IB +IC. During healthy conditions, the differential
current ID is also close to zero and the REF protection stage does not start.

Figure 115 depicts through-fault conditions and a fault in the protected zone.

During a through-fault condition, a ground fault current flowing from the faulty
phase to earth returns to the system’s neutral point. Because of the convention of
current directions, the resulting neutral point current (IN Meas) and calculated
residual current (IN Calc) are flowing in opposite directions resulting in zero or very
small differential current ID according to Equation 21.

When a fault occurs inside the protection zone, the neutral point current flowing
into the protection zone has a positive current direction according to the current
direction convention. Depending on the network conditions, an additional fault
current may or may not flow into the zone along the line. This additional fault
current manifests itself as a residual current. Additional fault currents flowing into
the protection zone have a positive current direction, too. In other words, the
neutral point current and residual current are in a phase which results in a high
differential current ID according to Equation 21.

Figure 115 - Through-fault condition (left) and ground fault in protected zone
(right)

A A A A
B B B B
C C C C
INCalc = IA + IB + IC INCalc = IA + IB + IC

IN Meas IN Meas
Id ≈ 0 Id > 0

During a through-fault or short-circuit fault outside the protection zone, the current
transformers may be exposed to very high currents. These high fault currents
may lead to different saturation of the phase current transformers resulting in an
erroneous residual current. To ensure correct operation of the protection stage, a
stabilization method is provided. Protection stage stabilisation is based on the
calculated bias current IB and programmable operating characteristics. The bias
current is calculated according to Equation 22.

Equation 22

|IA|+|IB|+|IC|
IB=
3

This bias current stabilization method is used in the dI0> stage. The dI0>> stage
does not consider the stabilization current IB and is purely based on the
differential current ID. Both the differential current ID and stabilization current IB
are current transformer ratings.

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Figure 116 - Restricted ground fault protection operating characteristics

N
I K

L
D
J
M
E H
F G

A. ID/ IN H. IB / IN
B. 2 x IN I. Single-end-feed limit
C. IN J. ISTART
D. 50% IN K. Maximum setting
E. 5% IN L. Slope 1
F. IN M. Minimum setting
G. 3 x IN N. Slope 2

Additional stabilization can be activated by selecting the directional blocking

feature. When directional blocking is used, the trip command is issued only when
the measured neutral current and calculated residual current are less than ±88°
apart. Normal second harmonic blocking and cold-load blocking can be used to
block the stage via the blocking matrix.

Figure 117 - Block diagram of REF protection stage

A
B
C I & J
D
>
& K

E F G H

A. Block G. Δ I> setting

B. IN3 H. Enable events
C. INCalc I. Diff & bias calculation
D. I’NCalc J. Trip

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E. Reverse blocking K. Register event

F. INCalc / I’NCalc selection

Characteristics

Table 79 - Restricted ground fault overcurrent (64REF)

64-1 64-2

Input signals - -

- Measured ground fault IN3 IN3

overcurrent input
- -
- Calculated ground fault
IN Calc or I’N Calc IN Calc or I’N Calc
overcurrent source

Start value - -

- dIo> 5–50 % of IN 5–50 % of In

Ibias for start of slope 1 0.5 x IN -

Slope 1 5–100 % -

Ibias for start of slope 2 1–3 x IN -

Slope 2 100–200 % -

Directional blocking On/off -

Operate time (ID > 1.2 x < 60 ms -

ISET)

Operate time (ID > 3.5 x < 50 ms < 50 ms

ISET)

Reset time < 95 ms < 95 ms

Reset ratio 0.95 0.95

Inaccuracy of starting ±3% of set value or 0.02 x In ±3 % of the set value or ±0.5
when currents are < 200 mA % of the rated value

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6.23 Directional phase overcurrent (ANSI 67)

Description

The directional phase overcurrent protection can be used for directional short-
circuit protection. Typical applications are:

• Short-circuit protection of two parallel cables or overhead lines in a radial

network.
• Short-circuit protection of a looped network with single feeding point.
• Short-circuit protection of a two-way feeder, which usually supplies loads but
is used in special cases as an incoming feeder.
• Directional ground-fault overcurrent protection in low-impedance grounded
networks. In this case, the relay is recommended to connect for line-to-neutral
(3LN) voltage measurement instead of line-to-line (2LL+U0) voltage
measurement. In low-impedance grounded network, residual voltage U0 may
be too low for reliable measurement. See 10.8 Voltage system configuration.

NOTE: For networks where the maximum possible ground-fault current is

lower than the overcurrent setting value, use the directional ground-fault (67N)
stages.

The directional phase overcurrent function measures the fundamental frequency

component of the phase current. The protection is sensitive to the highest three-
phase current. Whenever this value exceeds the configured start setting and, if
the polarization quantity is within the configured sector setting of a particular
stage, a start signal is issued. If the fault remains on longer than the time defined
by the operation delay setting, a trip signal is issued.

For line-to-line and three-phase faults, the fault direction is determined with
positive-sequence polarization using the angles between the positive sequences
of currents and voltages.

For line-to-neutral faults, the fault direction is determined with cross-polarization

using fault-phase current and a healthy line-to-line voltage.

For details on power direction, see 4.10 Power and current direction.

Voltage memory

An adjustable 0.2...3.2 s cyclic buffer that stores the phase-to-ground voltages is

used as the voltage memory. The stored phase angle information is used as
direction reference if all the line-to-line voltages drop below 1% during a fault. The
voltage memory can be adjusted by setting the Angle memory duration
parameter in the Scalings setting view in Easergy Pro.

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Block diagrams

Figure 118 - Block diagram of directional phase overcurrent stage Iϕ > and Iϕ >>

3vlsblock_Idir>_Idir>>
K

U1 U1
I1 I1

Im1
Im2 MAX > ts tr
& H
Im3
& I
A t

>1 J

& I

B C D E F G

A. Block G. Enable events

B. Setting I>s H. Start
C. Delay I. Register event
D. Definite / dependent time J. Trip
E. Dependent time characteristics K. Directional discrimination by U1/I1 angle
F. Multiplier

Figure 119 - Block diagram of directional phase overcurrent stage Iϕ >>> and Iϕ
>>>>

3vlsblock_Idir>>>_Idir>>>>
K

U1 U1
I1 I1

Im1
Im2 MAX > & H
Im3 ts tr

& I
A

t
J

& I

B C G

A. Block H. Start
B. Setting I>>>s I. Register event
C. Delay J. Trip
G. Enable events K. Directional discrimination by U1/I1 angle

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Operation

The directional phase overcurrent uses positive-sequence polarization methods

for faults that do not involve ground, that is, line-to-line faults and three-phase
faults. For faults that involve ground, the cross-polarization method is used.

The function has two conditions as shown in the block diagram. One is the current
threshold and the other is the fault direction or fault angle. If both conditions are
true, the stage starts and trips after the set trip delay. Whenever the highest three-
phase current exceeds the set value, there is an overcurrent condition.

The directional condition of the fault is different depending on whether ground is

involved in the fault or not.

For faults that do not involve ground, the fault direction or fault angle is
determined as an angle between the positive sequences of current and voltage.
The angle reference for the positive-sequence current is the positive-sequence
voltage that is rotated by the base-angle setting (also called relay characteristics
angle). The actual trip area is ± 88° from the base-angle setting. If the positive-
sequence current vector falls into the trip area, there is a directional condition.

The magnitude of the positive-sequence current has no impact on the overcurrent

condition or the directional condition.

If the current threshold and directional conditions are true, the stage starts and
trips after the set trip delay.

For faults that involve ground, the fault direction or fault angle is determined as an
angle between the healthy line-to-line voltage and the faulted phase current. The
angle reference for the faulted phase current is opposite to the healthy line-to-line
voltage that is rotated by the base-angle setting plus 90° to the positive direction.
The actual trip area is ± 88° from the base angle setting plus 90°. If the fault
current vector falls into the trip area, there is a directional condition. If both
conditions are true, the stage starts and trips after the set trip delay. If the current
threshold and directional conditions are true, the stage starts and trips after the
set trip delay.

A typical characteristic for the directional phase overcurrent protection for line-to-
line faults is shown in Figure 120. The base angle setting is -30°. The stage starts
if the maximum of the three-phase currents exceeds the current threshold and if
the tip of the positive-sequence current phasor gets into the grey area.

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Figure 120 - Example of the directional phase overcurrent protection area for line-
to-line fault

+90°

Reverse Forward

+88°
0°
U1
-88°

Angle offset setting= -30° (RCA)

-90° ldir_angle1

A typical characteristic for the directional phase overcurrent protection for line-to-
ground faults is shown in Figure 121. The base angle setting is -30°. The stage
starts if the maximum of the three-phase currents exceeds the current threshold
and if the tip of the fault current phasor gets into the grey area.

Figure 121 - Example of the directional phase overcurrent protection area for line-
to-ground fault , RCA internally rotated +90o CCW during ground fault

+90°
+60°
Forward

+88°
-88°
0°
U1

Angle offset setting= -30° (RCA)

Reverse

-90° ldir_angle2

Three modes are available:

• directional
• non-directional
• directional + backup

In the non-directional mode, the stage acts like an ordinary overcurrent 50/51
stage.

The directional + backup mode works like the directional mode, but it has non-
directional backup protection that is used if a close-up fault forces all voltages to
about zero. After the angle memory hold time, the direction would be lost.

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The directional + backup mode is required when the operate time is set longer
than the voltage memory setting or no other non-directional backup protection is
used.

In Figure 122, the grey area is the trip area.

Figure 122 - Difference between directional and non-directional mode

+90° +90°
-ind. +cap. -ind. +cap.
2°
DIRECTIONAL NON-DIRECTIONAL

SET SET
VALUE 0° VALUE 0°
-res. +res. -res. +res.
BASE ANGLE= 0°

TRIP AREA TRIP AREA

-cap. +ind. -cap. +ind.

-90° -90°

An example of the bidirectional operation characteristic is shown in Figure 123.

The stage on the right side in this example is stage Iφ> and on the left side Iφ>>.
The base angle setting of Iφ> is 0° and the base angle of Iφ>> is set to -180°.

Figure 123 - Bidirectional application with two stages 67-1 and 67-2

+90°
ind. +cap.
4°
67-2 TRIP AREA

SET SET
VA LUE VA LUE 0°
res. +res.
BASE ANGLE = °

BASE ANGLE = 180°

67-1 TRIP AREA

cap. +ind.

90° ldir_modeBiDir 15%

When any of the three-phase currents exceeds the setting value and, in
directional mode, the phase angle including the base angle is within the active
±88° wide sector, the stage starts and issues a start signal. If this fault remains on
longer than the time defined by the delay setting, a trip signal is issued.

Four independent stages

There are four separately adjustable stages available: 67-1, 67-2, 67-3, and 67-4.

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Dependent operate time

Stages 67-1 and 67-2 can be configured for definite time (DT) or dependent time
characteristic. See 6.6 Dependent operate time for details on the available
dependent delays.

Stages 67-3 and 67-4 have definite time operation delay. The relay shows a
scaleable graph of the configured delay on the local panel display.

Dependent time limitation

The maximum measured secondary current is 50 x IN. This limits the scope of
dependent curves with high start settings. See 6.6 Dependent operate time for
more information.

Cold load and inrush current handling

See 7.3 Cold load start and magnetizing inrush.

Setting groups

There are four setting groups available for each stage.

Characteristics

Table 80 - Directional phase overcurrent 67-1, 67-2 (67)

Characteristic Value

Input signal IA – IC

VA – V C

Start value 0.10...4.00 xIN or x IMOT (step 0.01)

Mode Directional/Directional+BackUp

Minimum voltage for the direction solving 2 VSECONDARY

Base angle setting range -180°...+179°

Operate angle ±88°

Definite time function: DT59)

- Operate time 0.04...300.00 s (step 0.01)

IDMT function:

- Delay curve family (DT), IEC, IEEE, RI Prg

- Curve type EI, VI, NI, LTI, MI…depends on the

- Inv. time coefficient k family60)

0.025...20.0, except

0.50...20.0 for RXIDG, IEEE and IEEE2

Start time Typically 30 ms

Reset time <95 ms

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Characteristic Value

Overshoot time <50 ms

Reset ratio 0.95

Reset ratio (angle) 2°

Transient overreach, any τ <10%

Angle memory duration 0.2...3.2 s

Inaccuracy:

- Starting (rated value IN= 1...5 A) ±3% of the set value or ±0.5% of the rated
value
- Angle
±2° V>5 V

±30° V = 0.1...5.0 V
- Operate time at DT function ±1% or ±25 ms
- Operate time at IDMT function ±5% or at least ±30 ms59)
59) This is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
60) EI = Extremely Inverse, NI = Normal Inverse, VI = Very Inverse, LTI = Long Time Inverse, MI=

Moderately Inverse

Table 81 - Directional phase overcurrent 67–3, 67–4 (67)

Characteristic Value

Input signal IA – IC

Va – VC

Start value 0.10...20.00 x IMODE (step 0.01)

Mode Directional/Directional+BackUp

Minimum voltage for the direction solving 2 VSECONDARY

Base angle setting range -180°...+179°

Operate angle ±88°

Definite time function: DT61)

- Operate time 0.04...300.00 s (step 0.01)

Start time Typically 30 ms

Reset time <95 ms

Overshoot time <50 ms

Reset ratio 0.95

Reset ratio (angle) 2°

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Characteristic Value

Transient overreach, any τ <10%

Angle memory duration 0.2...3.2 s

Inaccuracy:

- Starting (rated value IN= 1...5 A) ±3% of the set value or ±0.5% of the rated
value
- Angle
±2° V>5 V

±30° V = 0.1...5.0 V
- Operate time at DT function ±1% or ±25 ms
61) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.

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6.24 Directional ground fault overcurrent (ANSI 67N)

Description

The directional ground fault overcurrent is used in networks or motors where a

selective and sensitive ground fault protection is needed and in applications with
varying network structure and length.

The ground fault protection is adapted for various network ground systems.

The function is sensitive to the fundamental frequency component of the ground

fault overcurrent and neutral voltage displacement voltage and the phase angle
between them. The attenuation of the third harmonic is more than 60 dB.
Whenever the size of IN and VN and the phase angle between IN and VN fulfils the
start criteria, the stage starts and a start signal is issued. If the fault situation
remains on longer than the operate time delay setting, a trip signal is issued.

Polarization

The neutral overvoltage, used for polarization, is measured by energizing input

VN, that is, the angle reference for IN. Connect the VN signal according to the
connection diagram. Alternatively, the VN can be calculated from the line-to-line
voltages internally depending on the selected voltage measurement mode (see
10.8 Voltage system configuration):

• 3LN/LLY, 3LN/LNY and 3LN/VN: the zero sequence voltage is calculated from
the line-to-line voltages and therefore any separate zero sequence voltage
transformers are not needed. The setting values are relative to the configured
voltage transformer (VT) voltage/√3.
• 3LN+VN, 2LL+VN, 2LL+VN+LLy, 2LL+VN+LNy, LL+VN+LLy+LLz, and LN+VN
+LNy+LNz: the neutral overvoltage is measured with voltage transformer(s)
for example using a broken delta connection. The setting values are relative
to the VTN secondary voltage defined in the configuration.
• 3LN: the zero sequence voltage is calculated from the line-to-line voltages
and therefore any separate zero sequence voltage transformers are not
needed. The setting values are relative to the configured voltage transformer
(VT) voltage/√3.
• 3LN+VN and 2LL+VN: the zero sequence voltage is measured with voltage
transformer(s) for example using a broken delta connection. The setting
values are relative to the VTN secondary voltage defined in configuration.

Modes for different network types

The available modes are:

• ResCap

This mode consists of two sub modes, Res and Cap. A digital signal can be
used to dynamically switch between these two submodes. When the digital
input is active (DI = 1), Cap mode is in use and when the digital input is
inactive (DI = 0), Res mode is in use. This feature can be used with
compensated networks when the Petersen coil is temporarily switched off.
◦ Res

The stage is sensitive to the resistive component of the selected IN signal.

This mode is used with compensated networks (resonant grounding) and
networks grounded with a high resistance. Compensation is usually

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done with a Petersen coil between the neutral point of the main
transformer and ground. In this context, high resistance means that the
fault current is limited to be less than the rated phase current. The trip
area is a half plane as drawn in Figure 126. The base angle is usually set
to zero degrees.
◦ Cap

The stage is sensitive to the capacitive component of the selected IN

signal. This mode is used with ungrounded networks. The trip area is a
half plane as drawn in Figure 126. The base angle is usually set to zero
degrees.
• Sector

This mode is used with networks grounded with a small resistance. In this
context, "small" means that a fault current may be more than the rated phase
currents. The trip area has a shape of a sector as drawn in Figure 127. The
base angle is usually set to zero degrees or slightly on the lagging inductive
side (negative angle).
• Undir

This mode makes the stage equal to the non directional stage 50N/51N-1.
The phase angle and VN amplitude setting are discarded. Only the amplitude
of the selected IN input is supervised.

Input signal selection

Each stage can be connected to supervise any of the following inputs and signals:

• Input IN1 for all networks other than solidly grounded.

• Input IN2 for all networks other than solidly grounded.
• Calculated signal IN Calc for solidly and low-impedance grounded networks. IN
Calc = IA + IB + IC = 3IN.

Intermittent ground fault detection

Short ground faults make the protection start but does not cause a trip. A short
fault means one cycle or more. For shorter than 1 ms transient type of intermittent
ground faults in compensated networks, there is a dedicated stage I0INT> 67NI.
When starting happens often enough, such intermittent faults can be cleared
using the intermittent time setting.

When a new start happens within the set intermittent time, the operation delay
counter is not cleared between adjacent faults and finally the stage trips.

Two independent stages

There are two separately adjustable stages: 67N-1 and 67N-2. Both stages can
be configured for definite time delay (DT) or dependent time delay operate time.

Dependent operate time

Accomplished dependent delays are available for all stages 67N-1 and 67N-2.

The relay shows a scalable graph of the configured delay on the local panel
display.

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Dependent time limitation

The maximum measured secondary ground fault overcurrent is 10 x I0N and the
maximum measured phase current is 50 x IN. This limits the scope of dependent
curves with high start settings.

Block diagram

Figure 125 - Block diagram of the directional ground fault overcurrent stages
67N-1, 67N-2

I0fiisblock

A Isinφ
Icosφ
> & I

& J
B

C K
> t

& J

D E F G H

A. I0 G. Delay
B. Block H. Enable events
C. V0 I. Start
D. Choise Icosφ (Res) / Isinφ (Cap) J. Register event
E. Setting Iφ > s K. Trip
F. Setting I0 > s

Figure 126 - Operation characteristics of the directional ground fault protection in

Res and Cap mode
Iosin φ

67N-1
I0

Iocos φ
-V0
67N-1

Res mode can be used with compensated networks. Cap mode is used with ungrounded networks.

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Figure 127 - Operation characteristics examples of the directional ground fault

stages in the sector mode
+90º +90º
Angle offset = -15º +55º Angle offset = +32º
Sector = ±70º Sector = ±120º

I0
TRIP AREA +152º +32º

I0φ> 120º
70º 0º 0º
-V0 120º -V0
70º I0φ>
-15º
I0
TRIP AREA

-85º -88º
IoDir_SectorAdj

The drawn IN phasor is inside the trip area. The angle offset and half sector size are user’s
parameters.

Setting groups

There are four setting groups available for each stage.

Characteristics

Table 82 - Directional ground fault overcurrent 67N-1, 67N-2 (67N)

Input signal IN, VN

IN Calc = ( IA + IB + IC)

Start voltage 1–100% V0N (step 1%)

Mode Non-directional/Sector/ResCap

Base angle setting range -180°–179°

Operate angle ±88°

Definite time function:

- Operate time 0.1062) – 300.00 s (step 0.02 s)

IDMT function:

- Delay curve family (DT), IEC, IEEE, RI Prg

- Curve type EI, VI, NI, LTI, MI…, depends on the

- Inv. time coefficient k family63)

0.025–20.0, except

0.50–20.0 for RI, IEEE and IEEE2

Start time Typically 60 ms

Reset time < 95 ms

Reset ratio 0.95

Reset ratio (angle) 2°

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Inaccuracy:

- Starting VN & IN (rated value IN= 1–5A) ±3% of the set value or ±0.3% of the rated
value

- Starting VN & IN (Peak Mode when, rated ±5% of the set value or ±2% of the rated
value I0n= 1–10A) value (Sine wave <65 Hz)

- Starting VN & IN (IN Calc) ±3% of the set value or ±0.5% of the rated
value

- Angle ±2° when V> 1V and IN> 5% of I0N or > 50

mA

else ±20°

- Operate time at definite time function ±1% or ±30 ms

- Operate time at IDMT function ±5% or at least ±30 ms62)

62) This is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
63) EI = Extremely Inverse, NI = Normal Inverse, VI = Very Inverse, LTI = Long Time Inverse, MI=

Moderately Inverse

Table 83 - Directional ground fault overcurrent 67N-3 (67N)

Input signal IN, VN

IN Calc = ( IA + IB + IC)

Start voltage 1–100% V0N (step 1%)

Mode Non-directional/Sector/ResCap

Base angle setting range -180° – 179°

Operation angle ±88°

Definite time function:

- Operate time 0.1064)– 300.00 s (step 0.02 s)

IDMT function:

- Delay curve family (DT), IEC, IEEE, RI Prg

- Curve type EI, VI, NI, LTI, MI…, depends on the

- Inv. time coefficient k family65)

0.05–20.0, except

0.50–20.0 for RI, IEEE and IEEE2

Start time Typically 60 ms

Reset time < 95 ms

Reset ratio 0.95

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Reset ratio (angle) 2°

Inaccuracy:

- Starting VN & IN (rated value In= 1 – 5A) ±3% of the set value or ±0.3% of the rated
value

- Starting VN & IN (Peak Mode when, rated ±5% of the set value or ±2% of the rated
value I0n= 1 – 10A) value (Sine wave <65 Hz)

- Starting VN & IN (IN Calc) ±3% of the set value or ±0.5% of the rated
value

- Angle ±2° when V> 1V and IN> 5% of I0N or > 50

mA

else ±20°

- Operate time at definite time function ±1% or ±30 ms

- Operate time at IDMT function ±5% or at least ±30 ms64)

64) This is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
65) EI = Extremely Inverse, NI = Normal Inverse, VI = Very Inverse, LTI = Long Time Inverse, MI=

Moderately Inverse

6.24.1 Ground fault phase detection

The ground fault overcurrent stage (ANSI 50N/51N) and directional ground fault
overcurrent stage (ANSI 67N) have an inbuilt detection algorithm to detect a faulty
phase. This algorithm is meant to be used in radial-operated distribution
networks. The faulty phase detection can be used in solidly-grounded,
impedance-grounded or resonant-grounded networks.

Operation

The faulty phase detection starts from the ground fault stage trip. At the moment
of stage start, the phase currents measured prior to start are registered and
stored as prior-to-fault currents. At the moment of trip, phase currents are
registered again. Finally, faulty phase detection algorithm is performed by
comparing prior-to-fault currents to fault currents. The algorithm also uses positive
sequence current and negative sequence current to detect faulty phase.

The detection algorithm can be enabled and disabled by selecting or unselecting

a checkbox in the protection stage settings. Correct network grounding
configuration must be selected in the stage settings, too. In the ground fault
overcurrent stage settings, you can select between RES and CAP network
grounding configuration. This selection has no effect on the protection itself, only
on the faulty phase detection. In the directional ground fault overcurrent stage
settings, the detection algorithm uses the same network grounding type as
selected for protection. RES is used for solidly-grounded, impedance-grounded
and resonant-grounded networks. CAP is only used for isolated networks.

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The detected faulty phase is registered in the protection stage fault log (and also
in the event list and alarm screen). Faulty phase is also indicated by a line alarm
and line fault signals in the output matrix.

Possible detections of faulty phases are A-N, B-N, C-N, AB-N, AC-N, BC-N, ABC-
N, and REV. If the relay protection coordination is incorrect, REV indication is
given in case of a relay sympathetic trip to a reverse fault.

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6.25 Second harmonic inrush detection (ANSI 68F2)

Description

This stage can be used to block other stages and to indicate possible primary
faults in the power distribution network. The ratio between the second harmonic
component and the fundamental frequency component is measured on all the
phase currents. When the ratio in any phase exceeds the setting value, the stage
gives a start signal. After a settable delay, the stage gives a trip signal.

The start and trip signals can be used for blocking the other stages.

The trip delay is irrelevant if only the start signal is used for blocking.

The trip delay of the stages to be blocked must be more than 60 ms to ensure a
proper blocking.

Block diagram

Figure 128 - Block diagram of the second harmonic inrush detection stage

2ndHarm

Im1
Im2 MAX > & E
Im3 ts tr

& F
A

t
G

& F

B C D

A. Block E. Start
B. Setting 2nd harmonics F. Register event
C. Delay G. Trip
D. Enable events

Characteristics

Table 84 - Second harmonic inrush detection (68F2)

Current input IL or I’L

Input signal IA – IC

Settings:

- Start value 10–100 % (step 1%)

- Operate time 0.03–300.00 s (step 0.01 s)

Inaccuracy:

- Starting ±1% - unit

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NOTE: The amplitude of second harmonic content has to be at least 2% of

the nominal of CT. If the nominal current is 5 A, the 100 Hz component needs
to exceed 100 mA.

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6.26 Fifth harmonic detection (ANSI 68H5)

Description

Overexcitation of a transformer creates odd harmonics. The fifth harmonic

detection stage can be used detect overexcitation. This stage can also be used to
block some other stages.

The ratio between the fifth harmonic component and the fundamental frequency
component is measured on all the phase currents. When the ratio in any phase
exceeds the setting value, the stage activates a start signal. After a settable delay,
the stage operates and activates a trip signal.

The trip delay of the stages to be blocked must be more than 60 ms to ensure a
proper blocking.

Characteristics

Table 85 - Fifth harmonic detection (68H5)

Current input IL or I’L

Input signal IA – IC

Settings:

- Setting range over exicitation 10–100% (step 1%)

- Operate time 0.03–300.00 s (step 0.01 s)

Inaccuracy:

- Starting ±2%- unit

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6.27 Overfrequency and underfrequency (ANSI 81)

Description

Frequency protection is used for load sharing and shedding, loss of power system
detection and as a backup protection for overspeeding.

The frequency function measures the frequency from the two first voltage inputs.
At least one of these two inputs must have a voltage connected to be able to
measure the frequency. Whenever the frequency crosses the start setting of a
particular stage, this stage starts, and a start signal is issued. If the fault remains
on longer than the operating delay setting, a trip signal is issued. For situations
where no voltage is present, an adapted frequency is used.

Protection mode for 81–1 and 81–2 stages

These two stages can be configured either for overfrequency or for

underfrequency.

Undervoltage self-blocking of underfrequency stages

The underfrequency stages are blocked when the biggest of the three line-to-line
voltages is below the low-voltage block limit setting. With this common setting,
LVBlk, all stages in underfrequency mode are blocked when the voltage drops
below the given limit. The idea is to avoid purposeless alarms when the voltage is
off.

Initial self-blocking of underfrequency stages

When the biggest of the three line-to-line voltages has been below the block limit,
the underfrequency stages are blocked until the start setting has been reached.

Five independent frequency stages

There are five separately adjustable frequency stages: 81–1, 81–2, 81U–1,
81U-2, 81U-3. The two first stages can be configured for either overfrequency or
underfrequency usage. So totally five underfrequency stages can be in use
simultaneously. Using the programmable stages even more can be implemented
(chapter 6.32 Programmable stages (ANSI 99)). All the stages have definite
operate time delay (DT).

Setting groups

There are four setting groups available for each stage.

Characteristics

Table 86 - Overfrequency and underfrequency 81–1, 81–2 (81H/81L)

Input signal VA – VC

Frequency measuring area 16.0–75.0 Hz

Current and voltage meas. range 45.0–65.0 Hz

Frequency stage setting range 40.0–70.0 Hz (step 0.01)

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Low-voltage blocking 10–100% Vn

Definite time function:

-Operate time 0.0866) – 300.0 s (step 0.02 s)

Start time (overfrequency) < 100 ms

Start time (underfrequency) < 80 ms (slope change)

Reset time <120 ms

Reset ratio (LV block) Instant (no hysteresis)

Inaccuracy:

- Starting ±20 mHz

- Starting (LV block) 3% of the set value or ±0.5 V

- operate time ±1% or ±30 ms

66) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.

NOTE: If the relay restarts for some reason, there is no trip even if the
frequency is below the set limit during the start-up (Start and trip is blocked).
To cancel this block, frequency has to rise above the set limit.
Table 87 - Underfrequency 81U–1, 81U–2, 81U–3 (81L)

Input signal VA – Vc

Frequency measuring area 16.0–75.0 Hz

Current and voltage meas. range 45.0–65.0 Hz

Frequency stage setting range 40.0–64.0 Hz

Low-voltage blocking 10–100% Vn

Definite time function:

- operate time 0.0867) – 300.0 s (step 0.02 s)

Undervoltage blocking 2–100 %

Start time < 80 ms (slope change)

Reset time < 120 ms

Reset ratio 1.002

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Reset ratio (LV block) Instant (no hysteresis)

Inaccuracy:

- Starting ±20 mHz

- starting (LV block) 3% of the set value or ±0.5 V

- operate time ±1% or ±30 ms

67) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.

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6.28 Rate of change of frequency (ANSI 81R)

Description

The rate of change of frequency (ROCOF or df/dt) function is used for fast load
shedding, to speed up operate time in overfrequency and underfrequency
situations and to detect loss of grid. For example, a centralized dedicated load
shedding relay can be omitted and replaced with distributed load shedding, if all
outgoing feeders are equipped with Easergy P3 relays.

NOTE: Use ROCOF for load shedding only. Do not use it for loss of mains
detection.

Frequency behavior during load switching

Load switching and fault situations may generate change in frequency. A load
drop may increase the frequency and increasing load may decrease the
frequency, at least for a while. The frequency may also oscillate after the initial
change. After a while, the control system of any local generator may drive the
frequency back to the original value. However, in case of a heavy short-circuit
fault or if the new load exceeds the generating capacity, the average frequency
keeps on decreasing.

Figure 129 - An example of definite time df/dt operate time. At 0.6 s, which is the
delay setting, the average slope exceeds the setting 0.5 Hz/s and a trip signal is
generated.

FREQUENCY ROCOF1_v3

(Hz)

Settings:
df/dt = 0.5 Hz/s
1. t = 0.60 s
0
Hz 0.5
/s Hz tMin = 0.60 s
/s
0.7
2.0

5H
H

z/s TIME
z/s

(s)

START
TRIP

ROCOF implementation

The ROCOF function is sensitive to the absolute average value of the time
derivate of the measured frequency |df/dt|. Whenever the measured frequency
slope |df/dt| exceeds the setting value for 80 ms time, the ROCOF stage starts
and issues a start signal after an additional 60 ms delay. If the average |df/dt|,
since the start moment, still exceeds the setting, when the operation delay has
elapsed, a trip signal is issued. In this definite time mode the second delay
parameter "minimum delay, tMIN" must be equal to the operation delay parameter
"t".

If the frequency is stable for about 80 ms and the time t has already elapsed
without a trip, the stage resets.

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ROCOF and overfrequency and underfrequency stages

One difference between the overfrequency and underfrequency and the df/dt
function is the speed. Often a df/dt function can predict an overfrequency or
underfrequency situation and is thus faster than a simple overfrequency or
underfrequency function. However, in most cases, standard overfrequency and
underfrequency stages must be used together with ROCOF to ensure tripping
also if the frequency drift is slower than the slope setting of ROCOF.

Definite operate time characteristics

Figure 129 shows an example where the df/dt start value is 0.5 Hz/s and the
delay settings are t = 0.60 s and tMIN = 0.60 s. Equal times t = tMIN gives a definite
time delay characteristic. Although the frequency slope fluctuates, the stage does
not release but continues to calculate the average slope since the initial start. At
the defined operate time, t = 0.6 s, the average slope is 0.75 Hz/s. This exceeds
the setting, and the stage trips.

At slope settings less than 0.7 Hz/s, the fastest possible operate time is limited
according to the Figure 130.

Figure 130 - At very sensitive slope settings the fastest possible operate time is
limited.

ROCOF5_v3
Fastest possible operation time setting (s)

Slope setting df/dt (Hz/s)

Dependent operate time characteristics

By setting the second delay parameter tMIN smaller than the operate time delay t,
a dependent type of operate time characteristic is achieved.

Figure 132 shows one example, where the frequency behavior is the same as in
the first figure, but the tMIN setting is 0.15 s instead of being equal to t. The
operate time depends on the measured average slope according to the following
equation:

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Equation 23

s SET ⋅ t SET
t TRIP =
s

tTRIP = Resulting operate time (seconds).

sSET = df/dt i.e. slope setting (hertz/seconds).

tSET = Operate time setting t (seconds).

s = Measured average frequency slope (hertz/seconds).

The minimum operate time is always limited by the setting parameter tMIN. In the
example, the fastest operate time, 0.15 s, is achieved when the slope is 2 Hz/s or
more. The leftmost curve in Figure 131 shows the dependent characteristics with
the same settings as in Figure 132.

Figure 131 - Three examples of possible dependent df/dt operate time

characteristics. The slope and operation delay settings define the knee points on
the left. A common setting for tMin has been used in these three examples. This
minimum delay parameter defines the knee point positions on the right.

Slope and delay settings

0.5 Hz/s 1 Hz/s 1.5 Hz/s

ROCOF6_v3
Operation time (s)

Setting for minimum delay

tMin= 0.15 s

Measured slope |df/dt| (Hz/s)

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Figure 132 - An example of dependent df/dt operate time. The time to trip will be
0.3 s, although the setting is 0.6 s, because the average slope 1 Hz/s is steeper
than the setting value 0.5 Hz/s.

FREQUENCY ROCOF3_v3

(Hz)

50.0 Settings:
df/dt = 0.5 Hz/s
t = 0.60 s

1.
0
0.5 tMin = 0.15s

H
Hz

z/
/s

s
0.7

2.0
5 Hz

Hz/
/s TIME
49.7

s
(s)
0.00 0.15 0.30 0.45 0.60

START
TRIP

Settings groups

There are four setting groups available.

Characteristics

Table 88 - Rate of change of frequency 81R (81R)

Start setting df/dt 0.2–10.0 Hz/s (step 0.1 Hz/s)

Definite time delay (t> and tMin> are equal):

- Operate time t> 0.1468) – 10.00 s (step 0.02 s)

Dependent time delay (t> is more than

tMin>):
0.1468) – 10.00 s (step 0.02 s)
- Minimum operate time tMin>

Start time Typically 140 ms

Reset time 150 ms

Overshoot time < 90 ms

Reset ratio 1

Inaccuracy:

- Starting 10% of set value or ±0.1 Hz/s

- Operate time(overshoot ≥ 0.2 Hz/s) ±35 ms, when area is 0.2 – 1.0 Hz/s
68) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.

NOTE: ROCOF stage is using the same low voltage blocking limit as the
frequency stages.

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6.29 Lockout (ANSI 86)

Description

The lockout feature, also called latching, can be programmed for outputs in the
Output matrix setting view. Any protection stage start or trip, digital input, logic
output, alarm and GOOSE signal connected to the following outputs can be
latched when required:

• output contacts T1 – T7, A1

• LEDs on the front panel
• virtual outputs VO1- VO20

Figure 133 - The lockout programmed for LED A and 50/51-2 trip signals

In Figure 133, the latched signal is identified with a dot and circle in the matrix
signal line crossing.

The lockout can be released through the display or via the Easergy Pro. See
Chapter 4 Control functions.

Storing latch states

In the General > Release latches setting view, select the Store latch state
setting to configure latched states of relay outputs, virtual outputs, binary outputs
(BO) and high-speed outputs (HSO) to be stored. If some of these outputs are
latched and in “on” state, and the device is restarted, their status is set back to
“on” after restart.

Figure 134 - Store latch setting view

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In the LED configuration setting view, you can configure the latched states of
LEDs to be stored after a restart. In this example, storing has been configured for
LED A (green).

Figure 135 - LED configuration example

NOTE: To use the Store setting, Latch must also be selected.

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6.30 Differential overcurrent protection (ANSI 87T)

Description

The differential overcurrent protection comprises of two separately adjustable

stages: 87-1 and 87-2.

The differential protection is based on the winding currents' difference between I-1
and I-2 side. In transformer applications, the current calculation depends on
transformer connection group. For example, in a Yy0 connection, the measured
currents are also winding currents, see Figure 136.

Figure 136 - Winding currents in connection group Yy0

WindingCurrent1

IA winding I’A winding

IB winding I’B winding

IC winding I’C winding

IA IB IC I’C I’B I’A

In the second example, if the transformer IL side is connected to open delta for
example Dy11, then the winding currents are calculated on the delta side (IL
side), see Figure 137.

Figure 137 - Winding currents in connection group Dy11

WindingCurrent2

IA winding I’A winding

IB winding I’B winding

IC winding I’C winding

IA IB IC I’C I’B I’A

Equation 24 - Winding current calculation in delta side, Dy11 connection

(
IAW = IA − IB )
3

(
IBW = IB − IC )
3

(
ICW = IC − IA )
3

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Equation 25 - Winding currents in star side, Dy11 connection

I ' AW = I ' A
I' BW = I' B
I ' CW = I ' C

Equation 26 - Bias current

IW + I ' W
Ib =
2

Equation 27 - Differential current

I d = IW + I ' W

Bias current calculation is only used in protection stage 87–1>. Bias current
describes the average current flow in the transformer. Bias and differential
currents are calculated individually for each phase.

If the transformer is grounded, for example having the connection group Dyn11,
then zero current must be compensated before differential and bias current
calculation. Zero current compensation can be selected individually for the IL and
I’L side.

Table 89 describes the connection group and zero current compensation for
different connection groups. If the protection area is only generator, then the
connection group setting is always Yy0, see Table 89. Also the settings of Vn and
V’n are set to be the same, for example generator nominal voltage.

Table 89 - Zero-current compensation in transformer applications

Transformator Relay setting

Connection ConnGrp Io cmps I'o cmps

group

YNy0 Yy0 ON OFF

YNyn0 Yy0 ON ON

Yy0 Yy0 OFF OFF

Yyn0 Yy0 OFF ON

YNy6 Yy6 ON OFF

YNyn6 Yy6 ON ON

Yy6 Yy6 OFF OFF

Yyn6 Yy6 OFF ON

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Transformator Relay setting

Connection ConnGrp Io cmps I'o cmps

group

Yd1 Yd1 OFF OFF

YNd1 Yd1 ON OFF

Yd5 Yd5 OFF OFF

YNd5 Yd5 ON OFF

Yd7 Yd7 OFF OFF

YNd7 Yd7 ON OFF

Yd11 Yd11 OFF OFF

YNd11 Yd11 ON OFF

Dy1 Dy1 OFF OFF

Dyn1 Dy1 OFF ON

Dy5 Dy5 OFF OFF

Dyn5 Dy5 OFF ON

Dy7 Dy7 OFF OFF

Dyn7 Dy7 OFF ON

Dy11 Dy11 OFF OFF

Dyn11 Dy11 OFF ON

NOTE: Connect the high-voltage side currents to IL terminals.

Table 90 - Zero-current compensation in generator applications

Genarator only Relay setting

ConnGrp Io cmps I'o cmps

No grounding Yy0 OFF OFF

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Figure 138 - Block diagram of the differential overcurrent stage ΔI>

difflslohko

IL1
IL2 H I M >1 & N
IL3

I'L1
I'L2 H J M
I'L3
& O
K M

L >
>

A B C D E F G

A. Conngrp setting I. I0 compensation

B. I0 cmps J. I’0 compensation
C. I’0 cmps K. 2nd harmonics / Fund
D. 5th harmonics setting L. 5th harmonics / Fund
E. 2nd harmonics setting M. Diff & bias calculation
F. Δ I> setting N. Trip
G. Enable events O. Register event
H. Y/D

The stage ΔI> can be configured to operate as shown in Figure 139. This dual
slope characteristic allows more differential current at higher currents before
tripping.

Figure 139 - Example of differential overcurrent characteristics

A
M
B

N
K

J L
0.5

C 0.1
H
D E F G

A. ID/ITN H. IBIAS
B. Minimum trip area I. Maximum setting
C. ISTART J. Slope 1

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D. 0.5 x IN / IBIAS1 K. Slope 2

E. IN L. Minimum setting
F. IBIAS2 M. Default setting
G. 3 x IN N. Setting area

Table 91 - Settings

Parameter Value Default

IStart 5...50% IN 0.25

Slope 1 5...100% 50%

IBIAS2 1.00...3.00 x IN 2.00

Slope 2 100...200% 150%

The stage also includes second harmonic blocking. The second harmonic is
calculated from differential currents. Harmonic ratio is:

100 x If2_Winding / If1_Winding [%].

The fast differential overcurrent stage 87–1 does not include slope characteristics
or second harmonics blocking.

Current transformer supervision

The current transformer supervision (CTS) feature is used to detect a failure of

one or more of the phase current inputs to the relay. Failure of a phase current
transformer (CT) or an open circuit of the interconnecting wiring can result in
incorrect operation of any current-operated element. Additionally, interruption in
the current circuit generates dangerous CT secondary voltages.

Figure 140 - Current transformer supervision settings

The differential CTS method uses the ratio between positive and negative
sequence currents at both sides of the protected transformer to determine a CT
failure. This algorithm is inbuilt in the dI> stage. When this ratio is small (zero),
one of the following four conditions is present:

• The system is unloaded – both I2 and I1 are zero.

• The system is loaded but balanced – I2 is zero.
• The system has a three-phase fault – I2 is zero.
• There is a three-phase CT failure – unlikely to happen.

When the ratio is non-zero, one of the following two conditions is present:

• The system has an asymmetric fault – both I2 and I1 are non-zero.

• There is a 1 or 2 phase CT fault – both I2 and I1 are non-zero.

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The I2 to I1 ratio is calculated at both sides of the protected transformer. With this
information, we can assume that:

• If the ratio is non-zero at both sides, there is a real fault in the network and the
CTS should not operate.
• If the ratio is non-zero only at one side, there is a change of CT failure and the
CTS should operate.

Another criterion for CTS is to check whether the differential system is loaded or
not. For this purpose, the positive sequence current I1 is checked at both sides of
the protected transformer.

If load current is detected only at one side, it is assumed that there is an internal
fault condition and CTS is prevented from operating, but if load current is detected
at both line ends, CTS operation is permitted.

Another criterion for CTS is to check whether the differential system is loaded or
not. For this purpose, the positive sequence current I1 is checked at both ends. If
load current is detected only at one end, it is assumed that there is an internal
fault condition and CTS is prevented from operating, but if load current is detected
at both line ends, CTS operation is permitted.

There are three modes of operation:

• indication mode: CTS alarm is raised but there is no effect on tripping

• restrain mode: an alarm is raised and the differential current percentage
setting value increased by 100 (for example 30 % + 100 % = 130 %). The new
value is theoretically the maximum amount of differential current that a CT
failure can produce in a normal full-load condition.
• block mode: an alarm is raised and differential protection is prevented from
tripping

The differential CTS block mode is not recommended for two reasons:

• If there is a real fault during a CT failure, the differential protection would not
protect the line at all.
• Blocking the protection could slow down the operate time of the differential
protection because of transients in the beginning of the fault on the protected
line.

Setting groups

This stage has one setting group.

Characteristics

Table 92 - Differential overcurrent stage 87T-1

Start value 5–50 % IN

Bias current for start of slope 1 0.50 x IN

Slope 1 5–100 %

Bias current for start of slope 2 1.00–3.00 x IN

Slope 2 100–200 %

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Second harmonic blocking 5–30 %, or disable

Fifth harmonic blocking 20–50 %, or disable

Reset time < 95 ms

Reset ratio 0.95

Inaccuracy:

- Second harmonic blocking ±2% - unit

- Fifth harmonic blocking ±3% - unit

- Starting ±3% of set value or 0.02 x IN when currents

are < 200 mA

- Operate time (ID > 1.2 x ISET) < 60 ms

- Operate time (ID > 3.5 x ISET) < 50 ms

Table 93 - Differential overcurrent stage 87T-2

Start value 5.0 – 40.0 x IN

Reset time < 95 ms

Reset ratio 0.95

Inaccuracy:

- Starting ±3% of set value or ±0.5% of rated value

- Operate time (ID > 3.5 x ISET) < 40 ms

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6.31 Arc flash detection (AFD)

DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH

Information on this product is offered as a tool for conducting arc flash

hazard analysis. It is intended for use only by qualified persons who are
knowledgeable about power system studies, power distribution equipment,
and equipment installation practices. It is not intended as a substitute for the
engineering judgement and adequate review necessary for such activities.

Failure to follow this instruction will result in death or serious injury.

6.31.1 Arc flash detection, general principle

The arc flash detection contains 8 arc stages that can be used to trip for example
the circuit breakers. Arc stages are activated with overcurrent and light signals (or
light signals alone). The allocation of different current and light signals to arc
stages is defined in arc flash detection matrices: current, light and output matrix.
The matrices are programmed via the arc flash detection menus. Available matrix
signals depend on the order code (see 13.1 Order codes).

The available signal inputs and outputs for arc flash detection depend on the
relay's hardware configuration.

6.31.2 Arc flash detection menus

The arc flash detection menus are located in the main menu under ARC. The
ARC menu can be viewed either on the front panel or by using Easergy Pro.

Arc protection

Table 94 - Arc protection parameter group

Item Default Range Description

I>int. start setting 1.00 xln 0.50–8.00 x ln Phase A, B, C

overcurrent start
level

Io>int. start setting 1.00 xln 0.10–5.00 x ln Residual overcurrent

start level

Install arc sensors - -, Install Installs all connected

sensors

Installation state Ready Installing, Ready Installation state

Link Arc selfdiag to On On, Off Links Arc protection

SF relay selfsupervision
signal to SF relay

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Item Default Range Description

Stage Enabled On or Off On, Off Enables the arc

protection stage

Trip delay [ms] 0 0–255 Trip delay for the arc

protection stage

Min. hold time 2 2–255 Minimum trip pulse

[10ms] length for the arc
protection stage

(Overshoot time
<35ms)

Loop Sensor’s 737 100–900 Sensitivity setting for

sensitivity fibre loop sensor

WARNING
HAZARD OF DELAYED OPERATION

Do not use the arc stage delay for primary trip. This delay is intended, with
the separate arc stage, for the circuit breaker failure scheme only

Failure to follow these instructions can result in death, serious injury,

or equipment damage.

6.31.3 Configuration example of arc flash detection

Installing the arc flash sensors and I/O units

1. Go to Protection > Arc protection.

2. Under Settings, click the Install arc sensors drop-down list and select
Install.

3. Wait until the Installation state shows Ready. The communication between
the system components is created.

4. The installed sensors and units can be viewed at the bottom of the Arc
protection group view.

Figure 141 - Installed arc sensors

On the Easergy Pro group list, select Arc protection.

5. Click the Arc Stages 1, 2, and select Stage 1 and 2 'On'.

6. Click the Trip delay[ms] value, set it to for example '0' and press Enter.

7. Click the DI block value, set it to for example '-' and press Enter.

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Configuring the current start values

The General > Scaling setting view contains the primary and secondary values
of the CT. However, the Arc protection menu calculates the primary value only
after the I start setting value is given.

For example:

1. Go to General > Scaling.

2. Click the CT primary value, set it to for example 1200 A, and press Enter.

3. Click the CT secondary value, set it to for example 5 A, and press Enter.

4. On the Easergy Pro group list, select Protection > Arc protection.

5. Define the I start setting value for the relay.

6. Define the Io start setting in a similar manner.

Figure 142 - Example of setting the current transformer scaling values

Figure 143 - Example of defining the I start setting value

Configuring the current matrix

Define the current signals that are received in the arc flash detection system’s
relay. Connect currents to Arc stages in the matrix.

For example:

The arc flash fault current is measured from the incoming feeder, and the current
signal is linked to Arc stage 1 in the current matrix.

1. Go to Matrix > Arc matrix - Current

2. In the matrix, select the connection point of Arc stage 1 and I>int.

3. On the Communication menu, select Write Changed Settings To Device.

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Figure 144 - Configuring the current matrix – an example

Configuring the light matrix

Define what light sensor signals are received in the detection system. Connect
the light signals to the arc stages in the matrix.

For example:

1. Go to Matrix > Arc matrix - Light.

2. In the matrix, select the connection point of Arc sensor 1 and Arc stage 2.

3. Select the connection point of Arc sensor 2 and Arc stage 2.

4. On the Communication menu, select Write Changed Settings To Device.

Figure 145 - Configuring the light arc matrix

Configuring the output matrix

Define the trip relays that the current and light signals affect.

For example:

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1. Go to Matrix > Arc matrix - Output.

2. In the matrix, select the connection point of Arc stage 1 and T1.
3. Select the connection points of Latched and T1 and T9.

4. Select the connection point of Arc stage 2 and T9.

5. On the Communication menu, select Write Changed Settings To Device.

NOTE: It is recommended to use latched outputs for the trip outputs.

Arc output matrix includes only outputs which are directly controlled by FPGA.

Figure 146 - Configuring the output matrix - an example

Configuring the arc events

Define which arc events are written to the event list in this application.

For example:

1. Go to Logs > Event enabling - Arc.

2. In the matrix, enable both ‘Act On’ event and ‘Act Off’’ event for Arc sensor
1, Arc stage 1, and Arc stage 2.

3. On the Communication menu, select Write Changed Settings To Device.

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Figure 147 - Configuring the arc events – an example

6.31.4 Arc flash detection characteristics

The operation of the arc detection depends on the setting value of the I> int and
I01> int current limits.

The arc current limits cannot be set, unless the relay is provided with the optional
arc protection card.

Table 95 - Arc flash detection characteristics

Start current:

Phase currents 0.50–8.00 x IN (step 0.01)

Residual current 0.10–5.00 x IN (step 0.01)

Operate time

High break trip relays (T1, T9–T12)

- Light only ≤9 ms

- 4 x Iset and light ≤9 ms

Trip relays (T2, T3 and T4)

- Light only ≤7 ms

- 4 x Iset and light ≤7 ms

Semiconductor outputs (HSO1 – HSO2)

- Light only ≤2 ms

- 4 x Iset and light ≤2 ms

- Arc stage delay 0 – 255 ms

Inaccuracy:

Current ±5% of the set value

Delayed operation time +≤10 ms of the set value

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6.32 Programmable stages (ANSI 99)

Description

For special applications the user can built own detection stages by selecting the
supervised signal and the comparison mode.

The following parameters are available:

• Priority: Protection task execution cycle. If operate times less than 80

milliseconds are needed, select 10 ms. For operate times under one second,
20 ms is recommended. For longer operation times and THD signals, 100 ms
is recommended.
• Time-base for input value A: ”Instant” is the latest available value of the
measurement. The other ones are average values of the measurement during
the given time. The average values are calculated for different purposes all
the time, for example, the 200 ms value is used to update the local display.

NOTE: Pay attention to selecting these timing values. For example,

having a short operate time but 1 minute time base does not necessarily
give the expected result. Using long time bases gives the possibility to use
a filtered value to avoid unnecessary operations.
• Coupling A: The selected supervised signal in “>” and “<” mode. The
available signals are shown in the table below.
• Coupling B: The selected supervised signal in "Diff" and "AbsDiff" mode. This
selection becomes available once "Diff" or "AbsDiff" is chosen for Coupling A.
• Compare condition: Compare mode. ‘>’ for over or ‘<’ for under comparison,
“Diff” and “AbsDiff” for comparing Coupling A and Coupling B.
• AbsDiff | d |: Coupling A – coupling B. The stage activates if the difference is
greater than the start setting.
• Diff d: Coupling A – coupling B. The stage activates if the sign is positive and
the difference greater than the start setting.
• Start: Limit of the stage. The available setting range and the unit depend on
the selected signal.
• Operation delay: Definite time operation delay
• Hysteresis: Dead band (hysteresis). For more information, see 6.5 General
features of protection stages.
• No Compare limit for mode < : Only used with compare mode under (‘<’).
This is the limit to start the comparison. Signal values under NoCmp are not
regarded as fault.

Table 96 - Available signals to be supervised by the programmable stages

IA, IB, IC Phase currents (RMS values)

VAB, VBC, VCA Line-to-line voltages

IN Ground fault overcurrent

VA, VB, VC Line-to-neutral voltages

VN Neutral displacement voltage

f Frequency

P Active power

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Q Reactive power

S Apparent power

Cos Phi Cosine φ

IN Calc Phasor sum IA + IB + IC

I1 Positive sequence current

I2 Negative sequence current

I2/I1 Relative negative sequence current

I2/In Negative sequence current in pu

V1 Positive sequence overvoltage

V2 Negative sequence overvoltage

V2/V1 Relative negative sequence voltage

IAVG Average (IA + IB + IC) / 3

Tan Phi Tangent φ [= tan(arccosφ)]

PRMS Active power RMS value

QRMS Reactive power RMS value

SRMS Apparent power RMS value

THDILA Total harmonic distortion of IA

THDILB Total harmonic distortion of IB

THDILC Total harmonic distortion of IC

THDUA Total harmonic distortion of input VA

THDUB Total harmonic distortion of input VB

THDUC Total harmonic distortion of input VC

fy Frequency behind circuit breaker

fz Frequency behind 2nd circuit breaker

IA RMS IA RMS for average sampling

IB RMS IB RMS for average sampling

IC RMS IC RMS for average sampling

ILmin, ILmax Minimum and maximum of phase currents

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VLNmin, VLNmax Minimum and maximum of line-to-neutral

voltages

VAI1, VAI2, VAI3, VAI4, VAI5 Virtual analog inputs 1, 2, 3, 4, 5 (GOOSE)

Signals available depending on slot 8 options.

Eight independent stages

The relay has eight independent programmable stages. Each programmable

stage can be enabled or disabled to fit the intended application.

Setting groups

There are four settings groups available.

See 6.5 General features of protection stages for more details.

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