Rockwell Automation 865 User Manual

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865 Diﬀerential Protection Relay

For Motor, Transformer and Generator Dierential Protection Bulletin 865, Series A

User Manual

Solid-state equipment has operational characteristics differing from those of electro-

Important User Information

mechanical equipment. Safety Guidelines for the Application, Installation and Maintenance of Solid-State Controls (Publication SGI-1.1 available from your local Rockwell Automation sales office or online at http://literature.rockwellautomation.com) describes some important differences between solid-state equipment and hard-wired electromechanical devices. Because of this difference, and also because of the wide variety of uses for solid-state equipment, all persons responsible for applying this equipment must satisfy themselves that each intended application of this equipment is acceptable.

In no event will Rockwell Automation, Inc. be responsible or liable for any indirect or

consequential damages resulting from the use or application of this equipment.

The examples and diagrams in this manual are included solely for illustrative purposes.

Because of the many variables and requirements associated with any particular installation, Rockwell Automation, Inc. cannot assume responsibility or liability for actual use, based on the examples and diagrams.

No patent liability is assumed by Rockwell Automation, Inc. with respect to use of

information, circuits, equipment, or software described in this manual.

Reproduction of the contents of this manual, in whole or in part, without written

permission of Rockwell Automation, Inc. is prohibited.

Throughout this manual, when necessary we use notes to make you aware of safety

considerations.

W A R N I N GW A R N I N G

Identifies information about practices or circumstances that can cause an explosion in a hazardous environment, which may lead to personal injury or death, property damage, or economic loss.

I M P O R T A N TI M P O R T A N T

Identifies information that is critical for successful application and understanding of the product.

A T T E N T I O NA T T E N T I O N

Identifies information about practices or circumstances that can lead to personal injury or death, property damage, or economic loss. Attentions help you identify a hazard, avoid a hazard, and recognize the consequences.

S H O C K H A Z A R DS H O C K H A Z A R D

Labels may be on or inside the equipment (for example, drive or motor) to alert people that dangerous voltage may be present.

B U R N H A Z A R DB U R N H A Z A R D

Labels may be on or inside the equipment (for example, drive or motor) to alert people that surfaces may reach dangerous temperatures.

Chapter 1 Overview Introduction ............................................................................. 1-1

User Interface ...........................................................................1-3

Operating Safety ..................................................................... 1-3

Chapter 2 Relay Front Panel ....................................................................2-1

Display ............................................................................. 2-1

Menu Navigation and Pointers ......................................... 2-3

Keypad ............................................................................. 2-3

Operation Indicators ......................................................... 2-4

Resetting Latched Indicators and Output Relays ............. 2-5

Adjusting Display Contrast .............................................. 2-5

Local Panel Options ................................................................ 2-5

Navigating in Menus ........................................................ 2-5

Main Menu ....................................................................... 2-7

Menu Structure of Protection Functions .......................... 2-9

Setting Groups ................................................................ 2-12

Fault Logs ....................................................................... 2-13

Operating Levels ............................................................ 2-14

Opening Access .............................................................. 2-15

Password Handling ......................................................... 2-15

Operating Measures .............................................................. 2-16

Control Functions ........................................................... 2-16

Measured Data ............................................................... 2-17

Reading Event Register .................................................. 2-18

Forced Control (Force) ................................................... 2-19

Configuration and Parameter Setting .................................... 2-20

Parameter Setting ........................................................... 2-21

Setting Range Limits ...................................................... 2-22

Disturbance Recorder Menu DR .................................... 2-23

Configuring Digital Inputs DI ........................................ 2-23

Configuring Digital Outputs DO .................................... 2-24

Protection Menu Prot ..................................................... 2-24

Configuration Menu CONF ........................................... 2-25

Protocol Menu Bus ......................................................... 2-27

Single Line Diagram Editing .......................................... 2-30

SetPointPS PC Software ....................................................... 2-31

Local Panel User Interface

Chapter 3 Protection Functions Maximum Number of Protection Stages ................................ 3-1

Protection Functions ............................................................... 3-1

General Features of Protection Stages .................................... 3-1

Setting Groups .................................................................. 3-1

Forcing Start or Trip Condition for Testing ..................... 3-2

Forcing Start or Trip Condition for Testing Purposes ...... 3-2

Start and Trip Signals ....................................................... 3-2

Output Matrix ................................................................... 3-2

Blocking ........................................................................... 3-3

Main Relay Features ................................................................1-1

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ii Table of Contents

Retardation Time .............................................................. 3-3

Chapter 3 Protection Functions

Reset Time (Release Time) .............................................. 3-4

(cont.)

Hysteresis or Dead Band .................................................. 3-5

Differential Overcurrent Protection ΔI> (87) ......................... 3-6

Parameters of the Differential Overcurrent Stages ......... 3-10

Overcurrent Protection I> (50/51) ........................................ 3-11

Two Independent Stages ................................................ 3-11

Inverse Operation Time .................................................. 3-11

Inverse Time Limitation ................................................. 3-11

Setting Groups ................................................................ 3-11

Recorded Values of the Latest Eight Faults ................... 3-14

Current Unbalance Protection I

>, I’2 (46) ........................... 3-15

Inverse Delay ................................................................. 3-15

More Stages (Definite Time Delay only) ....................... 3-15

Setting Groups ................................................................ 3-15

Recorded Values of the Latest Eight Faults ................... 3-17

Earth Fault Protection I

> (50N/51N) ................................... 3-17

Input Signal Selection .................................................... 3-18

Intermittent Earth Fault Detection .................................. 3-18

Four Independent Undirectional Earth Fault

Overcurrent Stages ................................................... 3-18

Inverse Operation Time (I

> stage only) ........................ 3-19

Inverse Time Limitation ................................................. 3-19

Setting Groups ................................................................ 3-19

Recorded Values of the Latest Eight Faults ................... 3-22

Thermal Overload Protection T> (49) .................................. 3-22

Thermal Model ............................................................... 3-22

Time Constant for Cooling Situation ............................. 3-23

Heat Capacitance, Service Factor and Ambient Temp. ... 3-23

Example of a Behavior of the Thermal Model ............... 3-24

Initial Temperature Rise after Restart ............................ 3-24

Alarm Function .............................................................. 3-24

Circuit-Breaker Failure Protection CBFP (50BF) ................ 3-26

Recorded Values of the Latest Eight Faults .......................... 3-27

Arc Fault Protection (50ARC/50NARC) - Optional ............ 3-28

Three Stages for Arc Faults ............................................ 3-28

Light Channel Selection ................................................. 3-28

Binary Input ................................................................... 3-28

Binary Output ................................................................. 3-29

Delayed Light Indication Signal .................................... 3-29

Pick Up Scaling .............................................................. 3-29

Recorded Values of the Latest Eight Faults ................... 3-30

Programmable Stages (99) .................................................... 3-31

Available Signals to be Supervised by the

Programmable Stages .............................................. 3-31

Eight Independent Stages ............................................... 3-31

Setting Groups ................................................................ 3-31

Recorded Values of the Latest Eight Faults ................... 3-32

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Table of Contents iii

Inverse Time Operation ........................................................ 3-33

Chapter 3 Protection Functions

Stage Specific Inverse Delay .......................................... 3-33

(cont.)

Operation Modes ............................................................ 3-33

Local Panel Graph .......................................................... 3-33

Inverse Time Setting Error Signal .................................. 3-34

Limitation ....................................................................... 3-34

Standard Inverse Delays IEC, IEEE, IEEE2, RI ............ 3-35

IEC Inverse Time Operation .................................... 3-36

IEEE/ANSI Inverse Time Operation ....................... 3-38

IEEE2 Inverse Time Operation ............................... 3-42

RI and RXIDG type Inverse Time Operation .......... 3-43

Free Parametrisation using IEC, IEEE and IEEE2

Equations ................................................................. 3-45

Programmable Inverse Time Curves .............................. 3-46

Inverse Time Setting Error Signal .................................. 3-47

Limitations ..................................................................... 3-47

Chapter 4 Supporting Functions Event Log ................................................................................4-1

Event Enabling/Masking .................................................. 4-1

Event Buffer Overflow ..................................................... 4-2

Disturbance Recorder ............................................................. 4-2

Triggering the Recorder ................................................... 4-2

Reading Recordings ......................................................... 4-2

Number of Channels ........................................................ 4-3

Available Channels .......................................................... 4-3

Current Transformer Supervision ........................................... 4-5

Circuit Breaker Condition Monitoring ................................... 4-6

Breaker Curve and its Approximation ............................. 4-6

Setting Alarm Points ........................................................ 4-7

Clearing “Operations Left” Counters ............................... 4-8

Operation Counters to Monitor the Wearing .................... 4-8

Logarithmic Interpolation ................................................ 4-8

Example of the Logarithmic Interpolation ....................... 4-9

Example of Operation Counter Decrementing ................. 4-9

System Clock and Synchronization .......................................4-11

Adapting Auto Adjust .................................................... 4-11

Time Drift Correction Without External Sync ............... 4-11

System Clock Parameters ..................................................... 4-13

Running Hour Counter ......................................................... 4-14

Timers ................................................................................... 4-14

Combined Overcurrent Status ............................................... 4-16

Self-Supervision ................................................................... 4-17

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iv Table of Contents

Chapter 5 Measurement Functions Measurement Accuracy ...........................................................5-1

Harmonics and Total Harmonic Distortion (THD) ................. 5-2

RMS Values ............................................................................ 5-3

RMS Currents ................................................................... 5-3

Demand Values ....................................................................... 5-3

Maximum and Maximum Values ........................................... 5-3

Maximum Values of the last 31 days and 12 months ............. 5-4

Primary, Secondary and per unit Scaling ................................ 5-4

Current Scaling ................................................................. 5-4

Chapter 6 Control Functions Output Relays ..........................................................................6-1

Digital Inputs .......................................................................... 6-2

Virtual Inputs and Outputs ...................................................... 6-3

Output Matrix ......................................................................... 6-4

Blocking Matrix ...................................................................... 6-5

Controllable Objects ............................................................... 6-5

Object States ..................................................................... 6-6

Basic Settings for Controllable Objects ........................... 6-6

Output Signals of Controllable Objects ........................... 6-6

Settings for Read-only Objects ........................................ 6-7

Controlling with DI (Firmware version >= 5.53) ............. 6-7

Local/Remote Selection ................................................... 6-7

Logic Functions ...................................................................... 6-8

Chapter 7 Communications Communication Ports ..............................................................7-1

Local Port X4 ................................................................... 7-2

Remote Port X5 ................................................................ 7-4

Extension Port X4 ............................................................ 7-6

Optional Inbuilt Ethernet Port .......................................... 7-7

Optional 61850 Interface .................................................. 7-7

Communication Protocols ...................................................... 7-8

PC Communication .......................................................... 7-8

Modbus TCP and Modbus RTU........................................ 7-8

Probibus DP ..................................................................... 7-9

SPA-bus .......................................................................... 7-10

IEC 60870-5-103 ............................................................ 7-11

DNP 3.0 .......................................................................... 7-13

IEC 60870-5-101 .............................................................7-14

TCP/IP ............................................................................ 7-16

External I/O (Modbus RTU master) ............................... 7-16

IEC 61850 ...................................................................... 7-16

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Table of Contents v

Chapter 8 Applications Restricted Earth Fault Protection .............................................8-1

Restricted Earth Fault Protection for a Transformer

With Neutral Connection ................................................. 8-2

CT Requirements ............................................................. 8-2

Calculating the Stabilizing Resistance R

, VDR Value,

and Actual Sensitivity ................................................ 8-3

Value of Stabilizing Resistor R

...................................... 8-3

Voltage Limitation ........................................................... 8-3

Actual Operating Sensitivity ............................................ 8-4

Current Transformer Selection ............................................... 8-5

CT Classification according IEC 60044-1, 1996 ............. 8-5

CT Requirement for Protection ........................................ 8-8

Protection of a Dyn11 Transformer ...................................... 8-11

Protection of a YNd11 Transformer ..................................... 8-13

Protection of Generator and Block Transformer .................. 8-14

Application Example of Differential Protection

using Allen-Bradley 865 Relay ...................................... 8-15

Trip Circuit Supervision ...................................................... 8-16

Chapter 9 Connections Rear Panel View ......................................................................9-1

Auxiliary Voltage ................................................................... 9-5

Serial Communication Connectors ......................................... 9-5

Front Panel Connector ...................................................... 9-5

Rear Panel Connector X5 (REMOTE) ............................. 9-5

X4 Rear Panel Connector (Local RS232 and

Extension RS485 ports) ............................................. 9-7

Optional Two-Channel Arc Protection Card .......................... 9-8

Optional Digital I/O Card (DI19/DI20) .................................. 9-8

Connection Examples ............................................................. 9-9

865-UM001A-EN-P – July 2009

vi Table of Contents

Chapter 10 Technical Data Connections .......................................................................... 10-1

Measuring Circuitry ....................................................... 10-1

Auxiliary Voltage ........................................................... 10-1

Digital Inputs .................................................................. 10-2

Trip Contacts .................................................................. 10-2

Alarm Contacts ............................................................... 10-2

Local Serial Communication Port .................................. 10-3

Remote Control Connection ........................................... 10-3

Arc Protection Interface (Option) .................................. 10-3

Tests and Environmental Conditions .................................... 10-4

Disturbance Tests ........................................................... 10-4

Test Voltages .................................................................. 10-4

Mechanical Tests ............................................................ 10-4

Environmental Conditions .............................................. 10-4

Casing ............................................................................. 10-5

Package .......................................................................... 10-5

Protection Stages .................................................................. 10-5

Differential Protection .................................................... 10-5

Differential Overcurrent Stage ΔI> (87) .................. 10-5

Differential Overcurrent Stage ΔI>> (87) ............... 10-5

Non-Directional Current Protection ............................... 10-6

Overcurrent Stage I>, I’> (50/51) ............................ 10-6

Overcurrent Stage I>> and I’>> (50/51) .................. 10-6

Thermal Overload Stage T> (49) ............................. 10-7

Unbalance Stage I Earth Fault Stage I Earth Fault Stage I

>, I’2> (46) ................................. 10-7

> (50N/51N) ............................. 10-8

>>, I0>>>, I0>>>> (50N/51N) .. 10-8

Circuit-breaker Failure Protection .................................. 10-9

Arc Fault Protection Stages (Option) ............................. 10-9

Arc Protection Stage Arcl> (50AR), Option ........... 10-9

Arc Protection Stage Arcl Arc Protection Stage Arcl

> (50AR), Option .......... 10-9

> (50AR), Option ....... 10-10

Supporting Functions ................................................... 10-10

Disturbance Recorder (DR) ................................... 10-10

Chapter 11 List of Abbreviations and Symbols .......................................11-1

Abbreviations and Symbols

Chapter 12 Installation Mounting Instructions ........................................................... 12-1

865-UM001A-EN-P – July 2009

Chapter 1

Overview

Introduction The Allen-Bradley 865 differential protection system includes all the

essential protection functions needed to protect transformers for distribution networks of utilities, industry, power plants and offshore applications as well as motor and generator differential protection. Further, the device includes several programmable functions, such as thermal and circuit breaker protection and communication protocols for various protection and communication situations. An optional arc flash protection feature is also available.

The Allen-Bradley 865 can be used for selective differential

overcurrent, short-circuit protection of generators, transformers and motors in solidly or impedance earthed power systems. The relay can also be used for single, two or three-phase overcurrent and/or sensitive earth fault protection.

The modern technology in association with an extensive self-

supervision system and a reliable construction ensures extremely high system availability for the Allen-Bradley 865 protection relay.

Main Relay Features The main features of Allen-Bradley 865 are:

• Fully digital signal handling with a powerful 16-bit

microprocessor, and high measuring accuracy on all the setting ranges due to an accurate 16-bit A/D conversion technique

• Wide setting ranges for the protection functions, e.g. the earth

fault protection can reach a sensitivity of 0.5%

• The device can be matched to the requirements of the application

by disabling the functions that are not needed

• Flexible control and blocking possibilities due to digital signal

control inputs (DI) and outputs (DO)

• Easy adaptability of the relay to various substations and alarm

systems due to flexible signal-grouping matrix in the relay

• Freely configurable display with six measurement values

865-UM001A-EN-P – July 2009

1-2 Overview

Main Features (cont.)

• Freely configurable interlocking schemes with basic logic

functions

• Recording of events and fault values into an event register from

which the data can be read via a keypad and a local HMI or by means of a PC based SetPointPS user interface

• Latest events and indications are in non-volatile memory.

• Easy configuration, parameter setting and reading of information

via local HMI, or with the SetPointPS programming software

• Easy connection to power plant automation system due to a

versatile serial connection and several available communication protocols

• Built-in, self-regulating ac/dc converter for auxiliary power

supply from any source within the range from 40 to 865 V dc or ac. The alternative power supply is for 18 to 36 V dc

• Built-in disturbance recorder for evaluating all the analogue and

digital signals

• Eight (8) programmable stages for alarming or protection

purposes

The Allen-Bradley 865 differential protection relay is ideal for

transformer, motor, generator and short cable (100) differential protection. The relay features the following protection functions.

Table 1-1 – List of Protection Functions

IEEE/

ANSI code

50/51 3I>, 3I>>, 3I’>, 3I’>> Overcurrent protection

87 ∆I>, ∆I>> Differential overcurrent protection

46 I2>, I’2> Current unbalance protection

49 T> Thermal overload protection

50N/51N

50BF CBFP Circuit-breaker failure protection

99 Prg1...8 Programmable stages

50ARC

50NARC

Further the relay includes a disturbance recorder. Arc protection

is optionally available.

The relay communicates with other systems using common

protocols, such as the Modbus RTU, ModbusTCP, Profibus DP, Ethernet, DeviceNet, IEC 60870-5-103, SPA bus and DNP 3.0, IEC 61850 and IEC 60870-5-101.

IEC symbol Function name

>>,

>>>,

>>>>

ArcI>, ArcI’>

>, ArcI02>

ArcI

Earth fault protection

Optional arc fault protection

865-UM001A-EN-P – July 2009

Overview 1-3

User Interface

The relay can be controlled in three ways:

• Locally with the push-buttons on the relay front panel

• Locally using a PC connected to the serial port on the front panel

or on the rear panel of the relay (both cannot be used simultaneously)

• Via remote control over the remote control port on the relay rear

panel.

Operating Safety

A T T E N T I O NA T T E N T I O N

The terminals on the rear panel of the relay may carry dangerous voltages, even if the auxiliary voltage is switched off. A live current transformer secondary circuit must not be opened. Disconnecting a live circuit may cause dangerous voltages! Any operational measures must be carried out according to national and local handling directives and instructions.

Carefully read through all operation instructions before any

operational measures are carried out.

865-UM001A-EN-P – July 2009

1-4 Overview

865-UM001A-EN-P – July 2009

Chapter 2

Local Panel User Interface

Relay Front Panel The figure below shows, as an example, the front panel of the

Allen-Bradley 865 relay and the location of the user interface elements used for local control.

Figure 2.1 – Front Panel of Allen-Bradley 865 Relay

1. LCD dot matrix display

2. Keypad

3. LED indicators

4. RS 232 serial communication port for PC

Display

The relay is provided with a backlit 128x64 LCD dot matrix

display. The display enables showing 21 characters in one row and eight rows at the same time. The display has two different purposes: one is to show the single line diagram of the relay with the object status, measurement values, identification etc. (Figure

2.2). The other purpose is to show the configuration and parameter setting values of the relay (Figure 2.3).

865-UM001A-EN-P – July 2009

2-2 Local Panel User Interface

K00 0 6

Q0 Q3

AR : 1

50.02 Hz

Figure 2.2 – Sections of the LCD Matrix Display

1. Freely configurable single-line diagram

2. Five controllable objects

3. Status for six independent objects

4. Bay identification

5. Local/Remote selection

6. Auto-reclose on/off selection (if applicable)

7. Freely selectable measurement values (max. six values)

Figure 2.3 – Sections of the LCD Matrix Display

1. Main menu column

2. The heading of the active menu

3. The cursor of the main menu

4. Possible navigating directions (push buttons)

5. Measured/setting parameter

6. Measured/set value

865-UM001A-EN-P – July 2009

Local Panel User Interface 2-3

Backlight Control

Display backlight can be switched on with a digital input, virtual

input or virtual output. LOCALPANEL CONF/Display backlight ctrl setting is used for selecting trigger input for backlight control. When the selected input activates (rising edge), display backlight is set on for 60 minutes.

Menu Navigation and Pointers

1. Use the arrow keys UP and DOWN to move up and down in the main menu, that is, on the left-hand side of the display. The active main menu option is indicated with a cursor. The options in the main menu items are abbreviations, e.g. Evnt = events.

2. After any selection, the arrow symbols in the upper left corner of the display show the possible navigating directions (applicable navigation keys) in the menu.

3. The name of the active submenu and a possible ANSI code of the selected function are shown in the upper part of the display, e.g. CURRENTS.

4. Further, each display holds the measured values and units of one or more quantities or parameters, e.g. ILmax 300A.

Keypad

You can navigate in the menu and set the required parameter

values using the keypad and the guidance given in the display. Furthermore, the keypad is used to control objects and switches on the single line diagram display. The keypad is composed of four arrow keys, one cancel key, one enter key and one info key.

Figure 2-4 – Keys on the Keypad

1. Enter and confirmation key (ENTER)

2. Cancel key (CANCEL)

3. Up/Down [Increase/Decrease] arrow keys (UP/DOWN)

865-UM001A-EN-P – July 2009

2-4 Local Panel User Interface

4. Keys for selecting submenus [selecting a digit in a numerical value] (LEFT/RIGHT)

5. Additional information key (INFO)

NOTE: The term, which is used for the buttons in this manual,

is inside the rounded brackets.

Operation Indicators

The relay is provided with eight LED indicators:

Power

Error Com

Alarm Trip A B C

Figure 2.5 – Operation Indicators of the Relay

Table 2.1 – Operation Indicators

LED indicator Meaning Measure/ Remarks

Power LED lit The power has been switched on Normal operation state Error LED lit Internal fault, operates in parallel with

the self supervision output relay

Com LED lit or flashing The serial bus is in use and

transferring information

Alarm LED lit One or several signals of the output

relay matrix have been assigned to output LA and the output has been activated by one of the signals. (For more information about output matrix, please see page 2-24).

Trip LED lit One or several signals of the output

relay matrix have been assigned to output Tr, and the output has been activated by one of the signals. (For more information about output relay configuration, see “Configuring Digital Outputs DO” on page 2-24).

A- C LED lit Application-related status indicators. Configurable

The relay attempts to reboot [REBOOT]. If the error LED remains lit, call for maintenance.

Normal operation state

The LED is switched off when the signal that caused output Al to activate, e.g. the START signal, is reset. The resetting depends on the type of configuration, connected or latched.

The LED is switched off when the signal that caused output Tr to activate, e.g. the TRIP signal, is reset. The resetting depends on the type of configuration, connected or latched.

865-UM001A-EN-P – July 2009

Local Panel User Interface 2-5

Resetting Latched Indicators and Output Relays

All the indicators and output relays can be given a latching

function in the configuration.

There are several ways to reset latched indicators and relays:

• From the alarm list, move back to the initial display by pushing

the CANCEL key for approx. 3 s. Then reset the latched indicators and output relays by pushing the ENTER key.

• Acknowledge each event in the alarm list one by one by pushing

the ENTER key equivalent times. Then, in the initial display, reset the latched indicators and output relays by pushing the ENTER key.

The latched indicators and relays can also be reset via a remote

communication bus or via a digital input configured for that purpose.

Adjusting Display Contrast

The readability of the LCD varies with the brightness and the

temperature of the environment. The contrast of the display can be adjusted via the PC user interface, and SetPointPS software.

Local Panel Operations The front panel can be used to control objects, change the local/

remote status, read the measured values, set parameters, and to configure relay functions. Some parameters, however, can only be set by means of a PC connected to one of the local communication ports. Some parameters are factory-set.

Navigating in Menus

All the menu functions are based on the main menu/submenu structure:

1. Use the arrow keys UP and DOWN to move up and down in the main menu.

2. To move to a submenu, repeatedly push the RIGHT key until the required submenu is shown. Correspondingly, push the LEFT key to return to the main menu.

3. Push the ENTER key to confirm the selected submenu. If there are more than six items in the selected submenu, a black line appears to the right side of the display (Figure 2.6). It is then possible to scroll down in the submenu.

4. Push the CANCEL key to cancel a selection.

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2-6 Local Panel User Interface

Local Panel Operations (cont.)

5. Pushing the UP or DOWN key in any position of a sub-menu, when it is not selected, brings you directly one step up or down in the main menu.

The active main menu selection is indicated with black background

color. The possible navigating directions in the menu are shown in the upper-left corner by means of black triangular symbols.

Figure 2-6 – Example of Scroll Indication

Figure 2.7 – Principles of the Menu Structure and Navigation in the Menus

865-UM001A-EN-P – July 2009

Local Panel User Interface 2-7

6. Push the INFO key to obtain additional information about any menu item.

7. Push the CANCEL key to revert to the normal display.

Main Menu

The general menu structure is shown in Figure 2.7. The menu is

dependent on the user's configuration and the options according to the order code. For example only the enabled protection stages will appear in the menu.

Table 2.2 – List of the Local Main Menu

Main menu

1 Interactive mimic display 1 5 Double size measurements defined by the user 1 1 Title screen with device name, time and firmware version. P 14 Power measurements E 4 Energy measurements I 13 Current measurements U 15 Voltage measurements Dema 15 Demand values Umax 5 Time stamped min & max of voltages Imax 9 Time stamped min & max of currents Pmax 5 Time stamped min & max of power and frequency Mont 21 Maximum values of the last 31 days and the last twelve months Evnt 2 Events DR 2 Disturbance recorder 2 Runh 2 Running hour counter. Active time of a selected digital input and

TIMR 6 Day and week timers DI 5 Digital inputs including virtual inputs DO 4 Digital outputs (relays) and output matrix ExtAI 3 External analogue inputs 3 ExDI 3 External digital inputs 3 ExDO 3 External digital outputs 3 Prot 27 Protection counters, combined overcurrent status, protection

ΔI> 7 1st differential stages ΔI>> 5 2nd differential stage I> 5 1st overcurrent stage (primary side) 50/51 4 I>> 3 2nd overcurrent stage (primary side) 50/51 4 I’> 5 1st overcurrent stage (secondary side) 50/51 4 I’>> 3 2nd overcurrent stage (secondary side) 50/51 4 I2> 3 Current unbalance stage (primary side) 46 4 I’2> 3 Current unbalance stage (secondary side) 46 4

Number of

menus

Description ANSI code Note

time stamps of the latest start and stop.

status, protection enabling, cold load and inrush detectionIf2> and block matrix

865-UM001A-EN-P – July 2009

2-8 Local Panel User Interface

Local Panel Operations (cont.)

Table 2.2 – List of the Local Main Menu (cont.)

Main menu

T> 3 Thermal overload stage 49 4 Io> 5 1st earth fault stage 50N/51N 4 Io>> 3 2nd earth fault stage 50N/51N 4 Io>>> 3 3rd earth fault stage 50N/51N 4 Io>>>> 3 4th earth fault stage 50N/51N 4 Prg1 3 1st programmable stage 4 Prg2 3 2nd programmable stage 4 Prg3 3 3rd programmable stage 4 Prg4 3 4th programmable stage 4 Prg5 3 5th programmable stage 4 Prg6 3 6th programmable stage 4 Prg7 3 7th programmable stage 4 Prg8 3 8th programmable stage 4 CBFP 3 Circuit breaker failure protection 50BF 4 CBWE 4 Circuit breaker wearing supervision 4 CTSV 1 CT supervisor 4 CT’SV 1 CT’ supervisor 4 ArcI> 4 Optional arc protection stage for phase-to-phase faults and

ArcIo> 3 Optional arc protection stage for earth faults. Current input = I01 50NARC 4 ArcIo2> 3 Optional arc protection stage for earth faults. Current input = I02 50NARC 4 OBJ 11 Object definitions 5 Lgic 2 Status and counters of user's logic 1 CONF 10+2 Device setup, scaling etc. 6 Bus 13 Serial port and protocol configuration 7 Diag 6 Device selfdiagnosis

Number of

menus

Description ANSI code Note

50ARC 4

delayed light signal.

NOTES:

1. Configuration is done with SetPointPS.

2. Recording files are read with SetPointPS.

3. The menu is visible only if protocol ”External IO” is selected for one of the serial ports. Serial ports are configured in menu ”Bus”.

4. The menu is visible only if the stage is enabled.

5. Objects are circuit breakers, disconnectors, etc. Their position or status can be displayed and controlled in the interactive mimic display.

6. There are two extra menus, which are visible only if the access level ”operator” or ”configurator” has been opened with the corresponding password.

7. Detailed protocol configuration is done with SetPointPS.

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Local Panel User Interface 2-9

Menu Structure of Protection Functions

The general structure of all protection function menus is similar

although the details do differ from stage to stage. As an example the details of the second overcurrent stage I>> menus are shown below:

IRST MENU OF I>> 50/51 STAGE

I>> STATUS 50/51

Off

5 2 1

ExDO Prot I>

I>>

Iv>

Figure 2.8 – First Menu of I>>50/51 Stage

I>j

Status SCntr TCntr SetGrp SGrpDI Force

This is the status, start and trip counter and setting group menu. The

content is:

• Status – The stage is not detecting any fault at the moment. The stage can also be forced to pick-up or trip if the operating level is "Configurator" and the force flag below is on. Operating levels are explained in section “Operating Levels”.

• SCntr 5 – The stage has picked-up a fault five times since the last reset of restart. This value can be cleared if the operating level is at least "Operator".

• TCntr 1 – The stage has tripped two times since the last reset of restart. This value can be cleared if the operating level is at least "Operator".

• SetGrp 1 – The active setting group is one. This value can be edited if the operating level is at least “Operator”. Setting groups are explained in section “Setting Groups”.

• SGrpDI – The setting group is not controlled by any digital input. This value can be edited if the operating level is at least “Configurator”.

• Force Off – The status forcing and output relay forcing is disabled. This force flag status can be set to “On” or back to “Off” if the operating level is at least “Configurator”. If no front panel button is pressed within five minutes and there is no SetPointPS communication, the force flag will be set to “Off” position. The forcing is explained in section “Forced Control (Force)”.

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2-10 Local Panel User Interface

Local Panel Operations (cont.)

Figure 2.9 – Second Menu (next to the right) of I>>50/51 Stage

This is the main setting menu. The content is:

• Stage setting group 1 – These are the group 1 setting values.

ECOND MENU OF I>> 50/51 STAGE

I>> SET 50/51 Stage setting group 1 ExDI ExDO Prot

I>>

CBWE OBJ

ILmax Status I>> I>> t>>

403A

1013A

2.50xIgn

0.60s

The other setting group can be seen by pressing push buttons ENTER and then RIGHT or LEFT. Setting groups are explained in section “Setting Groups”.

• Ilmax 403A – The maximum of the three measured phase currents is at the moment 403 A. This is the value the stage is supervising.

• Status – Status of the stage. This is just a copy of the status value in the first menu.

• I>> 1013 A – The pick-up limit is 1013 A in primary value.

• I>> 2.50xIn – The pick-up limit is 2.50 times the rated current of the protected object. This value can be edited if the operating level is at least "Operator". Operating levels are explained in section “Operating Levels”.

• t>> 0.60s – The total operation delay is set to 600 ms. This value can be edited if the operating level is at least "Operator".

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Local Panel User Interface 2-11

HIRD MENU OF I>> 50/51 STAGE

I>> LOG 50/51

FAULT LOG 1 ExDI

ExDO Prot

I>>

CBWE OBJ

Figure 2.10 – Third and Last Menu (next to the right) of I>>50/51 Stage

2006-09-14 12:25:10.288 Type Flt Load EDly

1-2

2.86xIgn

0.99xIgn 81%

SetGrp 1

This is the menu for registered values by the I>> stage. Fault logs are

explained under “Fault Logs” on page 2-13.

• FAULT LOG 1 – This is the latest of the eight available logs. You may move between the logs by pressing push buttons ENTER and then RIGHT or LEFT.

• 2006-09-14 – Date of the log.

• 12:25:10.288 – Time of the log

• Type 1-2 – The overcurrent fault has been detected in phases L1 and L2 (A & B, red & yellow, R&S, u&v).

• Flt 2.86xIn – The fault current has been 2.86 per unit.

• Load 0.99xIn – The average load current before the fault has been 0.99 pu.

• EDly 81% – The elapsed operation delay has been 81% of the setting 0.60 s = 0.49 s. Any registered elapsed delay less than 100 % means that the stage has not tripped, because the fault duration has been shorter than the delay setting.

• SetGrp 1 – The setting group has been 1. This line can be reached by pressing ENTER and several times the DOWN button.

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2-12 Local Panel User Interface

Local Panel Operations (cont.)

Setting Groups

Most of the protection functions of the relay have two setting groups.

These groups are useful for example when the network topology is changed frequently. The active group can be changed by a digital input, through remote communication or locally by using the local panel.

The active setting group of each protection function can be selected

separately. Figure 2.11 shows an example where the changing of the I> setting group is handled with digital input one (SGrpDI). If the digital input is TRUE, the active setting group is group two and correspondingly, the active group is group one, if the digital input is FALSE. If no digital input is selected (SGrpDI = -), the active group can be selected by changing the value of the parameter SetGrp.

Figure 2.11 – Example of Protection Submenu with Setting Group

The changing of the setting parameters can be done easily. When the

desired submenu has been found (with the arrow keys), press the ENTER key to select the submenu. Now the selected setting group is indicated in the down-left corner of the display (See Figure 2.12). Set1 is setting group one and Set2 is setting group two. When the needed changes, to the selected setting group, have been done, press the LEFT or the RIGHT key to select another group (the LEFT key is used when the active setting group is 2 and the RIGHT key is used when the active setting group is 1).

Figure 2.12 – Example of I> Setting Submenu

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Local Panel User Interface 2-13

Fault Logs

All the protection functions include fault logs. The fault log of a

function can register up to eight different faults with time stamp information, fault values etc. Each function has its own logs (See Figure 2.13).

Figure 2.13 – Example of Fault Log

To see the values of, for example, log two, press the ENTER key to

select the current log (log one). The current log number is then indicated in the down-left corner of the display (See Figure 2.14, Log2 = log two). The log two is selected by pressing the RIGHT key once.

Figure 2.14 – Example of Selected Fault Log

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2-14 Local Panel User Interface

Operating Levels

Local Panel Operations (cont.)

The relay has three operating levels: User level, Operator level

and Configurator level. The purpose of the access levels is to prevent accidental change of relay configurations, parameters or settings.

USER level

Use: Possible to read e.g. parameter values,

measurements and events Opening: Level permanently open Closing: Closing not possible

OPERATOR level

Use: Possible to control objects and to change e.g. the

settings of the protection stages Opening: Default password is 1 Setting State: Push ENTER Closing: The level is automatically closed after 10 minutes

idle time. Giving the password 9999 can also close

the level.

CONFIGURATION level

Use: The configurator level is needed during the

commissioning of the relay. E.g. the scaling of the

voltage and current transformers can be set. Opening: Default password is 0002 Setting State: Push ENTER Closing: The level is automatically closed after 10 minutes

idle time. Giving the password 9999 can also close

the level.

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Local Panel User Interface 2-15

Opening Access

1. Push the INFO key and the ENTER key on the front panel.

ENTER PASSWORD

***

Figure 2.15 – Opening the Access Level

2. Enter the password needed for the desired level: the password can contain four digits. The digits are supplied one by one by first moving to the position of the digit using the RIGHT key and then setting the desired digit value using the UP key.

3. Push the ENTER key.

Password Handling

The passwords can only be changed using SetPointPS software

connected to the local RS-232 port on the relay.

It is possible to restore the password(s) in case the password is lost or

forgotten. In order to restore the password(s), a relay program is needed. The serial port settings are 38400 bps, 8 data bits, no parity and one stop bit. The bit rate is configurable via the front panel.

Command Description

get pwd_break Get the break code (Example: 6569403) get serno Get the serial number of the relay (Example: 12345)

Send both the numbers to Rockwell Automation and ask for a

password break. A device specific break code is sent back to you. That code will be valid for the next two weeks only for this specific device.

Command Description

set pwd_break=4435876 Restore the factory default passwords (“4435876” is

just an example. The actual code should be requested from Rockwell Automation.)

Now the passwords are restored to the default values (See section

“Operating Levels”).

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2-16 Local Panel User Interface

Operating Measures Control Functions

The default display of the local panel is a single-line diagram

including relay identification, Local/Remote indication, Auto-reclose on/off selection and selected analogue measurement values.

Please note that the operator password must be active in order to be

able to control the objects. Please refer to ‘Opening Access’ on page 2-15.

Toggling Local/Remote Control

1. Push the ENTER key. The previously activated object starts to blink.

2. Select the Local/Remote object (“L” or “R” squared) by using the arrow keys.

3. Push the ENTER key. The L/R dialog opens. Select “REMOTE” to enable remote control and disable local control. Select “LOCAL” to enable local control and disable remote control.

4. Confirm the setting by pushing the ENTER key. The Local/Remote state will change.

Object Control

1. Push the ENTER key. The previously activated object starts to blink.

2. Select the object to control by using the arrow keys. Please note that only controllable objects can be selected.

3. Push the ENTER key. A control dialog opens.

4. Select the “Open” or “Close” command by using the UP and DOWN arrow keys.

5. Confirm the operation by pushing the ENTER key. The state of the object changes.

Toggling Virtual Inputs

1. Push the ENTER key. The previously activated object starts to blink.

2. Select the virtual input object (empty or black square)

3. The dialog opens

4. Select “VIon” to activate the virtual input or select “VIoff” to deactivate the virtual input

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Local Panel User Interface 2-17

Measured Data

The measured values can be read from the main menus and their

submenus. Furthermore, any measurement value in the following table can be displayed on the main view next to the single line diagram. Up to six measurements can be shown.

Table 2.3 – Measured Values

Value Menu/Submenu Description

f P/POWER Frequency [Hz] IL1 I/PHASE CURRENTS Phase current IL1 [A] IL2 I/PHASE CURRENTS Phase current IL2 [A] IL3 I/PHASE CURRENTS Phase current IL3 [A] IL1da I/PHASE CURRENTS 15 min average for IL1 [A] IL2da I/PHASE CURRENTS 15 min average for IL2 [A] IL3da I/PHASE CURRENTS 15 min average for IL3 [A] I’L1 I/PHASE CURRENTS Phase current I’L1 [A] I’L2 I/PHASE CURRENTS Phase current I’L2 [A] I’L3 I/PHASE CURRENTS Phase current I’L3 [A] I’L1da I/PHASE CURRENTS 15 min average for I’L1 [A] I’L2da I/PHASE CURRENTS 15 min average for I’L2 [A] I’L3da I/PHASE CURRENTS 15 min average for I’L3 [A] Io I/SYMMETRIC CURRENTS Primary value of zero sequence/ residual current Io [A] Io2 I/SYMMETRIC CURRENTS Primary value of zero-sequence/residual current Io2 [A] IoC I/SYMMETRIC CURRENTS Calculated Io [A] I1 I/SYMMETRIC CURRENTS Positive sequence current [A] I2 I/SYMMETRIC CURRENTS Negative sequence current [A] I2/I1 I/SYMMETRIC CURRENTS Negative sequence current related to positive sequence current

(for unbalance protection) [%] I’1 I/SYMMETRIC CURRENTS Positive sequence current [A] I’2 I/SYMMETRIC CURRENTS Negative sequence current [A] I’2/I’1 I/SYMMETRIC CURRENTS Negative sequence current related to positive sequence current

(for unbalance protection) [%] THDIL I/HARM. DISTORTION Total harmonic distortion of the mean value of phase currents [%] THDIL1 I/HARM. DISTORTION Total harmonic distortion of phase current IL1 [%] THDIL2 I/HARM. DISTORTION Total harmonic distortion of phase current IL2 [%] THDIL3 I/HARM. DISTORTION Total harmonic distortion of phase current IL3 [%] THDI’L1 I/HARM. DISTORTION Total harmonic distortion of phase current I’L1 [%] THDI’L2 I/HARM. DISTORTION Total harmonic distortion of phase current I’L2 [%] THDI’L3 I/HARM. DISTORTION Total harmonic distortion of phase current I’L3 [%] Diagram I/HARMONICS of IL1 Harmonics of phase current IL1 [%] (See Figure 2.16) Diagram I/HARMONICS of IL2 Harmonics of phase current IL2 [%] (See Figure 2.16) Diagram I/HARMONICS of IL3 Harmonics of phase current IL3 [%] (See Figure 2.16) Diagram I/HARMONICS of I’L1 Harmonics of phase current I’L1 [%] (See Figure 2.16) Diagram I/HARMONICS of I’L2 Harmonics of phase current I’L2 [%] (See Figure 2.16) Diagram I/HARMONICS of I’L3 Harmonics of phase current I’L3 [%] (See Figure 2.16)

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2-18 Local Panel User Interface

Operating measures (cont.)

Figure 2.16 – Example of Harmonics Bar Display

Reading Event Register

The event register can be read from the EVNT submenu:

1. Push the RIGHT key once.

2. The EVENT LIST appears. The display contains a list of all the events that have been configured to be included in the event register.

Figure 2.17 – Example of an Event Register

3. Scroll through the event list with the UP and DOWN keys.

4. Exit the event list by pushing the LEFT key.

It is possible to set the order in which the events are sorted. If the

“Order” -parameter is set to “New-Old”, then the first event in the EVENT LIST is the most recent event.

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Local Panel User Interface 2-19

Forced Control (Force)

In some menus it is possible to switch a signal on and off by using

a force function. This feature can be used, for instance, for testing a certain function. The force function can be activated as follows:

1. Move to the setting state of the desired function, for example DO (see section “Configuration and Parameter Setting”).

2. Select the Force function (the background color of the force text is black).

Figure 2.18 – Selecting Force Function

3. Push the ENTER key.

4. Push the UP or DOWN key to change the "OFF" text to "ON", that is, to activate the Force function.

5. Push the ENTER key to return to the selection list. Choose the signal to be controlled by force with the UP and DOWN keys, for instance the T1 signal.

6. Push the ENTER key to confirm the selection. Signal T1 can now be controlled by force.

7. Push the UP or DOWN key to change the selection from "0" (not alert) to "1" (alert) or vice versa.

8. Push the ENTER key to execute the forced control operation of the selected function, e.g., making the output relay of T1 to pick up.

9. Repeat the steps 7 and 8 to alternate between the on and off state of the function.

10. Repeat the steps 1...4 to exit the Force function.

11. Push the CANCEL key to return to the main menu.

NOTE: All the interlockings and blockings are bypassed when

the force control is used.

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2-20 Local Panel User Interface

Configuration and

The minimum procedure to configure a relay is:

Parameter Setting

1. Open the access level "Configurator". The default password for configurator access level is 2.

2. Set the rated values in menu [CONF] including at least current transformers and a protected transformer rating. Also the date and time settings are in this same main menu.

3. Enable the needed protection functions and disable the rest of the protection functions in main menu [Prot].

4. Set the setting parameter of the enable protection stages according the application.

5. Connect the output relays to the start and trip signals of the enabled protection stages using the output matrix. This can be done in main menu [DO], although the SetPointPS program is recommended for output matrix editing.

6. Configure the needed digital inputs in main menu [DI].

7. Configure blocking and interlockings for protection stages using the block matrix. This can be done in main menu [Prot], although SetPointPS is recommended for block matrix editing.

Some of the parameters can only be changed via the RS-232

serial port using the SetPointPS software. Such parameters, (for example passwords, blockings and mimic configuration) are normally set only during commissioning.

Some of the parameters require the restarting of the relay. This

restarting is done automatically when necessary. If a parameter change requires restarting, the display will show as Figure 2.19.

Figure 2.19 – Example of Auto-Reset Display

Press CANCEL to return to the setting view. If a parameter must

be changed, press the ENTER key again. The parameter can now be set. When the parameter change is confirmed with the ENTER key, a [RESTART]- text appears to the top-right corner of the display. This means that auto-resetting is pending. If no key is pressed, the auto-reset will be executed within few seconds.

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Local Panel User Interface 2-21

Parameter Setting

1. Move to the setting state of the desired menu (for example CONF/CURRENT SCALING) by pushing the ENTER key. The Pick text appears in the upper-left part of the display.

2. Enter the password associated with the configuration level by pushing the INFO key and then using the arrow keys and the ENTER key (default value is 0002). For more information about the access levels, please refer to section “Operating Levels”.

3. Scroll through the parameters using the UP and DOWN keys. A parameter can be set if the background color of the line is black. If the parameter cannot be set the parameter is framed.

4. Select the desired parameter (for example Inom) with the ENTER key.

5. Use the UP and DOWN keys to change a parameter value. If the value contains more than one digit, use the LEFT and RIGHT keys to shift from digit to digit, and the UP and DOWN keys to change the digits.

6. Push the ENTER key to accept a new value. If you want to leave the parameter value unchanged, exit the edit state by pushing the CANCEL key.

Figure 2.20 – Changing Parameters

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2-22 Local Panel User Interface

Configuration and

Setting Range Limits

Parameter Setting

If the given parameter setting values are out-of-range values, a

(cont.)

fault message will be shown when the setting is confirmed with the ENTER key. Adjust the setting to be within the allowed range.

Figure 2.21 – Example of a Fault Message

The allowed setting range is shown in the display in the setting

mode. To view the range, push the INFO key. Push the CANCEL key to return to the setting mode.

Figure 2.22 – Allowed Setting Ranges shown in the Display

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Local Panel User Interface 2-23

Disturbance Recorder Menu DR

Via the submenus of the disturbance recorder menu the

following functions and features can be read and set:

DISTURBANCE RECORDER

• Recording mode (Mode)

• Sample rate (Rate)

• Recording time (Time)

• Pre trig time (PreTrig)

• Manual trigger (MnlTrig)

• Count of ready records (ReadyRe)

REC. COUPLING

• Add a link to the recorder (AddLink)

• Clear all links (ClrLnks)

Available links:

• DO, DI

• IL, I’L

• I2/In, I2/I1, I2, I1, IoCalc, I2/In, I’2/I’1, I’2, I’1, I’oCalc

• f

• Io2, Io1

• IL3, IL2, IL1, I’L3, I’L2, I’L1

• IL1RMS, IL2RMS, IL3RMS

• ILmin, ILmax, I’Lmin, I’Lmax

• ΔIl1, ΔIl2, ΔIl3

• IL1w, IL2w, IL3w, I’L1w, I’L2w, I’L3w

Configuring Digital Inputs DI

The following functions can be read and set via the submenus of

the digital inputs menu:

• The status of digital inputs (DIGITAL INPUTS 1-6)

• Operation counters (DI COUNTERS)

• Operation delay (DELAYs for DigIn)

• The polarity of the input signal (INPUT POLARITY). Either

normally open (NO) or normally closed (NC) circuit.

• Event enabling EVENT MASK1

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2-24 Local Panel User Interface

Configuration and

Configuring Digital Outputs DO

Parameter Setting

The following functions can be read and set via the submenus of

cont.)

the digital outputs menu:

• The status of the output relays (RELAY OUTPUTS1 and 2)

• The forcing of the output relays (RELAY OUTPUTS1 and 2)

(only if Force = ON): – Forced control (0 or 1) of the Trip relays – Forced control (0 or 1) of the Alarm relays – Forced control (0 or 1) of the IF relay

• The configuration of the output signals to the output relays. The

configuration of the operation indicators (LED) Alarm and Trip and application specific alarm leds A, B and C (that is, the output relay matrix).

NOTE: The amount of Trip and Alarm relays depends on the relay

type and optional hardware.

Protection Menu Prot

The following functions can be read and set via the submenus of

the Prot menu:

 Reset all the counters (PROTECTION SET/ClAll)  Read the status of all the protection functions (PROTECT

STATUS 1-x)

 Enable and disable protection functions (ENABLED STAGES

1-x)

 Define the interlockings between signals (only with SetPointPS).

Each stage of the protection functions can be disabled or enabled

individually in the Prot menu. When a stage is enabled, it will be in operation immediately without a need to reset the relay.

The relay includes several protection functions. However, the

processor capacity limits the number of protection functions that can be active at the same time.

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Local Panel User Interface 2-25

Configuration Menu CONF

The following functions and features can be read and set via the

submenus of the configuration menu:

DEVICE SETUP

• Bit rate for the command line interface in ports X4 and the front

panel. The front panel is always using this setting. If SPABUS is selected for the rear panel local port X4, the bit rate is according SPABUS settings.

• Access level [Acc]

LANGUAGE

• List of available languages in the relay

CURRENT SCALING

• Rated phase CT primary current (Inom)

• Rated phase CT secondary current (Isec)

• Rated input of the relay [Iinput]. 5 A or 1 A. This is specified in

the order code of the device.

• Rated phase CT’ primary current (I’nom)

• Rated phase CT’ secondary current (I’sec)

• Rated input of the relay [I’input]. 5 A or 1 A. This is specified in

the order code of the device.

• Rated value of I

CT primary current (Ionom)

CT secondary current (Iosec)

• Rated I01 input of the relay [Ioinp]. 5 A or 1 A. This is specified

in the order code of the device.

• Rated value of I

CT primary current (Io2nom)

CT secondary current (Io2sec)

• Rated I02 input of the relay [Io2inp]. 5A, 1 A or 0.2 A. This is

specified in the order code of the device.

The rated input values are usually equal to the rated secondary

value of the CT.

The rated CT secondary may be greater than the rated input but

the continuous current must be less than four times the rated input. In compensated, high impedance earthed and isolated networks using cable transformer to measure residual current I

it is quite usual to use a relay with 1 A or 0.2 A input although the CT is 5 A or 1A. This increases the measurement accuracy.

The rated CT secondary may also be less than the rated input but

the measurement accuracy near zero current will decrease.

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2-26 Local Panel User Interface

Configuration and

TRANSFORMER SETTING

Parameter Setting

cont.)

• Rated voltage in IL side (typically high voltage side)

• Rated voltage in I’L side (typically low voltage side)

• Rated power of transformer

• Connection group of transformer

• Zero current compensation in IL side (If transformer is earthed in

IL side, this must set as “ON”)

• Zero current compensation in I’L side (If transformer is earthed

in I’L side, this must set as “ON”)

• Connection group of the unit transformer, if any. IEC marking

with capital letters Y and D for HV side and small case letters y and d for LV side combined with the dial hour is used. For example Yd11 means a wye-delta transformer where the delta side phase-to-ground voltages are leading 30° the wye side phase-to-ground voltages.

DEVICE INFO

• Relay type (Type ALLEN BRADLEY 865)

• Serial number (SerN)

• Software version (PrgVer)

• Bootcode version (BootVer)

DATE/TIME SETUP

• Day, month and year (Date)

• Time of day (Time)

• Date format (Style). The choices are "yyyy-mm-dd",

"dd.nn.yyyy" and "mm/dd/yyyy".

CLOCK SYNCHRONISATION

• Digital input for minute sync pulse (SyncDI). If any digital input

is not used for synchronization, select "".

• Daylight saving time for NTP synchronization (DST).

• Detected source of synchronization (SyScr).

• Synchronization message counter (MsgCnt).

• Latest synchronization deviation (Dev).

The following parameters are visible only when the access level is

higher than "User".

• Offset, i.e. constant error, of the synchronization source (SyOS).

• Auto adjust interval (AAIntv).

• Average drift direction (AvDrft): "Lead" or "lag".

• Average synchronization deviation (FilDev).

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Local Panel User Interface 2-27

Protocol Menu Bus

There are three communication ports in the rear panel. In

addition there is a connector in the front panel overruling the local port in the rear panel.

REMOTE PORT X5

• Communication protocol for remote port X5 [Protocol].

• Message counter [Msg#]. This can be used to verify that the

device is receiving messages.

• Communication error counter [Errors].

• Communication time-out error counter [Tout].

• Information of bit rate/data bits/parity/stop bits.

This value is not directly editable. Editing is done in the appropriate protocol setting menus.

The counters are useful when testing the communication.

LOCAL PORT X4 (pins 2, 3 and 5)

This port is disabled, if a cable is connected to the front panel connector.

• Communication protocol for the local port X4 [Protocol]. For

SetPointPS use "None" or "SPABUS".

• Message counter [Msg#]. This can be used to verify that the

device is receiving messages.

• Communication error counter [Errors].

• Communication time-out error counter [Tout].

• Information of bit rate/data bits/parity/stop bits.

This value is not directly editable. Editing is done in the appropriate protocol setting menus. For SetPointPS and protocol "None" the setting is done in menu CONF/DEVICE SETUP.

PC (LOCAL/SPA BUS)

This is a second menu for local port X4. The SetPointPS communication status is showed.

• Bytes/size of the transmitter buffer [Tx].

• Message counter [Msg#]. This can be used to verify that the

device is receiving messages.

• Communication error counter [Errors]

• Communication time-out error counter [Tout].

• Same information as in the previous menu.

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2-28 Local Panel User Interface

Configuration and

EXTENSION PORT X4 (pins 7, 8 and 5)

Parameter Setting (cont.)

• Communication protocol for extension port X4 [Protocol].

• Message counter [Msg#]. This can be used to verify that the

device is receiving messages.

• Communication error counter [Errors].

• Communication time-out error counter [Tout].

• Information of bit rate/data bits/parity/stop bits.

This value is not directly editable. Editing is done in the appropriate protocol setting menus.

MODBUS

• Modbus address for this slave device [Addr]. This address has to

be unique within the system.

• Modbus bit rate [bit/s]. Default is "9600".

• Parity [Parity]. Default is "Even".

For details see the technical description part of the manual.

EXTERNAL I/O protocol

This is a Modbus master protocol to communicate with the extension I/O modules connected to the extension port. Only one instance of this protocol is possible.

• Bit rate [bit/s]. Default is "9600".

• Parity [Parity]. Default is "Even".

For details see the technical description part of the manual.

SPA BUS

Several instances of this protocol are possible.

• SPABUS address for this device [Addr]. This address has to be

unique within the system.

• Bit rate [bit/s]. Default is "9600".

• Event numbering style [Emode]. Default is "Channel".

For details see the technical description part of the manual.

IEC 60870-5-103

Only one instance of this protocol is possible.

• Address for this device [Addr]. This address has to be unique

within the system.

• Bit rate [bit/s]. Default is "9600".

• Minimum measurement response interval [MeasInt].

• ASDU6 response time mode [SyncRe].

For details see the technical description part of the manual.

IEC 103 DISTURBANCE RECORDINGS

For details see the technical description part of the manual.

865-UM001A-EN-P – July 2009

Local Panel User Interface 2-29

PROFIBUS

Only one instance of this protocol is possible.

• [Mode]

• Bit rate [bit/s]. Use 2400 bps. This parameter is the bit rate

between the main CPU and the Profibus ASIC. The actual Profibus bit rate is automatically set by the Profibus master and can be up to 12 Mbit/s.

• Event numbering style [Emode].

• Size of the Profibus Tx buffer [InBuf].

• Size of the Profibus Rx buffer [OutBuf].

When configuring the Profibus master system, the length of these buffers are needed. The size of the both buffers is set indirectly when configuring the data items for Profibus.

• Address for this slave device [Addr]. This address has to be

unique within the system.

• Profibus converter type [Conv]. If the shown type is a dash “-“,

either Profibus protocol has not been selected or the device has not restarted after protocol change or there is a communication problem between the main CPU and the Profibus ASIC.

For details see the technical description part of the manual.

DNP3

Only one instance of this protocol is possible.

• Bit rate [bit/s]. Default is "9600".

• [Parity].

• Addres for this device [SlvAddr]. This address has to be unique

within the system.

• Master's addres [MstrAddr].

For further details see the technical description part of the manual.

TCP/IP

These TCP/IP parameters are used by the ethernet interface module. For changing the nnn.nnn.nnn.nnn style parameter values, SetPointPS is recommended.

• IP address [IpAddr].

• Net mask [NetMsk].

• Gateway [Gatew].

• Name server [NameSw].

• Network time protocol (NTP) server [NTPSvr].

• Protocol port for IP [Port]. Default is 502.

865-UM001A-EN-P – July 2009

2-30 Local Panel User Interface

Configuration and Parameter Setting

The optional plug on DeviceNet Communication Module provides

(cont.)

DEVICENET

the following features:

 Node address and network data rate is programmable through the

front panel of the 865 relay.

 Alternatively, the configuration settings can be accomplished

over the DeviceNet network, utilizing a network configuration tool such as RSNetWorx for DeviceNet.

 The status of the module is reported the status of the device bus

and network communications.

 UCMM (Unconnected Message Manager) messages are

supported with the ability to allocate up to 3 explicit message connections concurrently.

 DeviceNet Group 2 slave functionality including:

– Explicit connection – Polled connection – 1 COS (Change of State)/Cyclic connection

 Full DeviceNet Parameter Object support allows EDS files to be

extracted from all units.

TCP/IP [Ethernet]

These TCP/IP parameters are used by the ethernet interface module. For changing the nnn.nnn.nnn.nnn style parameter values, SetPointPS is recommended.

 IP address [IpAddr].  Net mask [NetMsk].  Gateway [Gatew].  Name server [NameSw].  Network time protocol (NTP) server [NTPSvr].  Protocol port for IP [Port]. Default is 502.

Single Line Diagram Editing

The single-line diagram is drawn with the SetPointPS software. For

more information, please refer to the SetPointPS manual.

865-UM001A-EN-P – July 2009

Local Panel User Interface 2-31

Bay

0 L

0.000A 0kW

0Kvar

Figure 2.23 – Single Line Diagram

Blocking and Interlocking Configuration

The configuration of the blockings and interlockings is done with the

SetPointPS software. Any start or trip signal can be used for blocking the operation of any protection stage. Furthermore, the interlocking between objects can be configured in the same blocking matrix of the SetPointPS software. For more information, please refer to the SetPointPS manual.

SetPointPS PC Software The PC user interface can be used for:

 On-site parameter setting of the relay  Loading relay software from a computer  Reading measured values, registered values and events to a

computer

 Continuous monitoring of all values and events

Two RS-232 serial ports are available for connecting a local PC with

SetPointPS to the relay; one on the front panel and one on the rear panel of the relay. These two serial ports are connected in parallel. However, if the connection cables are connected to both ports, only the port on the front panel will be active. To connect a PC to a serial port, use connection cable part no. 857-VX003-3.

The SetPointPS program can also use TCP/IP LAN connection.

Optional hardware is required.

There is a free of charge PC program called SetPointPS available for

configuration and setting of Allen-Bradley relays. Please download the latest SetPointPS.exe from our web page www.AB.com

. For more information about the SetPointPS software, please refer to the user’s manual, Publication 857-PM001A-EN-P. Also the SetPointPS user’s manual is available at our web site.

865-UM001A-EN-P – July 2009

2-32 Local Panel User Interface

865-UM001A-EN-P – July 2009

Chapter 3

Protection Functions

Each protection stage can independently be enabled or disabled

according to the requirements of the intended application.

The device limits the maximum number of enabled stages to about

Maximum Number of Protection Stages in one application

Table 3.1 – List of Protection Functions

Protection Functions

30, depending on the type of the stages. For more information, please see the configuration instructions in Chapter 2 in the first part of this manual.

IEEE/

ANSI code

50/51 3I>, 3I>>, 3I’>, 3I’>> Overcurrent protection

87 ∆I>, ∆I>> Differential overcurrent protection

46 I2>, I’2> Current unbalance protection

49 T> Thermal overload protection

50N/51N

50BF CBFP Circuit-breaker failure protection

99 Prg1...8 Programmable stages

50ARC

50NARC

IEC Symbol Function Name

>>,

>>>,

>>>>

ArcI>, ArcI’>

>, ArcI02>

ArcI

Earth fault protection

Optional arc fault protection

Setting Groups

General Features of Protection Stages

Most stages have two setting groups. Changing between setting

groups can be controlled manually or using any of the digital inputs, virtual inputs, virtual outputs or LED indicator signals. By using virtual I/O the active setting group can be controlled using the local panel mimic display, any communication protocol or using the inbuilt programmable logic functions.

865-UM001A-EN-P – July 2009

3-2 Protection Functions

Forcing Start or Trip Condition for Testing

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

• Ok = ‘–‘

• Blocked

The stage is not detecting any fault.

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

• Start

• Trip

The stage is counting the operation delay.

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 inbuilt blocking logic. For example an under frequency stage is blocked if voltage is too low. For more details about block matrix, see Chapter 5.

Forcing Start or Trip Condition for Testing Purposes

There is a "Force flag" parameter which, when activated, allows

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

After testing the force flag will automatically reset 5-minute after the

last local panel push button activity.

The force flag also enables forcing of the output relays and forcing

the optional mA outputs.

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.

Output Matrix

Using the output matrix the user connects the internal start and trip

signals to the output relays and indicators. For more details see Chapter 5.

865-UM001A-EN-P – July 2009

Protection Functions 3-3

Blocking

Any protection function, except arc protection, can be blocked with

internal and external signals using the block matrix (Chapter 5). 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 inbuilt blocking functions. For

example under-frequency protection has inbuilt under-voltage blocking to avoid tripping when the voltage is off.

When a protection stage is blocked, it won't pick-up in case of 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 pick-up reason, i.e. the fault condition, disappears. If the stage is already tripping, the blocking has no effect.

Retardation Time

Retardation time is the time a protection relay needs to notice that a

fault has been cleared during the operation time delay. This parameter is important when grading the operation time delay settings between relays.

RetardationTime

FAULT

t<50ms

RET

DELAY SETTING > t + t

TRIP CONTACTS

FAULT RET

Figure 3.1 – Retardation Time

865-UM001A-EN-P – July 2009

3-4 Protection Functions

Definition of retardation time: 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 i.e. pick-up 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 operation time difference

is not big enough. The difference must be more than the retardation time of the incoming feeder relay plus the operating time of the outgoing feeder circuit breaker.

Figure 3.1 shows an overcurrent fault seen by the incoming feeder,

when the outgoing feeder does clear 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 Allen-Bradley relays, the retardation time is less than 50 ms.

Reset Time (Release Time)

Figure 3.2 shows an example of reset time i.e. 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 will still flow 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 reset time varies from fault to fault depending on the fault size. After a big fault the time is longer. The reset time also depends on the specific protection stage. The maximum reset time for each stage is specified in Chapter 9. For most stages it is less than 95 ms.

SET

TRIP CONTACTS

Figure 3.2 – Reset time is the time it takes the trip or start relay contacts to

open after the fault has been cleared.

RESET

ReleaseTime

865-UM001A-EN-P – July 2009

Protection Functions 3-5

Hysteresis or Dead Band

When comparing a measured value against a pick-up 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.

hysteresis

PICK UP LEVEL

Hysteresis_GT

> PICK UP

Figure 3.3 – Behavior of a greater than comparator. For example in

overcurrent and overvoltage stages the hysteresis (dead band) acts according this figure.

hysteresis

PICK UP LEVEL

< PICK UP

Hysteresis_LT

Figure 3.4 – Behavior of a less than comparator. For example in under-voltage

and under frequency stages the hysteresis (dead band) acts according this figure.

865-UM001A-EN-P – July 2009

(

)

3-6 Protection Functions

Differential Overcurrent

The differential overcurrent protection comprises two separately

Protection ΔI> (87)

The differential protection is based on winding currents difference

Figure 3.5 – Winding currents in connection group Yy0

In the second example if transformer IL side is connected to open

adjustable stages, stage ΔI> and stage ΔI>>.

between IL and I’L side. In transformer applications the current calculation depends on transformer connection group. E.g. in Yy0 connection measured currents are also winding currents, see Figure

3.5. In generator applications the connection group is always Yy0 and measured currents are also winding currents.

delta, e.g. Dy11, then winding currents are calculated in delta side (IL side), see Figure 3.6.

Figure 3.6 – Winding currents in connection group Dy11

Equation 1: Winding current calculation in delta side, Dy11 connection

211

LLWL

III

−=

)(

III

−=

322

( )

865-UM001A-EN-P – July 2009

LLWL

133

LLWL

III

−=

Protection Functions 3-7

Equation 2: Winding currents in star side, Dy11 connection

LWL

Equation 3: Bias current

Equation 4: Differential current

LWL

III+

III '+=

Bias current calculation is only used in protection stage ΔI>. Bias

current describes the average current flow in transformer. Bias and differential currents are calculated individually for each phase.

If transformer is earthed, e.g. connection group Dyn11, then zero

current must be compensated before differential and bias current calculation. Zero current compensation can be selected individually for IL and I’L side.

Table 3.2 describes connection group and zero current compensation

for different connection groups. If protection area is only generator then connection group setting is always Yy0, see Table 3.3. Also the settings of Un and U’n are set to be the same, e.g. generator nominal voltage.

865-UM001A-EN-P – July 2009

3-8 Protection Functions

Table 3.2 – Zero Current Compensation in Transformer Applications

Transformator

Connection 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

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

ConnGrp Io cmps I'o cmps

Relay setting

Table 3.3 – Zero Current Compensation in Generator Applications

Genarator only

ConnGrp Io cmps I'o cmps

None earthing Yy0 OFF OFF

Relay setting

865-UM001A-EN-P – July 2009

Protection Functions 3-9

Figure 3.7 – Block Diagram of the Differential Overcurrent Stage ΔI>

The stage ΔI> can be configured to operate as shown in Figure 3.8.

This dual slope characteristic allows more differential current at higher currents before tripping.

Figure 3.8 – Example of differential overcurrent characteristics

865-UM001A-EN-P – July 2009

3-10 Protection Functions

The stage also includes second harmonics blocking. The second

harmonic is calculated from winding currents. Harmonic ratio is:

100 x I

f2_Winding

/ I

f1_Winding

[%]

Fast differential overcurrent stage ΔI>> does not include slope

characteristics and second harmonics blocking.

Parameters of the Differential Overcurrent Stages

Table 3.4 – Parameters of the Differential Overcurrent Stages ΔI> (87)

Parameter Value/unit

ΔL1

Measured values 

Setting values 

Recorded values

 Measurement ranges are described under “Measuring Circuitry” in Chapter 10.  Setting ranges are described in Table 10.15 and Table 10.16, Chapter 10.

Table 3.5 – Parameters of the Differential Overcurrent Stages ΔI>> (87)

Parameter Value/unit

Measured values

Setting values ΔI>> xIn Setting value Recorded values

ΔL2 ΔL3 ΔI> %ln Setting value Slope1 % Slope 1 setting Ibias2 xIn Bias current start of slope 2 Slope2 % Slope 2 setting Harm2> On/Off 2. harmonic blocking enable/disable Harm2> % 2. harmonic block limit TCntr Cumulative trip counter

Type

ΔFlt xIn Max. value of fault differential current as compared to In Bias xIn Value of bias current of faulted phase as compared to In Load xIn 1 s mean value of pre-fault phase currents IL1…IL3

ΔL1 ΔL2 ΔL3

TCntr Cumulative trip counter Type

ΔFlt xIn Max. value of fault differential current as compared to In Load xIn 1 s mean value of pre-fault phase currents IL1…IL3

xIn Current difference value

1-N, 2-N, 3-N Fault type/single-phase fault e.g.: 1-N = fault on phase L1

1-2, 2-3, 1-3 Fault type/two-phase fault e.g.: 2-3 = fault between L2 and L3

1-2-3 Fault type/three-phase fault

xIn Current difference value

1-N, 2-N, 3-N Fault type/single-phase fault e.g.: 1-N = fault on phase L1

1-2, 2-3, 1-3 Fault type/two-phase fault e.g.: 2-3 = fault between L2 and L3

1-2-3 Fault type/three-phase fault

865-UM001A-EN-P – July 2009

Protection Functions 3-11

Overcurrent Protection

Overcurrent protection is used against short circuit faults and heavy

I> (50/51)

overloads.

The overcurrent function measures the fundamental frequency

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

Two Independent Stages

There are two separately adjustable overcurrent stages: I>, I>>

I’>and I’>>. The first stage I> can be configured for definite time (DT) or inverse time operation characteristic (IDMT). The stage I>> has 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 3.9 shows a functional block diagram of the I> overcurrent

stage with definite time and inverse time operation time. Figure 3.10 shows a functional block diagram of the I>> overcurrent stage with definite time operation delay.

Inverse Operation Time

Inverse delay means that the operation time depends on the amount

the measured current exceeds the pick-up setting. The bigger the fault current is the faster will be the operation. Accomplished inverse delays are available for the I> stage. The relay will show the currently used inverse delay curve graph on the local panel display.

Inverse Time Limitation

The maximum measured secondary current is 50xIN. This limits the

scope of inverse curves with high pick-up settings.

Setting Groups

There are two settings groups available for each stage. Switching

between setting groups can be controlled by digital inputs, virtual inputs (mimic display, communication, logic) and manually.

865-UM001A-EN-P – July 2009

3-12 Protection Functions

Figure 3.9 – Typical block diagram of the three-phase overcurrent stage I> and I’>

Figure 3.10 – Typical block diagram of the three-phase overcurrent stage I>> and I>>>

865-UM001A-EN-P – July 2009

Protection Functions 3-13

Table 2.6 – Parameters of the Overcurrent Stage I> and I’> (50/51)

Parameter Value Unit Description Note

Status -

Blocked Start

Trip TripTime s Estimated time to trip SCntr Cumulative start counter Clr TCntr Cumulative trip counter Clr SetGrp 1 or 2 Active setting group Set SGrpDI

DIx

VIx

LEDx

VOx Force Off

ILmax A The supervised value. Max. of IL1, IL2

I> A Pick-up value scaled to primary value I> xIgn Pick-up setting Set Curve

IEC

IEEE

IEEE2

PrgN Type

LTI

Parameters t> s Definite operation time (for definite time

k> Inverse delay multiplier (for inverse time

Dly20x s Delay at 20xIset Dly4x s Delay at 4xIset Dly2x s Delay at 2xIset Dly1x s Delay at 1xIset A, B, C, D, E User's constants for standard equations.

For details of setting ranges see “Protection Stages” in Chapter 10. Set = An editable parameter (password needed) C = Can be cleared to zero F = Editable when force flag is on

Current status of the stage

Digital signal to select the active setting

group None Digital input Virtual input LED indicator signal Virtual output

Force flag for status forcing for test

purposes. This is a common flag for all stages and output relays, too. This flag is automatically reset 5 minutes after the last front panel push button pressing.

and IL3

Delay curve family:

Definite time Inverse time. See “Inverse Time Operation”.

Pre 1996

Delay type.

Definite time Inverse time. See “Inverse Time Operation”.

only)

Type=Parameters. See “Inverse Time Operation”.

F F

Set

865-UM001A-EN-P – July 2009

3-14 Protection Functions

Table 2.7 – Parameters of the Overcurrent Stages I>>, I’>> (50/51)

Parameter Value Unit Description Note

Status

SCntr Cumulative start counter C TCntr Cumulative trip counter C SetGrp 1 or 2 Active setting group Set

SGrpDI

Force

ILmax A The supervised value. Max. of IL1, IL2 and IL3 I>>, I>>> A Pick-up value scaled to primary value I>>, I>>> xIn Pick-up setting Set t>>, t>>> s Definite operation time Set

For details of setting ranges see “Protection Stages” in Chapter 10. Set = An editable parameter (password needed) C = Can be cleared to zero F = Editable when force flag is on

Blocked Start Trip

- DIx VIx LEDx VOx Off On

Current status of the stage

Digital signal to select the active setting group None Digital input Virtual input LED indicator signal Virtual output Force flag for status forcing for test purposes. This is a common flag for all stages and output relays, too. Automatically reset by a 5-minute timeout.

Recorded Values of the Latest Eight Faults

Detailed information is available on the eight latest faults: Time

stamp, fault type, fault current, load current before the fault, elapsed delay and setting group.

Table 2.8 – Recorded Values of the Overcurrent Stages (8 latest faults) I>, I>>, I>>> (50/51)

Parameter Value Unit Description

yyyy-mm-dd Time stamp of the recording, date hh:mm:ss.ms Time stamp, time of day

Type

1-N 2-N 3-N

1-2 2-3 3-1

1-2-3

Flt xIgn Maximum fault current Load xIgn 1 s average phase currents before the fault EDly % Elapsed time of the operating time setting. 100% = trip SetGrp 1 2 Active setting group during fault

Fault type

Ground fault Ground fault Ground fault Two phase fault Two phase fault Two phase fault Three phase fault

F F

Set

865-UM001A-EN-P – July 2009

Protection Functions 3-15

The current unbalance stage protects against unbalanced phase

Current unbalance protection

>, I’2> (46)

currents and single phasing. The protection is based on the negative sequence current.

Both definite time and inverse time characteristics are available. The

inverse delay is based on Equation 5. Only the base frequency components of the phase currents are used to calculate the negative sequence value I

Inverse Delay

The inverse delay is based on the following equation.

Equation 5

= , where

⎛ ⎜

⎜ ⎝

t = Operation time K

= Delay multiplier

= Measured and calculated negative sequence

= Rated current

= Pick-up setting I2> in pu. The maximum

Example:

= 15 s

= 22.9 % = 0.229 xIN

= 5 % = 0.05 xIN

⎛ ⎜

⎝

The operation time in this example will be five minutes.

More Stages (Definite Time Delay only)

If more than one definite time delay stages are needed for current

unbalance protection, the freely programmable stages can be used (Chapter 2).

⎞

⎟ ⎟

⎠

−

phase current of fundamental frequency.

allowed degree of unbalance.

229.0

⎞

−

⎟

⎠

05.0

4.300

Setting Groups

There are two settings groups available. Switching between setting

groups can be controlled by digital inputs, virtual inputs (mimic display, communication, logic) and manually.

865-UM001A-EN-P – July 2009

3-16 Protection Functions

2000

1000

K =2%

K = 40 %

Negative sequence current I (%)

500

200

100

Operation time (s)

K = 40 %

K = 70 %

40 60 80 100

Figure 3.11 – Inverse operation delay of current unbalance stage I

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

Table 3.9 – Parameters of the Current Unbalance Stage I

Parameter Value Unit Description Note

Status -

Blocked Start

Trip SCntr Cumulative start counter C TCntr Cumulative trip counter C SetGrp 1 or 2 Active setting group Set SGrpDI

DIx

VIx

LEDx

VOx Force Off

I2/In %In The supervised value. I2> %In Pick-up setting Set t> s Definite operation time (Type=DT) Set Type DT

INV K1 s Delay multiplier (Type =INV) Set

Current status of the stage

Digital signal to select the active setting

group None Digital input Virtual input LED indicator signal Virtual output

Force flag for status forcing for test

purposes. This is a common flag for all stages and output relays, too. Automatically reset by a 5-minute timeout.

Definite time

Inverse time (Equation)

CurrentUnbalanceChar

K = 70 %

K = 50 s

K =1s

>, I’2> (46)

F F

Set

For details of setting ranges see “Protection Stages” in Chapter 10. Set = An editable parameter (password needed) C = Can be cleared to zero F = Editable when force flag is on

865-UM001A-EN-P – July 2009

Protection Functions 3-17

Recorded Values of the Latest Eight Faults

Detailed information is available on the eight latest faults: Time

stamp, unbalance current, elapsed delay and setting group.

Table 3.10 – Parameters of the Current Unbalance Stage (8 latest faults) I2>, I’2> (46)

Parameter Value Unit Description yyyy-mm-dd Time stamp of the recording, date hh:mm:ss.ms Time stamp, time of day

Flt %In Maximum unbalance current EDly % Elapsed time of the operating time setting.

100% = trip

SetGrp

Undirectional earth fault protection is used for earth faults in low

Earth fault protection I

> (50N/51N)

impedance earthed networks. In high impedance earthed networks, compensated networks and isolated networks undirectional earth fault can be used as back-up protection.

The undirectional earth fault function is sensitive to the fundamental

frequency component of the residual current 3I the third harmonic is more than 60 dB. Whenever this fundamental value exceeds the user's pick-up setting of a particular stage, this stage picks up and a start signal is issued. If the fault situation remains on longer than the user's operation time delay setting, a trip signal is issued.

1 2

Active setting group during the fault

. The attenuation of

Figure 3.12 – Typical block diagram of the earth fault stage I0>

Figure 3.13 – Typical block diagram of the earth fault stages I

865-UM001A-EN-P – July 2009

>>, I0>>> and I0>>>>

3-18 Protection Functions

Figure 3.12 shows a functional block diagram of the I

> earth

overcurrent stage with definite time and inverse time operation time. Figure 3.13 shows a functional block diagram of the I I

>>>> earth fault stages with definite time operation delay.

>>, I0>>> and

Input Signal Selection

Each stage can be connected to supervise any of the following inputs and signals:

• Input I

• Calculated signal I

networks. I

• Calculated signal I’

networks. I’

Additionally the stage I measure current peaks to detect a restriking intermittent earth fault:

• I

01Peak

• I

02Peak

for all networks other than rigidly earthed

for rigidly and low impedance earthed

0Calc

= I

+ I

0Calc

= I’

+ IL3

for rigidly and low impedance earthed

0Calc

+ I’

+ I’L3

> have two more input signal alternatives to

to measure the peak value of input I01 to measure the peak value of input I02

Intermittent Earth Fault Detection

Short earth faults make the protection to start (pick up), but will not

cause trip. 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 will trip. By using input signals I

01Peak

or I

02Peak

a single one-millisecond current peak is enough to start the stage and increase the delay counter by 20 ms. For example if the operating time is 120 ms, and the time between two peaks does not exceed the intermittent time setting, the sixth peak will cause a trip.

Four Independent Undirectional Earth Fault Overcurrent Stages

There are four separately adjustable earth fault stages: I0>, I0>>,

>>>, and I0>>>>. The first stage I0> can be configured for definite

time (DT) or inverse 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.

865-UM001A-EN-P – July 2009

Protection Functions 3-19

Inverse Operation Time (I0> stage only)

Inverse delay means that the operation time depends on the amount

the measured current exceeds the pick-up setting. The bigger the fault current is the faster will be the operation. Accomplished inverse delays are available for the I

> stage. The inverse delay

types are described in Chapter 2. The relay will show a scaleable graph of the configured delay on the local panel display.

Inverse Time Limitation

The maximum measured secondary residual current is 10xI

maximum measured phase current is 50xI

. This limits the scope of

and

inverse curves with high pick-up settings. See Chapter 2 for more information.

Setting Groups

There are two settings groups available for each stage. Switching

between setting groups can be controlled by digital inputs, virtual inputs (mimic display, communication, logic) and manually.

Table 3.11 – Parameters of the Undirectional Earth Fault Stage I0> (50N/51N)

Parameter Value Unit Description Note

Status -

Blocked Start

Trip TripTime s Estimated time to trip SCntr Cumulative start counter Clr TCntr Cumulative trip counter Clr SetGrp 1 or 2 Active setting group Set SGrpDI

DIx

VIx

LEDx

VOx Force Off

Current status of the stage

Digital signal to select the active setting

group None Digital input Virtual input LED indicator signal Virtual output

Force flag for status forcing for test

purposes. This is a common flag for all stages and output relays, too. Automatically reset by a 5-minute timeout.

F F

Set

865-UM001A-EN-P – July 2009

3-20 Protection Functions

Table 3.11 – Parameters of the Undirectional Earth Fault Stage I

> (50N/51N)

(cont.)

Parameter Value Unit Description Note

Io Io2 IoCalc IoPeak Io2Peak I’oCalc Io> A Pick-up value scaled to primary value Io> pu Pick-up setting relative to the parameter

Curve

Type

t> s Definite operation time (for definite time

k> Inverse delay multiplier (for inverse time

Input Io1

Intrmt s Intermittent time Set Dly20x s Delay at 20xIset Dly4x s Delay at 4xIset Dly2x s Delay at 2xIset Dly1x s Delay at 1xIset A, B, C, D, E User's constants for standard equations.

pu The supervised value according the

parameter "Input" below.

"Input" and the corresponding CT value

Delay curve family: DT IEC IEEE IEEE2 RI PrgN

DT NI VI EI LTI Parameters

Io2 IoCalc Io1Peak Io2Peak I’oCalc

Definite time Inverse time. See “Inverse Time

Operation”.

Delay type.

Definite time Inverse time. See “Inverse Time

Operation”, Table 3.23.

only)

X1-7&8. See Chapter 9.

X1-9&10 IL1 + IL2 + IL3 X1-7&8 peak mode X1-9&10 peak mode I’L1 + I’L2 + I’L3

Type=Parameters. See “Inverse Time Operation”.

Set

For details of setting ranges see “Protection Stages” in Chapter 10. Set = An editable parameter (password needed) C = Can be cleared to zero F = Editable when force flag is on

865-UM001A-EN-P – July 2009

Protection Functions 3-21

Table 3.12 – Parameters of the Undirectional Earth Fault Stage I0>>, I0>>>, I

>>>> (50N/51N)

Parameter Value Unit Description Note

Status -

Blocked Start

Trip TripTime s Estimated time to trip SCntr Cumulative start counter Clr TCntr Cumulative trip counter Clr SetGrp 1 or 2 Active setting group Set SGrpDI

DIx

VIx

LEDx

VOx Force Off

Io Io2 IoCalc Io>> Io>>> Io>>>> Io>> Io>>> Io>>>> t> s Definite operation time (for definite time

Input Io1

pu The supervised value according the

A Pick-up value scaled to primary value

pu Pick-up setting relative to the parameter

Io2

IoCalc

I’oCalc

Current status of the stage

Digital signal to select the active setting

group None Digital input Virtual input LED indicator signal Virtual output

Force flag for status forcing for test

purposes. This is a common flag for all stages and output relays, too. Automatically reset by a 5-minute timeout.

parameter "Input" below.

"Input" and the corresponding CT value

only)

X1-7&8. See Chapter 4.

X1-9&10 IL1 + IL2 + IL3 I’L1 + I’L2 + I’L3

F F

Set

For details of setting ranges see “Protection Stages” in Chapter 10. Set = An editable parameter (password needed) C = Can be cleared to zero F = Editable when force flag is on

865-UM001A-EN-P – July 2009

3-22 Protection Functions

Recorded Values of the Latest Eight Faults

Detailed information is available on the eight latest earth faults: Time

stamp, fault current, elapsed delay and setting group.

Table 3.13 – Parameters of the Undirectional Earth Fault Stages (8 latest faults) I

Parameter Value Unit Description yyyy-mm-dd Time stamp of the recording, date hh:mm:ss.ms Time stamp, time of day

Flt pu Maximum earth fault current EDly % Elapsed time of the operating time setting.

SetGrp

The thermal overload function protects the transformer against

Thermal Overload Protection T> (49)

excessive temperatures.

>>, I0>>>, I0>>>> (50N/51N)

100% = trip

1 2

Active setting group during the fault

Thermal model

The temperature is calculated using rms values of phase currents and

a thermal model according IEC 60255-8. The rms value is calculated using harmonic components up to the 15

−

Trip time:

⋅= τ

−

alarmIkka

Alarm:

Trip:

Release time:

Trip release:

Start release:

T = Operation time τ

ln = Natural logarithm function I = Measured rms phase current (the max. value

= Thermal time constant tau (Setting value)

of three phase currents)

⋅Θ⋅=

⋅⋅=

mod

Ikka

mod

Ika ××= 95.0

⋅⋅Θ⋅=

−

alarmIka

×××= 95.0

(Alarm 60% = 0.6)

865-UM001A-EN-P – July 2009

Protection Functions 3-23

Ip =

Preload current,

temperature rise is 120%

IkI ××= θ (If

2.1=θ ). This

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

k = Overload factor (Maximum continuous

current), i.e. service factor. (Setting value)

kΘ

= Ambient temperature factor (Permitted

current due to tamb). See Figure 3.14

= The rated current (IN or I

MODE

= Relay cooling time constant (Setting value)

MOT

)

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 cΘ for thermal constant available to be used as cooling time constant, when current is less than 0.3xI

Heat Capacitance, Service Factor and Ambient Temperature

The trip level is determined by the maximum allowed continuous

current I the heat capacitance of the transformer. I service factor k and ambient temperature Θ and I

MAX70

corresponding to the 100 % temperature rise Θ

MAX

depends of the given

MAX

and settings I

AMB

according the following equation.

TRIP

MAX40

i.e.

IkkI ⋅⋅=

NMAX

The value of ambient temperature compensation factor kΘ depends

on the ambient temperature Θ

and settings I

AMB

MAX40

and I

MAX70

. See Figure 3.14. 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)  TAMB is +40 °C.

865-UM001A-EN-P – July 2009

3-24 Protection Functions

1.2

MAX40

1.0

MAX70

0.8

0.6

10 20 30 40 50 60 70 80

Figure 3.14 – Ambient Temperature Correction of the Overload Stage T>

AmbientTemperatureCompensation

(°C)

AMB

Example of a Behavior of the Thermal Model

Figure 3.15 shows an example of the thermal model behavior. In

this example τ = 30 minutes, k = 1.06 and kτ = 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 0.85xI ture rise starts to approach value (0.85/1.06) time constant. At time=300 min, the temperature is about 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.

and the tempera-

= 64 % according the

Initial Temperature Rise After Restart

When the relay is switched on, an initial temperature rise of

70 % is used. Depending of 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

865-UM001A-EN-P – July 2009

its start signal.

Protection Functions 3-25

Figure 3.15 – Example of the thermal model behavior

865-UM001A-EN-P – July 2009

3-26 Protection Functions

Table 3.14 – Parameters of the Thermal Overload Stage T> (49)

Parameter Value Unit Description Note

Status -

Blocked Start

Trip Time hh:mm:ss Estimated time to trip SCntr Cumulative start counter C TCntr Cumulative trip counter C Force Off

T % Calculated temperature rise. Trip

MaxRMS Arms Measured current. Highest of the

Imax A kxIgn. Current corresponding to the

k> xIn Allowed overload (service factor) Set Alarm % Alarm level Set tau min Thermal time constant Set ctau xtau Coefficient for cooling time constant.

kTamb xIn Ambient temperature corrected max.

Imax40 %In

Imax70 %In

Tamb

Samb

n/a

ExtAI1...16

Current status of the stage

Force flag for status forcing for test

purposes. This is a common flag for all stages and output relays, too. Automatically reset by a 5-minute timeout.

limit is 100 %.

three phases.

100 % temperature rise.

Default = 1.0

allowed continuous current

Allowed load at Tamb +40 °C. Default = 100 %.

Allowed load at Tamb +70 °C. Ambient temperature. Editable

°C

Samb=n/a. Default = +40 °C Sensor for ambient temperature No sensor in use for Tamb External Analogue input 1...16

F F

Set

For details of setting ranges see “Protection Stages” in Chapter 10. Set = An editable parameter (password needed) C = Can be cleared to zero F = Editable when force flag is on

The circuit breaker failure protection can be used to trip any upstream

Circuit-breaker failure protection CBFP (50BF)

The operation of the circuit-breaker failure protection (CBFP) is

865-UM001A-EN-P – July 2009

circuit breaker (CB), if the fault has not disappeared within a given time after the initial trip command. A different output contact of the relay must be used for this backup trip.

based on the supervision of the signal to the selected trip relay and the time the fault remains on after the trip command.

Protection Functions 3-27

If this time is longer than the operating time of the CBFP stage, the

CBFP stage activates another output relay, which will remain activated until the primary trip relay resets.

The CBFP stage is supervising all the protection stages using the

same selected trip relay, since it supervises the control signal of this relay. See Chapter 5 for details about the output matrix and the trip relays.

Table 3.15 – Parameters of the Circuit Breaker Failure Stage CBFP (50BF)

Parameter Value Unit Description Note

Status -

Blocked Start

Trip SCntr Cumulative start counter C TCntr Cumulative trip counter C Force Off

CBrelay

2 t> s Definite operation time. Set

Current status of the stage

Force flag for status forcing for test

purposes. This is a common flag for all stages and output relays, too. Automatically reset by a 5-minute timeout.

The supervised output relay 

Relay T1 Relay T2

F F

Set

For details of setting ranges see “Protection Stages” in Chapter 10. Set = An editable parameter (password needed) C = Can be cleared to zero F = Editable when force flag is on

 This setting is also used by the circuit breaker condition monitoring. See Chapter 3.

Recorded Values of the Latest Eight Faults

Detailed information is available on the eight latest faults: Time

stamp and elapsed delay.

Table 3.16 – Recorded values of the Circuit Breaker Failure Stage (8 latest faults) CBFP (50BF)

Parameter Value Unit Description

yyyy-mm-dd Time stamp of the recording, date hh:mm:ss.ms Time stamp, time of day EDly % Elapsed time of the operating time setting.

100% = trip

865-UM001A-EN-P – July 2009

3-28 Protection Functions

NOTE: This protection function needs optional hardware in slot X6.

Arc fault protection (50ARC/50NARC) (optional)

Arc protection is used for fast arc protection. The function is based

More details of the hardware can be found under “Optional TwoChannel Arc Protection Card” in Chapter 9, and “Arc Protection Interface (Option)” in Chapter 10.

on simultaneous light and current measurement. Special arc sensors are used to measure the light of an arc.

Three Stages for Arc Faults

There are three separate stages for the various current inputs:

ArcI> for phase-to-phase arc faults. Current inputs

•

IL1, IL2, IL3 are used.

ArcI’> for phase-to-phase arc faults. Current inputs

•

I’L1, I’L2, I’L3 are used.

ArcI01> for phase-to-earth arc faults. Current input

•

is used.

ArcI02> for phase-to-earth arc faults. Current input

•

is used.

Light Channel Selection

The light information source to the stages can be selected from the

following list.

–

•

S1 Light sensor S1.

•

S2 Light sensor S2.

•

S1/S2 Either one of the light sensors S1 or S2.

•

BI Binary input of the arc card. 48 Vdc.

•

S1/BI Light sensor S1 or the binary input.

•

S2/BI Light sensor S2 or the binary input.

•

S1/S2/BI Light sensor S1 or S2 or the binary input.

No sensor selected. The stage will not work.

Binary Input

The binary input (BI) on the arc option card (see Chapter 8) can be

used to get the light indication from another relay to build selective arc protection systems. The BI signal can also be connected to any of the output relays, BO, indicators etc. offered by the output matrix (See Chapter 5). BI is a dry input for 48 Vdc signal from binary outputs of other Allen-Bradley relays or dedicated arc protection devices by Allen-Bradley.

865-UM001A-EN-P – July 2009

Protection Functions 3-29

Binary Output

The binary output (BO) on the arc option card (see Chapter 8) can be

used to give the light indication signal or any other signal or signals to another relay's binary input to build selective arc protection systems. Selection of the BO connected signal(s) is done with the output matrix (See Chapter 5). BO is an internally wetted 48 Vdc signal for BI of other Allen-Bradley relays or dedicated arc protection devices by Allen-Bradley.

Delayed Light Indication Signal

There is a delayed light indication output signal available for

building selective arc protection systems. Any light source combination and a delay can be configured. The resulting signal is available in the output matrix to be connected to BO, output relays etc.

Pick Up Scaling

The per unit (pu) values for pick up setting are based on the current

transformer values.

ArcI>: 1 pu = 1xI ArcI’>: 1 pu = 1xI’ ArcI

>: 1 pu = 1xI

for input I

ArcI

>: 1 pu = 1xI

for input I

= rated phase current CT value

= rated residual current CT value

01N

= rated residual current CT value

02N

Table 3.17 – Parameters of Arc Protection Stages Arcl>, Arcl’>, Arcl01A, Arcl

> (50 ARC / 50N ARC)

Parameter Value Unit Description Note

Status –

Start Trip

LCntr Cumulative light indication counter. S1,

SCntr Cumulative light indication counter for

TCntr Cumulative trip counter C Force Off

ILmax I’Lmax Io1 Io2

Value of the supervised signal

Current status of the stage

Light detected according ArcIn Light and overcurrent detected

S2 or BI.

the selected inputs according parameter ArcIn

Force flag for status forcing for test

purposes. This is a common flag for all stages and output relays, too. Automatically reset by a 5-minute timeout.

Stage ArcI> Stage ArcI’> Stage ArcI Stage ArcI

F F C

Set

865-UM001A-EN-P – July 2009

3-30 Protection Functions

Table 3.17 – Parameters of Arc Protection Stages Arcl>, Arcl’>, Arcl Arcl

> (50 ARC / 50N ARC) (cont.)

Parameter Value Unit Description Note

ArcI> ArcI’> ArcIo1> ArcIo2> ArcIn

Pick up setting xI

Pick up setting xI’

Pick up setting xI

Light indication source selection – S1 S2 S1/S2 BI

No sensor selected Sensor 1 at terminals X6:4-5 Sensor 2 at terminals X6:6-7

Terminals X6:1-3

01N

02N

Set

S1/BI S2/BI S1/S2/BI

Delayed light signal output

Ldly s Delay for delayed light output signal Set LdlyCn

– S1 S2 S1/S2 BI

Light indication source selection

No sensor selected Sensor 1 at terminals X6:4-5 Sensor 2 at terminals X6:6-7

Terminals X6:1-3

Set

S1/BI S2/BI S1/S2/BI

For details of setting ranges see “Protection Stages” in Chapter 10. Set = An editable parameter (password needed) C = Can be cleared to zero F = Editable when force flag is on

Recorded Values of the Latest Eight Faults

Detailed information is available on the eight latest faults: Time

stamp, fault type, fault value, load current before the fault and elapsed delay.

Table 3.18 – Recorded Values of the Arc Protection Stages Arcl>, Arcl’>, Arcl

A, Arcl02> (50 ARC / 50N ARC)

Parameter Value Unit Description

yyyy-mm-dd Time stamp of the recording, date hh:mm:ss.ms Time stamp, time of day Type pu Fault type value. Only for ArcI> stage. Flt pu Fault value Load pu Pre fault current. Only for ArcI> stage. EDly % Elapsed time of the operating time setting.

100% = trip

865-UM001A-EN-P – July 2009

Protection Functions 3-31

Programmable Stages (99) For special applications the user can built his own protection stages

by selecting the supervised signal and the comparison mode.

The following parameters are available:

Priority

•

If operation times less than 60 milliseconds are needed select 10 ms. For operation times under one second 20 ms is recommended. For longer operation times and THD signals 100 ms is recommended.

Link

•

The name of the supervised signal (see table below).

Cmp

•

Compare mode. ‘>’ for over or ‘<’ for under comparison.

Pick-up

•

Limit of the stage. The available setting range and the unit depend on the selected signal.

•

Definite time operation delay

Hyster

•

Dead band (hysteresis)

NoCmp

•

Only used with compare mode under (‘<’). This is the limit to start the comparison. Signal values under NoCmp are not regarded as fault.

Available Signals to be Supervised by the Programmable Stages

Alarm stages link signals Task interval

IL1 – IL3, IL1W-IL3W, I’L1W-I’L3W, IL, I’L 100ms Io, Io2, Iocalc, I’oCalc, I1, I2, I2/I1, I2/In, I’1,

I’2, I’2/I’1, I’2/In, dIL1, dIL2, dIL3 THDIL1, THDIL2, THDIL3

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 two settings groups available. Switching between setting

groups can be controlled by digital inputs, virtual inputs (mimic display, communication, logic) and manually.

There are two identical stages available with independent setting

parameters.

865-UM001A-EN-P – July 2009

3-32 Protection Functions

Table 3.19 – Parameters of the Programmable Stages PrgN (99)

Parameter Value Unit Description Note

Status -

Blocked Start

Trip SCntr Cumulative start counter C TCntr Cumulative trip counter C SetGrp 1 or 2 Active setting group Set SGrpDI

DIx

VIx

LEDx

VOx Force Off

Link (See table

above) (See table

above) Cmp

Pickup Pick up value scaled to primary level Pickup pu Pick up setting in pu Set t s Definite operation time. Set Hyster % Dead band setting Set NoCmp pu Minimum value to start under

Set = An editable parameter (password needed) C = Can be cleared to zero F = Editable when force flag is on

Value of the supervised signal

Current status of the stage

Digital signal to select the active

setting group None Digital input Virtual input LED indicator signal Virtual output

Force flag for status forcing for test

purposes. This is a common flag for all stages and output relays, too. Automatically reset by a 5-minute timeout.

Name for the supervised signal Set

Mode of comparison

Over protection Under protection

comparison. (Mode='<')

Recorded values of the latest eight faults

F F

Set

Detailed information is available on the eight latest faults: Time

stamp, fault value and elapsed delay.

Table 3.20 – Recorded Values of the Programmable Stages PrgN (99)

Parameter Value Unit Description

yyyy-mm-dd Time stamp of the recording, date hh:mm:ss.ms Time stamp, time of day Flt pu Fault value EDly % Elapsed time of the operating time setting.

100% = trip

SetGrp 1 2 Active setting group during fault

865-UM001A-EN-P – July 2009

Protection Functions 3-33

Inverse Time Operation The inverse time operation – i.e. inverse delay minimum time (IDMT)

type of operation – is available for several protection functions. The common principle, formula and graphic representations of the available inverse delay types are described in this chapter.

Inverse delay means that the operation time depends on the measured

real time process values during a fault. When utilizing an overcurrent stage using an inverse delay, a large fault current results in faster operation. The alternative to inverse delay is definite delay. With definite delay a preset time is used and the operation time does not depend on the size of a fault.

Stage Specific Inverse Delay

Some protection functions have their own specific type of inverse

delay. Details of these dedicated inverse delays are described with the appropriate protection function.

Operation Modes

There are three operation modes to use the inverse 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 “Standard Inverse Delays IEC, IEEE, IEEE2, RI”.

 Standard delay formula with 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 “Parameter setting using IEC, IEEE and IEEE2 Equations”.

 Fully programmable inverse delay characteristics

Building the characteristics by setting 16 [current, time] points. The relay interpolates the values between given points with 2nd degree polynomials. This mode is activated by setting curve family to ‘PrgN’'. There are maximum three different programmable curves available at the same time. Each programmed curve can be used by any number of protection stages. See “Programmable Inverse Time Curves”.

Local Panel Graph

The relay will show a graph of the currently used inverse delay on

the local panel display. Up and down keys can be used for zooming. Also the delays at 20xI

865-UM001A-EN-P – July 2009

SET

, 4xI

and 2xI

SET

are shown.

SET

3-34 Protection Functions

Inverse Time Setting Error Signal

If there are any errors in the inverse delay configuration the

appropriate protection stage will use definite time delay.

There is a signal ‘Setting Error’ available in output matrix, which

indicates three different situations:

1. Settings are currently changed with SetPointPS or local panel, and there is temporarily an illegal combination of curve/delay/points. For example if previous settings were IEC/NI and then curve family is changed to IEEE, the setting error will active, 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 will release.

 There are errors in formula parameters A…E, and the device

is not able to build the delay curve

 There are errors in the programmable curve configuration

and the device is not able to interpolate values between the given points.

Limitation

The maximum measured phase current is 50xIN and the maximum

directly measured earth fault current is 5xI inverse curves when the setting is more than 2.5xI stages and earth fault stages using I fault stages using I

input or I

0Calc

input). The IN and I

depend on the order code (See Chapter 12). The table below gives the limit values in secondary amperes.

Example of limitation:

CT = 750/5 I

CT Secondary scaled I

= 577 A = 100/1 (a cable CT for I0)

is now 3.85A

GNsec

For overcurrent stage I> the table below gives 12.5 A. Thus the

maximum setting for I> stage giving full inverse delay range is 12.5 A / 3.85 A = 3.25 xI

For earth fault stage I

Thus the maximum setting for I

> and input I01 the table below gives 0.25 A.

> stage giving full inverse delay

range is 0.25A / 1 A = 0.25 pu. This equals a 25A primary earth fault current.

. This limits the scope of

(overcurrent

input) or 0.25xI

01N

and I

(earth

02N

When using input signal I

the corresponding setting is 12.5A / 1 A

0Calc

= 12.5 pu. This equals a 9375A of primary earth fault current.

865-UM001A-EN-P – July 2009

Protection Functions 3-35

Table 3.21 – Maximum Secondary Scaling Settings

RATED INPUT

Maximum secondary scaled setting enabling inverse delay times up to 20x setting

Order code IL I’L I01 I02 IL1, IL2, IL3

& I

0Calc

Allen-Bradley 865-1_ 1 1 2.5 A 2.5 A Allen-Bradley 865-3_ 1 5 2.5 A 12.5 A Allen-Bradley 865-4_ 5 1 12.5 A 2.5 A Allen-Bradley 865-5_ 5 5 12.5 A 12.5 A Allen-Bradley 865-_A 5 5 1.25 A 1.25 A Allen-Bradley 865-_B 5 1 1.25 A 0.25 A Allen-Bradley 865-_C 1 5 0.25 A 1.25 A Allen-Bradley 865-_D 1 1 0.25 A 0.25 A

I’

, I’L2, I’L3

& I’

0Calc

I02

Standard Inverse Delays IEC, IEEE, IEEE2, RI

The available standard inverse delays are divided in four categories

IEC, IEEE, IEEE2 and RI called delay curve families. Each category of family contains a set of different delay types according to the following table.

Inverse Time Setting Error Signal

The inverse time setting error signal will be activated, if the delay

category is changed and the old delay type doesn't exist in the new category.

Limitations

The minimum definite time delay start latest, when the measured

value is twenty times the setting. However, there are limitations at high setting values due to the measurement range.

865-UM001A-EN-P – July 2009

3-36 Protection Functions

Table 3.22 – Available Standard Delay Families and Types

Curve family

Delay type

DT Definite time X

NI1 Normal inverse X X

VI Very inverse X X X

EI Extremely inverse X X X

LTI Long time inverse X X

LTEI Long time extremely inverse X

LTVI Long time very inverse X

MI Moderately inverse X X

STI Short time inverse X

STEI Short time extremely inverse X

RI Old ASEA type X

RXIDG Old ASEA type X

IEC

IEEE

IEEE2

IEC Inverse Time Operation

The operation time depends on the measured value and other

parameters according Equation 6. 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 6

pickup

⎛ ⎜ ⎜ ⎝

t = Operation delay in seconds k = User’s multiplier I = Measured value I

= User’s pick up setting

pickup

A, B = Constants parameters according Table 3.23.

There are three different delay types according IEC 60255-3, Normal

inverse (NI), Extremely inverse (EI), Very inverse (VI) and a VI extension, Long time inverse (LTI).

⎞ ⎟ ⎟ ⎠

1−

865-UM001A-EN-P – July 2009

Protection Functions 3-37

Table 3.23 – Constants for IEC Inverse Delay Equation

Delay type

NI Normal inverse 0.14 0.02 EI Extremely inverse 80 2 VI Very inverse 13.5 1

LTI Long time inverse 120 1

Parameter

A B

Example for Delay type "Normal inverse (NI) ":

k = 0.50 I = 4 pu (constant current) I

= 2 pu

pickup

A = 0.14 B = 0.02

14.050.0

⋅

02.0

⎞

⎛ ⎜

⎝

−

⎟

⎠

0.5

The operation time in this example will be 5 seconds. The same

result can be read from Figure 3.16.

Figure 3.16 – IEC Normal Inverse Delay Figure 3.17 – IEC Extremely Inverse Delay

865-UM001A-EN-P – July 2009

3-38 Protection Functions

Figure 3.18 – IEC Very Inverse Delay Figure 3.19 – IEC Long Time Inverse Delay

IEEE/ANSI Inverse Time Operation

There are three different delay types according IEEE Std C37.112-

1996 (MI, VI, EI) and many de facto versions according Table 3.24. The IEEE standard defines inverse delay for both trip and release operations. However, in the Allen-Bradley relay only the trip time is

The operation delay depends on the measured value and other

Equation 7:

inverse according the standard but the release time is constant.

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.

⎡ ⎢ ⎢

= B

⎢ ⎢ ⎢ ⎢

⎣

pickup

⎞ ⎟

−

⎟ ⎠

⎛ ⎜ ⎜ ⎝

⎤ ⎥ ⎥

⎥ ⎥

⎦

t = Operation delay in seconds k = User’s multiplier I = Measured value I

= User’s pick up setting

pickup

A,B,C = Constant parameter according to Table 3.24

865-UM001A-EN-P – July 2009

Protection Functions 3-39

Table 3.24 – Constants for IEEE/ASI Inverse Delay Equation

Delay type

LTI Long time inverse 0.086 0.185 0.02 LTVI Long time very inverse 28.55 0.712 2 LTEI Long time extremely inverse 64.07 0.250 2

MI Moderately inverse 0.0515 0.1140 0.02 VI Very inverse 19.61 0.491 2 EI Extremely inverse 28.2 0.1217 2

STI Short time inverse 0.16758 0.11858 0.02

STEI Short time extremely inverse 1.281 0.005 2

A B C

Parameter

Example for Delay type "Moderately inverse (MI)":

k = 0.50 I = 4 pu I

pickup

= 2 pu A = 0.0515 B = 0.114 C = 0.02

⎡ ⎢

0515.0

⎢

⋅=t

50.0

⎢

⎞

⎛

⎢

⎟

⎜

⎢

⎠

⎝

⎣

02.0

−

⎤ ⎥ ⎥ ⎥

9.11140.0

⎥ ⎥

⎦

The operation time in this example will be 1.9 seconds. The same result

can be read from Figure 3.23.

Figure 3.20 – ANSI/IEEE Long Time Figure 3.21 – ANSI/IEEE Long Time Inverse Delay Very Inverse Delay

865-UM001A-EN-P – July 2009

3-40 Protection Functions

Figure 3.22 – ANSI/IEEE Long Time Figure 3.23 – ANSI/IEEE Moderately Extremely Inverse Delay Inverse Delay

Figure 3.24 – ANSI/IEEE Short Time Figure 3.25 – ANSI/IEEE Short Time Inverse Delay Extremely Inverse Delay

865-UM001A-EN-P – July 2009

Protection Functions 3-41

IEEE2 Inverse Time Operation

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 8, which in the 865 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 Table 3.25. The old

electromechanical induction disc relays have inverse delay for both trip and release operations. However, in the Bulletin 865 only the trip time is inverse, the release time being constant.

The operation delay depends on the measured value and other

parameters according Equation 8. 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 8

⎡ ⎢ ⎢

Akt

⎢ ⎢ ⎢

⎣

t = Operation delay in seconds k = User’s multiplier I = Measured value I

pickup

A,B,C,D = Constant parameter according Table 3.25

Table 3.25 – Constants for IEEE2 Inverse Delay Equation

Delay type

MI Moderately inverse 0.1735 0.6791 0.8 -0.08 0.1271 NI Normally inverse 0.0274 2.2614 0.3 -.1899 9.1272 VI Very inverse 0.0615 0.7989 0.34 -0.284 4.0505 EI Extremely inverse 0.0399 0.2294 0.5 3.0094 0.7222

⎛

⎜ ⎜

pickup

⎝

= User’s pick up setting

⎞ ⎟

− ⎟

⎠

⎛

⎜ ⎜ ⎝

−

A B C D E

⎞ ⎟ ⎟ ⎠

Parameter

⎤ ⎥

⎛

⎜ ⎜

pickuppickup

⎝

⎥ ⎥

⎞

⎥

⎟

−

⎥

⎟ ⎠

⎦

865-UM001A-EN-P – July 2009

3-42 Protection Functions

Example for Delay type "Moderately inverse (MI)":

k = 0.50 I = 4 pu I

= 2 pu

pickup

A = 0.1735 B = 0.6791 C = 0.8 D = -0.08 E = 0.127

⎡ ⎢ ⎢

1735.05.0

⎢ ⎢

⎣

The operation time in this example will be 0.38 seconds. The same result

can be read from Figure 3.26.

6791.0

+⋅=t

⎛

−

⎜

⎝

⎞

8.0

⎟ ⎠

08.0

−

⎛

−

⎜

⎝

⎞

8.0

⎟ ⎠

127.0

⎛

−

⎜

⎝

⎤ ⎥ ⎥

⎥

⎞

8.0

⎟

⎥

⎠

⎦

38.0

Figure 3.26 – IEEE2 Moderately Figure 3.27 – IEEE2 Normal Inverse Delay Inverse Delay

865-UM001A-EN-P – July 2009

Protection Functions 3-43

Figure 3.28 – IEEE2 Very Inverse Delay Figure 3.29 – IEEE2 Extremely Inverse Delay

RI and RXIDG type Inverse Time Operation

These two inverse delay types have their origin in old ASEA (ABB)

earth fault relays.

The operation delay of types RI and RXIDG depends on the

measured value and other parameters according Equation 9 and Equation 10. 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 9 – RI

−

339.0

⎛ ⎜ ⎜

pickup

⎝

236.0

⎞

⎟ ⎟ ⎠

865-UM001A-EN-P – July 2009

3-44 Protection Functions

Equation 10 – RXIDG

t ln35.18.5 −=

RXIDG

pickup

t = Operation delay in seconds k = User’s multiplier I = Measured value I

= User’s pick up setting

pickup

Example for Delay type RI : k = 0.50 I = 4 pu I

= 2 pu

pickup

5.0

339.0

236.0

−

⎞

⎛

⎟

⎜

⎠

⎝

3.2

The operation time in this example will be 2.3 seconds. The same result can be read from Figure 3.30.

Example for Delay type RXIDG:

k = 0.50 I = 4 pu

= 2 pu

pickup

RXIDG

−=

ln35.18.5 =

⋅

9.3

25.0

The operation time in this example will be 3.9 seconds. The same result can be read from Figure 3.31.

865-UM001A-EN-P – July 2009

Protection Functions 3-45

Figure 3.30 –Inverse Delay of type RI Figure 3.31 – Inverse Delay of type RXIDG

Parameter Setting using IEC, IEEE and IEEE2 Equations

This mode is activated by setting delay type to ‘Parameters’, and then

editing the delay function constants, i.e. 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 for GE-IAC51 delay type inverse:

k = 0.50 I = 4 pu I A = 0.2078 B = 0.8630 C = 0.8000 D = –0.4180 E = 0.1947

= 2 pu

pickup

⎡ ⎢ ⎢ ⎢ ⎢

⎢

⎣

⎤

−

2078.05.0 4

⎛

−

⎜

⎝

8630.0

+⋅=t

⎞

8.0

⎟ ⎠

4180.0

⎛ ⎜

⎝

⎞

−

8.0

⎟ ⎠

1947.0

⎛

−

⎜

⎝

⎥ ⎥

37.0

⎥

⎞

8.0

⎥

⎟

⎥

⎠

⎦

The operation time in this example will be 0.37 seconds. The

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

865-UM001A-EN-P – July 2009

3-46 Protection Functions

Inverse Time Setting Error Signal

The inverse time setting error signal will become active, if

interpolation with the given parameters is not possible. See Chapter 2 for more details.

Limitations

The minimum definite time delay start latest, when the measured

value is twenty times the setting. However, there are limitations at high setting values due to the measurement range. See Chapter 2 for more details.

Programmable Inverse Time Curves

The [current, time] curve points are programmed only using SetPointPS PC program. There are some rules for defining the curve points:

• Configuration must begin from the topmost line

• Line order must be as follows: the smallest current (longest

operation time) on the top and the largest current (shortest operation time) on the bottom

• All unused lines (on the bottom) should be filled with [1.00

0.00s]

• Device must be rebooted to initialize the settings.

Here is an example configuration of curve points:

Table 3.26 – Curve Point Configurations

Point Current I/I

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

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

pick-up

Operation delay

865-UM001A-EN-P – July 2009

Protection Functions 3-47

Inverse Time Setting Error Signal

The inverse time setting error signal will be activated, if interpolation

with the given points fails. See section “Inverse Time Operation” for more details.

Limitations

The minimum definite time delay start latest, when the measured

value is twenty times the setting. However, there are limitations at high setting values due to the measurement range. See section “Inverse Time Operation” in Chapter 2 for more details.

865-UM001A-EN-P – July 2009

3-48 Protection Functions

865-UM001A-EN-P – July 2009

Chapter 4

Supporting Functions

Event Log

Event log is a buffer of event codes and time stamps including date

and time. For example each start-on, start-off, trip-on or trip-off of any protection stage has a unique event number code. Such a code and the corresponding time stamp are called an event.

As an example of information included with a typical event an

overvoltage trip event of the first 59 stage U> is shown in the following table.

Table 4.1 – Typical Overvoltage Trip Event

Event Description Local Panel

Code: 30E2 Channel 30, event 2 Yes Yes U> trip on Event text Yes No

112.0 %Ugn Fault value Yes No 2007-01-31 Date Yes Yes 08:35:13.413 Time Yes Yes Type: U12,23,31 Fault type Yes No

Communication

Protocols

Events are the major data for a control system. Control systems are

reading events using any of the available communication protocols. Event log can also be scanned using the front panel or using SetPointPS. With SetPointPS, the events can be stored to a file especially in case the relay is not connected to any control system.

Only the latest event can be read when using communication

protocols or SetPointPS. Every reading increments the internal read pointer to the event buffer. (In case of communication error, the latest event can be reread any number of times using another parameter.) On the local panel scanning the event buffer back and forth is possible.

Event enabling/masking

There is room for 50 latest events in the event buffer. The oldest one

will be overwritten, when a new event does occur. The shown resolution of a time stamp is one millisecond, but the actual resolution depends of the particular function creating the event. For example most protection stages create events with 10 ms or 20 ms resolution. The absolute accuracy of all time stamps depends on the time synchronizing of the relay. See page 4-11 for system clock synchronizing.

Events can be masked, which prevents their inclusion in the event

buffer.

865-UM001A-EN-P – July 2009

4-2 Supporting Functions

Event Buffer Overflow

The normal procedure is to poll events from the device all the time.

If this is not done, the event buffer will eventually overflow. On the local screen this is indicated with string "OVF" after the event code.

Table 4.2 – Setting Parameters for Events

Parameter Value Description Note

Count Number of events ClrEn

– Clear

Order

Old-New New-Old

FVSca

Pri Display Alarms

FORMAT OF EVENTS ON THE LOCAL DISPLAY

Code: CHENN CH = event channel, NN=event code Event description Event channel and code in plain text yyyy-mm-dd Date (for available date formats see “System

hh:mm:ss.nnn Time

Off

Clear event buffer Set

Order of the event buffer for local display

Scaling of event fault value Per unit scaling Primary scaling Alarm pop-up display is enabled No alarm display

Clock and Synchronization” on page 4-11)

Set

Disturbance Recorder The disturbance recorder can be used to record all the measured

signals, that is, currents, voltages and the status information of digital inputs (DI) and digital outputs (DO). The digital inputs include also the arc protection signals S1, S2, BI and BO, if the optional arc protection is available.

Triggering the Recorder

Reading Recordings

The recordings can be uploaded, viewed and analyzed with the

For more details, please see a separate SetPointPS manual.

The recorder can be triggered by any start or trip signal from any protection stage or by a digital input. The triggering signal is selected in the output matrix (vertical signal DR). The recording can also be triggered manually. All recordings are time stamped.

SetPointPS program. The recording is in COMTRADE format. This means that also other programs can be used to view and analyze the recordings made by the relay.

865-UM001A-EN-P – July 2009

Supporting Functions 4-3

Number of Channels

At the maximum, there can be 12 recordings, and the maximum

selection of channels in one recording is also 12 (limited in waveform recording). The digital inputs reserve one channel (includes all the inputs). Also the digital outputs reserve one channel (includes all the outputs). If digital inputs and outputs are recorded, there will be still 10 channels left for analogue waveforms.

Available Channels

The following channels i.e. signals can be linked to a disturbance

recorder:

Table 4.3 – Available Channels

Channel Description

IL1, IL2, IL3 Phase current Yes I’L1, I’L2, I’L3 Phase current Yes Io1, Io2 Measured residual current Yes f Frequency – IoCalc Phasor sum Io = (IL1+IL2+IL3)/3 – I’oCalc Phasor sum Io = (I’L1+I’L2+I’L3)/3 – I1, I’1 Positive sequence current – I2, I’2 Negative sequence current – I2/I1, I’2/I’1 Relative current unbalance – I2/In, I’2/I’n Current unbalance [xIGN] – IL Average (IL1 + IL2 + IL3)/3 – I’L Average (I’L1 + I’L2 + I’L3)/3 – DO Digital outputs Yes DI Digital inputs Yes THDIL1 Total harmonic distortion of IL1 – THDI’L1 Total harmonic distortion of I’L1 – THDIL2 Total harmonic distortion of IL2 – THDI’L2 Total harmonic distortion of I’L2 – THDIL3 Total harmonic distortion of IL3 – THDI’L3 Total harmonic distortion of I’L3 – IL1RMS IL1 RMS for average sampling – IL2RMS IL2 RMS for average sampling – IL3RMS IL3 RMS for average sampling – ILmin I’Lmin ILmax I’Lmax ΔIL1,ΔIL2,ΔIL3 IL1w,IL2w,IL3w I’L1w,I’L2w,I’L3w

Available for

waveform

865-UM001A-EN-P – July 2009

4-4 Supporting Functions

Table 4.4 – Disturbance Recorder Parameters

Parameter Value Unit Description Note

Mode

Saturated Overflow

32/cycle 16/cycle 8/cycle 1/10ms 1/20ms 1/200ms 1/1s 1/5s 1/10s 1/15s 1/30s

1/1min Time s Recording length Set PreTrig % Amount of recording data before

MaxLen s Maximum time setting.

Status

–

Run

Trig

FULL ManTrig

–

Trig ReadyRec n/m n = Available recordings

Set = An editable parameter (password needed)

 This is the fundamental frequency rms value of one cycle updated every 10 ms.  This is the fundamental frequency rms value of one cycle updated every 20 ms.

Behaviour in memory full

Set

situation: No more recordings are accepted The oldest recorder will be

overwritten

Sample rate

Set Waveform Waveform Waveform One cycle value  One cycle value  Average Average Average Average Average Average Average

Set the trig moment

This value depends on sample rate, number and type of the selected channels and the configured recording length.

Status of recording

Not active Waiting a triggering Recording Memory is full in saturated mode

Manual triggering Set

m = maximum number of recordings

The value of 'm' depends on sample rate, number and type of the selected channels and the configured recording length.

865-UM001A-EN-P – July 2009

Supporting Functions 4-5

Table 4.4 – Disturbance Recorder Parameters (cont.)

Parameter Value Unit Description Note

AddCh IL1, IL2, IL3

I’L1, I’L2, I’L3 Io1, Io2 f IoCalc I1, I2, I2/I1 I2/In, IoCalc I’1, I’2, I’2/I’1 I’2/I’n, I’oCalc IL, I’L DO, DI THDIL1 THDIL2 THDIL3 IL1RMS IL2RMS IL3RMS ILmin, ILmax I’Lmin I’Lmax ΔIL1, ΔIL2, ΔIL3 IL1w, IL2w,

IL3w I’L1w, I’L2w,

I’L3w

ClrCh –

Clear

(Ch) List of selected channels

Set = An editable parameter (password needed)

 This is the fundamental frequency rms value of one cycle updated every 10 ms.  This is the fundamental frequency rms value of one cycle updated every 20 ms.

Add one channel. Maximum

simultaneous number of channels is 12.

Remove all channels Set

Set

Current Transformer

The relay supervise the external wiring between the relay terminals

Supervision

and current transformers (CT) and the CT them selves. Furthermore, this is a safety function as well, since an open secondary of a CT, causes dangerous voltages.

The CT supervisor function measures phase currents. If one of the

three phase currents drops below I current is exceeding the I

> setting, the function will issue an alarm

max

< setting, while another phase

min

after the operation delay has elapsed.

865-UM001A-EN-P – July 2009

4-6 Supporting Functions

Table 4.5 – Setting Parameters of CT, CT’ Supervisor – CTSV ( )

Parameter Value Unit Default Description

Imax> 0.0 … 10.0 xIn 2.0 Upper setting for CT supervisor Imin< 0.0 … 10.0 xIn 0.2 Lower setting for CT supervisor t> 0.02 … 600.0 s 0.10 Operation delay CT on On; Off - On CT supervisor on event CT off On; Off - On CT supervisor off event

Table 4.6 – Measured and Recorded Values of CT, CT’ Supervisor – CTSV ( )

Parameter Value Unit Description

ILmax A Maximum of phase currents Measured

value

Display Imax>,

Recorded values

ILmin A Minimum of phase currents

A Setting values as primary Imin< Date - Date of CT supervision alarm Time - Time of CT supervision alarm Imax A Maximum phase current Imin A Minimum phase current

values

The relay has a condition monitoring function that supervises the

Circuit Breaker Condition Monitoring

wearing of the circuit-breaker. The condition monitoring can give alarm for the need of CB maintenance well before the CB condition is critical.

The CB wear function measures the breaking current of each CB

pole separately and then estimates the wearing of the CB accordingly the permissible cycle diagram. The breaking current is registered when the trip relay supervised by the circuit breaker failure protection (CBFP) is activated. (See Chapter 2 for CBFP and the setting parameter "CBrelay".)

Breaker Curve and its Approximation

The permissible cycle diagram is usually available in the

documentation of the CB manufacturer (Figure 4.1). The diagram specifies the permissible number of cycles for every level of the breaking current. This diagram relates to the parameter settings for the breaker condition monitoring function with maximum eight [current, cycles] points. See Table 4.7. If less than eight points needed, the unused points are set to [I the maximum breaking capacity.

, 1], where I

BIG

is more than

BIG

If the CB wearing characteristics or part of it is a straight line on a

log/log graph, the two end points are enough to define that part of the characteristics. This is because the relay is using logarithmic interpolation for any current values falling in between the given current points 2...8.

865-UM001A-EN-P – July 2009

Supporting Functions 4-7

The points 4...8 are not needed for the CB in Figure 4.1. Thus

they are set to 100 kA and one operation in the table to be discarded by the algorithm.

100000

10000

1000

100

Number of permitted operations

100 200 500 1000 10000 100000

Breaked current (A)

CBWEARcharacteristics

Figure 4.1 – An example of circuit breaker wearing characteristic graph

Table 4.7 – Example of Circuit Breaker Wearing Characteristics

Point Interrupted current (kA) Number of permitted operations

1 0 (mechanical age) 10000 2 1.25 (rated current) 10000 3 31.0 (maximum breaking current) 80 4 100 1 5 100 1 6 100 1 7 100 1 8 100 1

Note: Values taken from Figure 4.1. The table is edited with SetPointPS under menu

“Breaker Curve”.

Setting Alarm Points

There are two alarm points available having two setting parameters

each.  Current

The first alarm can be set for example to nominal current of the CB or any application typical current. The second alarm can be set for example according a typical fault current.

 Operations left alarm limit

An alarm is activated when there are less operation left at the given current level than this limit.

865-UM001A-EN-P – July 2009

4-8 Supporting Functions

Any actual interrupted current will be logarithmically weighted for

the two given alarm current levels and the number of operations left at the alarm points is decreased accordingly. When the "operations left" i.e. the number of remaining operations, goes under the given alarm limit, an alarm signal is issued to the output matrix. Also an event is generated depending on the event enabling.

Clearing "Operations Left" Counters

After the breaker curve table is filled and the alarm currents are

defined, the wearing function can be initialized by clearing the decreasing operation counters with parameter "Clear" (Clear oper. left cntrs). After clearing the relay will show the maximum allowed operations for the defined alarm current levels.

Operation Counters to Monitor the Wearing

The operations left can be read from the counters "Al1Ln" (Alarm 1)

and "Al2Ln" (Alarm2). There are three values for both alarms, one for each phase. The smallest of three is supervised by the two alarm functions.

Logarithmic Interpolation

The permitted number of operations for currents in between the

defined points is logarithmically interpolated using equation

Equation 4.1

C =

C = permitted operations I = interrupted current a = constant according Equation 4.2 n = constant according Equation 4.2

Equation 4.2

Equation 4.3

ln = natural logarithm function C

k+1

, where

ICa =

= permitted operations. k = row 2...7 in Table 4.7.

= corresponding current. k = row 2...7 in Table 4.7. = permitted operations. k = row 2...7 in Table 4.7. = corresponding current. k = row 2...7 in Table 4.7.

865-UM001A-EN-P – July 2009

Rockwell Automation 865 User Manual

Specifications and Main Features

Frequently Asked Questions

User Manual

Important User Information

Table of Contents

Introduction The Allen-Bradley 865 differential protection system includes all the

Main Relay Features The main features of Allen-Bradley 865 are:

User Interface

Operating Safety

Relay Front Panel The figure below shows, as an example, the front panel of the

Display

Menu Navigation and Pointers

Keypad

Operation Indicators

Resetting Latched Indicators and Output Relays

Adjusting Display Contrast

Local Panel Operations The front panel can be used to control objects, change the local/

Navigating in Menus

Main menu

Menu Structure of Protection Functions

Setting Groups

Fault Logs

Operating Levels

Opening Access

Password Handling

Operating Measures Control Functions

Measured Data

Reading Event Register

Forced Control (Force)

Parameter Setting

Setting Range Limits

Disturbance Recorder Menu DR

Configuring Digital Inputs DI

Configuring Digital Outputs DO

Protection Menu Prot

Configuration Menu CONF

Single Line Diagram Editing

Blocking and Interlocking Configuration

SetPointPS PC Software The PC user interface can be used for:

Protection Functions

Setting Groups

General Features of Protection Stages

Forcing Start or Trip Condition for Testing

Forcing Start or Trip Condition for Testing Purposes

Start and Trip Signals

Output Matrix

Blocking

RetardationTime

Reset Time (Release Time)

Hysteresis or Dead Band

Parameters of the Differential Overcurrent Stages

Two Independent Stages

Inverse Operation Time

Inverse Time Limitation

Setting Groups

Recorded Values of the Latest Eight Faults

Inverse Delay

More Stages (Definite Time Delay only)

Setting Groups

Recorded Values of the Latest Eight Faults

Input Signal Selection

Intermittent Earth Fault Detection

Four Independent Undirectional Earth Fault Overcurrent Stages

Inverse Time Limitation

Setting Groups

Recorded Values of the Latest Eight Faults

Thermal model

Time Constant for Cooling Situation

Heat Capacitance, Service Factor and Ambient Temperature

Example of a Behavior of the Thermal Model

Initial Temperature Rise After Restart

Alarm Function

Recorded Values of the Latest Eight Faults

Three Stages for Arc Faults

Light Channel Selection

Binary Input

Binary Output

Delayed Light Indication Signal

Pick Up Scaling