Siemens SG8158-00 User Manual

ISGS

Intelligent SwitchGear System Operators Manualfirmware version V3

Manual No. SG8158-00

IMPORTANT

The information contained herein is general in nature and not intended for specific application purposes. It does not relieve the user of responsibility to use sound practices in application, installation, operation, and maintenance of the equipment purchased. Siemens reserves the right to make changes at any time without notice or obligations. Should a conflict arise between the general information contained in this publication and the contents of drawings or supplementary material, or both, the latter shall take precedence.

QUALIFIED PERSON

For the purposes of this manual, a qualified person is one who is familiar with the installation, construction, or operation of the equipment and the hazards involved. In addition, this person has the following qualifications:

(a) is trained and authorized to de-energize, clear, ground, and tag cir-

cuits and equipment in accordance with established safety practices.

(b) is trained in the proper care and use of protective equipment such as

rubber gloves, hard hat, safety glasses or face shields, flash clothing, etc. in accordance with established safety procedures.

NOTE

These instructions do not purport to cover all details or variations in equipment, nor to provide for every possible contingency to be met in connection with installation, operation, or maintenance. Should further information be desired or should particular problems arise which are not covered sufficiently for the purchasers purposes, the matter should be referred to the local sales office.

The contents of the instruction manual shall not become part of or modify any prior or existing agreement, commitment or relationship. The sales contract contains the entire obligation of Siemens Energy & Automation, Inc. The warranty contained in the contract between parties is the sole warranty of Siemens Energy & Automation, Inc. Any statements contained herein do not create new warranties or modify the existing warranty.

Introduction

Table

Contents

Installation

User Interface

Hardware Configuration

Protective Function Configuration

Control & Communications

Data Acquisition

ISGS Wisdom Software

Trip Curves & Equations

Metering

Menu Structure

Acceptance Test Procedures

Schematics

Settings Worksheet

Glossary

Index

Siemens Energy & Automation, Inc.

Table of Contents

1 Introduction ...............................................1

1.1 About this Manual............................................. 1

1.2 Safety................................................................ 1

1.3 Product Description .......................................... 2

1.3.1 Standard Configuration......................... 2

1.3.2 Optional Configurations ........................ 3

1.4 Wisdom Software.............................................. 3

1.5 Technical Specifications ................................... 4

2 Installation .................................................5

2.1 Unpacking......................................................... 5

2.2 Storing............................................................... 5

2.3 Mounting ........................................................... 5

2.4 Wiring................................................................ 6

2.5 Communications............................................... 8

2.5.1 PC Communications (RS-232) ..............8

2.5.2 Network Communications (RS-485) ..... 8

2.6 Cradle Assembly............................................... 8

2.6.1 Removing .............................................. 8

2.6.2 Inserting ................................................ 8

3 User Interface............................................9

3.1 Keypad.............................................................. 9

3.2 Indicators .......................................................... 9

3.2.1 LEDs...................................................... 9

3.2.2 LCD ..................................................... 10

3.3 Password Protection....................................... 10

3.4 Menu ............................................................... 11

3.5 Standard Operating Procedures..................... 11

4 Hardware Configuration.........................15

4.1 Startup ............................................................15

4.1.1 Power On Display................................ 15

4.1.2 Power On Meter Display ..................... 15

4.2 Device Configuration ...................................... 16

4.3 Setting Binary Input Voltages.......................... 16

4.4 CT Configuration............................................. 18

4.5 VT Configuration ............................................. 18

5 Protective Function Configuration ........21

5.1 Overview ......................................................... 21

5.2 Instantaneous Phase Overcurrent (50)............ 21

5.3 High-Set Instantaneous Phase

Overcurrent (50HS) ......................................... 22

5.4 Instantaneous Neutral or Ground

Overcurrent (50N)............................................ 22

5.5 High-Set Instantaneous Neutral or

Ground Overcurrent (50HSN).......................... 22

5 Protective Function Configuration (cont.)

5.6 Phase Time Overcurrent (51)...........................23

5.7 Neutral Time Overcurrent (51N) ......................23

5.8 Blocking Capability for Breaker or

Interrupter Saving............................................ 24

5.9 Directional Phase Time Overcurrent (67).........24

5.10 Directional Neutral or Ground Time

Overcurrent (67N)............................................25

5.11 Overvoltage (59) ..............................................26

5.12 Undervoltage (27)............................................26

5.13 Phase Sequence Voltage (47) .........................27

5.14 Negative Sequence Voltage (47N) ..................27

5.15 Overfrequency (81O) ....................................... 28

5.16 Underfrequency (81U) ..................................... 28

5.17 Breaker Failure (50BF)..................................... 28

5.18 Demand Setpoints ..........................................29

5.19 Power Setpoints.............................................. 30

6 Control & Communications ................... 31

6.1 Matrixing Events to Outputs ...........................31

6.2 Binary Inputs ...................................................33

6.3 Binary Outputs ................................................33

6.4 Trip Contacts ...................................................34

6.5 Comm Events.................................................. 34

6.6 Breaker Monitoring..........................................34

6.7 Logs and Breaker Monitor Reset ....................35

6.8 Breaker Operations Count ..............................36

6.9 Hardware Status (Relay Data) ......................... 36

6.10 Self-Monitoring (Value Supervision) ................ 37

6.11 Parameter Sets ...............................................39

6.11.1 Active Set ............................................40

6.11.2 Default Set........................................... 40

6.11.3 Switching Sets ....................................40

6.11.4 Copying Sets.......................................40

6.12 Communications Port .....................................41

6.13 Passwords.......................................................41

6.14 Date and Time Setting ....................................41

7 Data Acquisition ..................................... 43

7.1 Event Log ........................................................43

7.2 Trip Logs ......................................................... 43

7.3 Min/Max Logs .................................................44

7.3.1 Current Minimum/Maximum Log ........44

7.3.2 Voltage Minimum/Maximum Log ........45

7.3.3 Power Minimum/Maximum Log ..........45

7.3.4 Frequency Minimum/Maximum Log ...45

Siemens Energy & Automation, Inc. i

Table of Contents

7 Data Acquisition (cont.)

7.4 Metered Data ..................................................46

7.4.1 Current Values .....................................46

7.4.2 Voltage Values .....................................46

7.4.3 Power Values....................................... 46

7.4.4 Frequency Values................................46

7.5 Meter Display ..................................................47

7.6 Waveform Capture .......................................... 47

8 ISGS Wisdom Software ..........................49

8.1 Overview .........................................................49

8.2 Setup...............................................................49

8.3 Menus .............................................................49

8.4 Demo Mode ....................................................51

A Trip Curves & Equations.........................53

A.1 Instantaneous Curve ........................................ 53

A.2 Standard Time Overcurrent Equation ..............53

A.3 Definite Inverse Equation .................................55

A.4 I-Squared-T Curve ...........................................56

A.5 Custom Protective Curve................................. 56

A.6 Over/Undervoltage Curves ..............................56

B Metering.................................................. 58

B.1 Accuracy ..........................................................58

B.2 Power Conventions..........................................59

C Menu Structure....................................... 60

D Acceptance Test Procedures ................ 63

E Schematics ............................................. 79

E.1 DC Trip System ................................................79

E.2 AC (Capacitor) Trip Systems............................80

Settings Worksheet

Glossary

Index

Service Request Form

ACCESS, CBPM, ISGS, SEAbus, WinPM, and Wisdom are trademarks of Siemens Energy & Automation, Inc. SIEMENS is a registered trademark of Siemens AG. All other brands and product names are trademarks of their respective companies.

ii Siemens Energy & Automation, Inc.

Introduction

1 Introduction

The Intelligent SwitchGear System (ISGS) from Siemens is a high-speed, numerical, microprocessor-based protective relay designed to be easily incorporated into a computermonitored medium voltage power system. The relay is designed and manufactured in accordance with the latest provisions of the applicable IEEE, ANSI, and NEMA standards. You must thoroughly read and understand this operators manual before you begin any work with the ISGS relay. Successful application and operation of this equipment depends as much upon proper installation and maintenance by the user as it does upon the careful design and fabrication by Siemens.

1.1 About this Manual

The purpose of this manual is to assist the operator in developing safe and efficient procedures for the installation, maintenance, and use of the equipment.

This manual provides the necessary information to safely install, operate, configure, maintain, and troubleshoot the ISGS relay. In addition, the manual offers worksheets for parameter settings, acceptance test procedures, and troubleshooting. For quick reference, a complete menu structure, metering accuracies, trip curves, equations, and schematics are included in the appendix.

Contact the nearest Siemens representative if any additional information is desired.

1.2 Safety

Qualified Person

For the purpose of this manual and product labels, a Qualified Person is one who is familiar with the installation, con-

struction, and operation of this equipment, and the hazards involved. In addition, this person has the following qualifications.

 Training and authorization to energize, de-energize,

clear, ground, and tag circuits and equipment in accordance with established safety practices

 Training in the proper care and use of protective equip-

ment such as rubber gloves, hard hat, safety glasses or face shields, flash clothing, etc., in accordance with established safety procedures

 Training in rendering first aid

Siemens Energy & Automation, Inc. 1

Introduction

Signal Words

The signal words Danger, Warning, and Caution used in this manual indicate the degree of hazard that the user or operator can encounter. These words are defined as follows:

 Danger - indicates an imminently hazardous situation

which, if not avoided, will result in death or serious injury

 Warning - indicates a potentially hazardous situation

which, if not avoided, could result in death or serious injury

 Caution - indicates a potentially hazardous situation

which, if not avoided, could result in moderate or minor injury

Required Procedures

In addition to normal safety practices, user personnel must adhere to the following procedures:

1. Always work on de-energized equipment. Always deenergize a breaker or contactor, and remove it from the equipment before performing any tests, maintenance, or repair.

2. Always perform maintenance on equipment employing springs after the spring-charged mechanisms are discharged.

3. Always let an interlock device or safety mechanism perform its function without forcing or defeating the device.

Field Service Operation

Siemens can provide competent, well-trained Field Service Representatives to provide technical guidance and advisory assistance for the installation, overhaul, repair, and maintenance of Siemens equipment, processes, and systems. Contact regional service centers, sales offices, or the factory for details.

1.3 Product Description

The ISGS relay is a general purpose, multifunction, microprocessor-based protective relay. It performs protection, metering, and monitoring for three phase current transformer (CT) inputs and one ground CT input.

The ISGS relay provides two breaker tripping contacts and one relay disabled (alarm) contact. The relay disabled contact is a normally closed contact which opens when the relay is functioning properly.

1.3.1 Standard Configuration

The ISGS relay base unit includes the following standard protection, metering, and monitoring features:

 Instantaneous Phase Overcurrent (50) protection

 Instantaneous Neutral or Ground Overcurrent (50N)

protection

 Phase Time Overcurrent (51) protection

 Neutral or Ground Time Overcurrent (51N) protection

ISGS

System Pickup Trip

Direct

Target Reset

Pass

Addr

word

Trip

Target

Log

Reset

ISGS

Cat# C552-100V-5D0-000 VPSn120VAC/250VDC IPH 5A IC 5A Ser# Beta05HW15W2.XX

Pass word

Yes No

∞

Data Port

-/+

Enter

Figure 1.1 Intelligent SwitchGear System (ISGS) Relay

 Nine selectable time overcurrent curves and one custom

curve

 Breaker Failure (50BF) protection

 Phase and neutral current as well as average current

metering

 Minimum/maximum logs for storing metering data

 Waveform capture

 Trip log for recording information on last eight trip events

 Event log for monitoring and recording relay functions

for status changes

 2-line by 16-character liquid crystal display (LCD) for

viewing measured data

 26-key membrane keypad for local access and selected

manual data entry.

 LED indicators for general relay status information

 Standard RS-232 communications port for local access

to all parameter settings using a personal computer (PC) and Wisdom software

 Password security

The ISGS relay is supplied in an M1-size drawout case with dust tight front cover. The case is compatible with XLA connecting plugs that are commonly used to test relays.

2 Siemens Energy & Automation, Inc.

Introduction

1.3.2 Optional Configurations

The ISGS relay is a dynamic, feature-rich device that can be used in numerous industrial and utility applications. It allows the addition of options or configuration changes at any time without discarding the basic hardware.

There are four optional configurations that can be added to the ISGS relay base unit.

Metering

Adding metering to the ISGS relay provides the relay with three inputs for the connection of VTs. Each input can be set from 100 V to 120 V. These inputs extend metering capabilities as follows:

 Rms and average rms voltages

 Active and apparent power

 Kilowatt demand and kilowatt demand hours

 Power factor

 Frequency

The installation of the voltage input card now also allows the setting of these protective functions:

 High-Set Instantaneous Phase Overcurrent (50HS)

 High-Set Instantaneous Neutral or Ground Overcurrent

(50HSN)

The metering option is also a prerequisite for the next two options: additional protective functions and remote communications.

Additional Protective Functions

For an ISGS relay with the metering option installed, the following additional protective functions offer a powerful extension of its protection capabilities:

 Under/Overvoltage (27/59)

 Phase Sequence Voltage (47)

 Negative Sequence Voltage (47N)

 Directional Time Overcurrent (67/67N)

 Over/Underfrequency (81U/O)

Communications

Adding communications to the ISGS relay provides the relay with an RS-485 port. Using the SEAbus communications protocol, this port allows remote communications and control via the ACCESS electrical distribution and communication system (ACCESS system).

Communications allows configuration, measurement, and protection functions to be performed or reviewed easily from a remote location using Wisdom software.

1.4 Wisdom Software

While it is possible to completely set up and configure the ISGS relay using the front panel keyboard and display, the free Wisdom software package provided with the relay reduces the complexity of configuring the relay, reading metered values, and retrieving stored data. For more information on Wisdom software, refer to Chapter 8.

Siemens Energy & Automation, Inc. 3

Introduction

1.5 Technical Specifications

Applicable Standards

ANSI / IEEE C37.90-1989 IEEE Standard Relays and Relay

IEC 255-4 Single Input Energizing Quantity

General Technical Data

Operating ambient temperature -20°C to +55°C (-4°F to +131°F)

Storage temperature -40°Cto +75°C (-40°F to +167°F)

Relative humidity The average relative humidity

Altitude < 1500 meters

Frequency 50 Hz or 60 Hz, software select-

Power Supply AC/DC

DC Rated voltages 48 V (19-56 V),

Permissible ripple <10%

AC Rated voltage 120 V rms (102-132 V, 50-60 Hz)

Power consumption <15W

Input Circuit Ratings

Rated current (In) 1 or 5 A, independently for

Maximum input current 4 x In continuous

CT burden <0.1 VA for 1A CT

Rated voltage (Vn) 115 or 120 volts

Maximum input voltage for measurement: 1.25 x Vn

VT burden 150k

Tripping relays 2 or 3

Contact configuration (Trip 1, Trip 2, Trip 3)

Contact rating IEEE/ANSI C37.90-1989, Sec-

Systems Associated With Electric Power Apparatus

Measuring Relays With Dependent or Independent Time

may be up to 55% outside of enclosure for temperatures up to 40°C, with excursions up to 95% for a maximum of 96 hours, without condensation.

able

125 V (46-144 V), 250 V (92-288 V)

phase and ground inputs

10 x In for 10 s

100 x In for 1 s

<0.5 VA for 5A CT

MOV protected at: 2.5 x Vn

Ω

Trip Circuit

tion 6.7 (Make and carry 30 A for at least 2000 duty cycles, resistive load, interrupted by independent means. Duty cycle: 200 ms on, 15 s off, 250 V)

Trip Circuit (continued)

Binary output contacts (BO1 and BO2)

Maximum switching voltage 300 VDC, 250 VAC

Maximum switching current 8 A

Maximum switching capacity (for currents not interrupted by independent means)

Trip source monitor 215 mA for 48 VDC supply

Applicable standards ANSI/IEEE C37.90-1989,

Between all circuits (except communications interfaces, analog inputs and outputs) and ground, and between these circuits.

Between communications interfaces, analog inputs and outputs and ground, and between these circuits

Across open contacts rated for tripping

Across open contacts not rated for tripping

Applicable standards IEC 255-4, IEC 255-5

For all circuits (except communications interfaces, analog inputs and outputs), transverse and common mode

RS-485 and local communications interfaces, analog I/Os

Electrostatic Discharge

Applicable standards IEC 801-2 (test without cover)

Contact discharge class 3, 6 kV

Air discharge class 3, 8 kV

Surge Withstand Capability

Applicable standards ANSI/IEEE C37.90-1989,

For all circuits except communications interfaces, analog inputs and outputs

For RS-485 interface, analog inputs and outputs

Electromagnetic Field

Applicable standards ANSI/IEEE C37.90.2

All six faces 10 V/m (+100%, -0%),

2 x N.O. (independent, not rated for tripping)

DC: voltage dependent;

50 W at V 100 W at 48 VDC 270 W at 35 VDC AC: 2000 VA

63 mA for 125 VDC supply 36 mA for 250 VDC supply Source quality checked approximately every 4 minutes

Isolation

IEC 255-4, IEC 255-5

2 kV rms, 50/60 Hz, 1 minute

500 VDC, 1 minute

1500 V rms, 50/60 Hz, 1 minute

1000 V rms, 50/60 Hz, 1 minute

Impulse

class 3, 5 kV, 1.2/50

class 1, 0 kV

IEC 255-4, IEC 255-22-1, IEC 41B (CO) 53

ANSI: Oscillatory and Fast Transient, transverse and common mode IEC: Class 3, 2.5 kV

IEC: Class 1, 0.5 kV

2-1000 MHz

≥70 VDC

µs, 0.5 J

4 Siemens Energy & Automation, Inc.

Installation

2 Installation

This chapter explains the installation of the ISGS relay and includes procedures for unpacking, storing, mounting, and wiring the relay. Prior to installation, ensure that the system power is off and that you have all required tools and test equipment available.

2.1 Unpacking

Upon receipt of the relay, inspect the carton for signs of damage. If the carton has been opened or damaged, carefully inspect and verify the contents against the packing list. If pieces are missing or damaged, contact the shipping agent or your Siemens representative. Refer to Figure 2.1 to iden- tify the different parts of the relay.

Note: To avoid damage to the relay, transport or

store the relay in the original packing material. Always transport the cradle assembly inside the case.

2.3 Mounting

The ISGS relay is typically installed in a switchgear unit or relay panel. The required panel opening and a side view of the relay are shown in Figure 2.2.

5.69

14.63

(371.5)

7.31

(185.7)

(144.5)

2.84

(72.1)

7.13

(181.0)

4X .25 (6.4) DIA

14.25

(362.0)

Figure 2.1 Case, Cradle, Paddles, and Cover of ISGS Relay

2.2 Storing

Extended storage of the relay should adhere to the following guidelines:

 Store the relay in a clean, dry location in the original

packing material

 Storage temperature range is -40°F to +167°F

(-40°C

to +75°C)

Note: This device contains electrolytic capacitors,

which can degrade over time when stored at temperatures over 86°F (30°C). Take care not to store the relay at high temperatures for extended periods.

After extended storage, connect the relay to its auxiliary voltage source for one or two days prior to taking it into actual service. This serves to regenerate the electrolytic capacitors of the auxiliary supply.

(77.0)

6.06

(154.0)

6.19

(157.2)

(7.9)

7.06

(179.4)

7.06

(179.4)

(7.9)

MOUNTING PANEL

Figure 2.2 Mounting Dimensions

3.03

.31

.63

(16.0)

.63

(16.0)

10-32

SCREWS

10-32

SCREWS

Siemens Energy & Automation, Inc. 5

Installation

Mount the relay using the following steps.

1. Install the relay M1-type case in the panel opening on the switchgear equipment.

2. Connect the case ground to the terminal lug on the back of the M1-type case as shown in Figure 2.3.

3. Wire as described in Section 2.4.

Use toothed washers to ensure solid metal contact through paint of cover and panel

Case ground, #12 or braided cable to good cubicle ground, as short as possible

IMPORTANT: Any unused terminals must remain disconnected. They are for factory use only.

Relay Disabled 2

Relay Disabled 1

Impedance Sense

Impedance Source

Ground Monitor

BI Trip

BI B Switch

Power Input +

Power Input -

Top

BI1A 21 BI1B 22 BI2A 23 BI2B 24 BI3A 25 BI3B 26 BI4A 27 BI4B 28 Trip 3A 29 Trip 3B 30

17 15 13 11

18 16 14 12

41 VT1+ 42 VT143 VT2+ 44 VT245 VT3+ 46 VT347 NC (unused) 48 SEAbus Signal + 49 SEAbus Signal 50 SEAbus Ref

Trip 2

Figure 2.3 Case Grounding

2.4 Wiring

Wire the ISGS relay after the case is installed. Connect the wiring to the applicable terminals to support the desired features. Refer to Figure 2.4 for terminal locations. Figure 2.5 shows the internal connections of the ISGS relay. To avoid injury to personnel or the equipment, perform power connections after all other wiring has been completed.

Assure that all power is off before performing any wiring. Terminals 1 through 20 accept ring-tongue or forked spade terminals and are suitable for 14 AWG to 10 AWG wire. Terminals 21 through 60 are for directly inserting the appropriate wire and are suitable for 22 AWG to 14 AWG wire.

Communications connections made to terminals 48 to 50 require shielded twisted pair wire.

CT connections should be made with the polarity end of the CT connected to current terminal marked with an asterisk (*).

BO1A 31 BO1B 32 BO2A 33 BO2B 34 AI1+ 35 AI1- 36 AI2+ 37 AI2- 38 AO1+ 39 AO1- 40

CTN-2

7531

8642

CTN-1*

CT3-2

CT3-1*

Figure 2.4 Terminal Locations

Case Ground

CT2-2

CT2-1*

CT1-2

CT1-1*

Trip 1

Trip Common

6 Siemens Energy & Automation, Inc.

Current Input

Voltage Input

BI B Switch

CT 1-1 CT 1-2 CT 2-1 CT 2-2

CT 3-1 CT 3-2

CT N-1 CT N-2

VT 1+ VT 1VT 2+ VT 2-

VT 3+ VT 3-

Installation

ISGS

3 4 5 6 7 8 9

10 41

42 43 44 45 46

2 Trip 1

Trip Common

Trip 2

Trip 3

Relay Disabled 1

19 20

Relay Disabled 2

BO 1

32 33

BO 2

Binary Outputs

Trip Relays

Relay Disabled Alarm Contact

Breaker and Trip Source Monitor

BI Trip

Impedance Source Impedance Sense

Ground Monitor

Binary Input

Power Supply

Communications In

Data +

RxD

17 18 16

13 12

(3)

RS-485 SEAbus

RS-232

Front Panel

Communications Out

Data -

Reference

(2)

TxD

(7)

Reference Ground

Figure 2.5 Internal Connections

Note: The relay disabled contact should be wired to plant-wide distributed control system or external alarm.

Siemens Energy & Automation, Inc. 7

Installation

2.5 Communications

The ISGS relay must be connected to a host computer in order for it to communicate with other devices. The relay supports both RS-232 and RS-485 (optional) data interfaces. The use of either of these data interfaces will allow the same level of access to the system as the front panel keypad, but configuration through communications does not require a password.

The next section describes the connection to the interfaces. For more information about operating the ISGS relay via the data interfaces, refer to the documentation for the communications software, such as WinPM or Wisdom. Keypad operations are described in Chapter 3.

2.5.1 PC Communications (RS-232)

The RS-232 interface (front port) is intended only for shortterm connections to a portable computer. Use this interface to perform initial setup or to read the ISGS relay data logs or waveform buffers using an appropriate software program. To connect your PC to the front port, follow these instructions:

1. Remove the relay case front cover.

2. Locate the RS-232 connector on the front panel of the cradle assembly.

3. Connect the PC to the front panel RS-232 port using a standard DB-9 serial port connection cable (DB-9 male to DB-9 female or DB-25 female depending on the type of port on the computer). This connection does not require the use of special adapters or a null-modem cable.

2.5.2 Network Communications (RS-485)

The optional RS-485 interface (rear port) allows remote communication over a shielded twisted pair wire at distances of up to 4000 feet. Use this interface together with an appropriate software program for remote monitoring and control of the ISGS relay.

To connect the ISGS relay to your communications system, follow these instructions:

1. Locate the RS-485 connector on the rear of the M1 case.

2.6 Cradle Assembly

Some of the setup and maintenance procedures in this manual require removal of the relay cradle assembly from the drawout case. Use the following instructions for the proper removal and insertion of the cradle assembly.

IMPORTANT: The relay module contains CMOS circuits. Electrostatic discharges into or around the relay cradle or any of its components must be avoided. Use grounding straps or touch a grounded metal surface before handling the relay cradle.

2.6.1 Removing

Use the following procedure to remove the cradle assembly from the case:

1. Remove the relay case front cover.

2. Remove the top and bottom connecting plugs (paddles).

3. Loosen the cradle assembly by pulling the top release lever to the left and the bottom release lever to the right until the assembly ejects from the case.

4. Grasp the cradle assembly by the edges of the front panel and pull it out of the drawout case.

5. Place the cradle assembly on an anti-electrostatic surface and perform the desired work.

2.6.2 Inserting

Use the following procedure to insert the cradle assembly into the drawout case:

1. Insert the cradle assembly until the release levers come in contact with the protrusions on the case.

2. Position the top and bottom release levers until the slots on the levers align with the protrusions on the case.

3. Use the release levers to finish inserting the cradle assembly into the case. Apply pressure to the cradle assembly front panel until the assembly fully seats in the case.

2. Use shielded twisted pair wire to connect pins 48, 49, and 50 to your electrical distribution system.

To connect the ISGS relay to your PC via the rear port

 directly, use an RS-232 to RS-485 converter.

 via modem, use an RS-232 to RS-485 converter and a

null modem.

8 Siemens Energy & Automation, Inc.

4. Insert the top and bottom paddles.

5. Check for proper insertion of the cradle assembly by seeing if the expected measured values are observed on the relay display.

6. Install the front cover.

User Interface

3 User Interface

Operation, parameter selection, and control of the ISGS relay are performed using the front panel controls and indicators. They consist of a 26-key membrane keypad, a 2-line by 16-character liquid crystal display (LCD), three light-emitting diodes (LEDs), and the front port.

3.1 Keypad

The relay can be controlled via the keypad, the front port, or the optional rear port. This manual covers only keypad operations. For information about communicating with the ISGS relay via the data ports, refer to the documentation supplied with the communications software (WinPM or Wisdom).

The ISGS relay keypad allows access to any relay information or function for display or parameter changes where applicable. The keypad consists of 26 keys. Table 3.1 pro- vides a detailed description of each key type.

To access relay information or functions for display or modification, use the Arrow keys to scroll through relay addresses or use the Direct Addr key and the specific address number to go directly to the information or function.

Use the Double Arrow keys to scroll through the address blocks and use the Single Arrow keys to scroll within an address block.

3.2 Indicators

The indicators on the front panel display consist of three LEDs and a two-line LCD.

Key Name Function

Password Accesses the password function,

Direct Addr

Trip Log Displays the trip log.

Target Reset Resets the Trip LED.

Double Arrow Scrolls through the address

Single Arrow Scrolls through the addresses

F Saves new settings when followed

Numeric Used to enter an address number

which is required for programming relay settings.

Allows direct entry of addresses.

blocks.

within an address block.

by Enter, enters or exits subaddress level, or switches to alternate parameter set when followed by 1 or 2 and Enter.

after pressing Direct Addr, or to enter a numeric setting.

3.2.1 LEDs

The LED indicators are used to provide general status information, which alerts the operator to an event or problem and prompts the operator to use the LCD to review the logs for more detailed information. The three LEDs and their functions are listed below.

LED Color Function

System Green Denotes the relay is operating properly

(always on when relay is in service).

Pickup Red Denotes a protective function is in

pickup.

Trip Red Denotes a protective function or

remote command has initiated a trip.

Both the Pickup and the System LED operate automatically and do not require a reset.

 The System LED remains on as long as power is applied

and the relay is functioning properly.

 The Pickup LED is illuminated as long as a protective

function is in pickup.

Decimal Point Indicates a decimal point or the

separation between month, day, and year, or between hours, minutes, and seconds.

Plus/Minus Toggles between positive and

negative values.

Backspace Deletes one character to the left or

selects backwards.

Infinity Programs the setting to the high-

est possible value.

Enter Chooses the setting option, enters

a setting value, or confirms the address entered after pressing

Direct Addr.

Yes Accepts the displayed setting, or

replies yes to the displayed prompt.

No Rejects the displayed setting,

allows entry of a numeric setting, replies No to the displayed prompt, or selects forward.

Table 3.1 Front Panel Keys

Siemens Energy & Automation, Inc. 9

User Interface

The Trip LED is illuminated until the Target Reset key is depressed. Reset the Trip LED by momentarily depressing the Target Reset key.

Note: If the Trip LED is on and power is removed, it

will still be set to on when power is restored.

3.2.2 LCD

The two-line by sixteen-character LCD allows the viewing of parameters, measured data, and keypad entries. The LCD also displays messages returned by events such as a relay going into pickup.

Whenever a relay goes into pickup, in addition to lighting the pickup LED, the LCD shows a message that indicates which protection element is in pickup. A pickup message is displayed as follows:

PICKUP FFF Pxxxx MM/DD hh:mm:ss

In this message

FFF is the two or three character ANSI pro-

tection code number, for example, 50, or 50N.

xxxx is a sequence of the characters 1, 2, 3,

and/or N, indicating which phase or combination of phases and neutral have picked up.

MM/DD hh:mm:ss is the date and time of the event.

Level 3 includes additional access to all matrixing, the

changing of which can cause a device reset.

Password configuration is described in Section 9.4.

To access any password protected information or function, either first enter the password (up to five digits) and then go to the desired address, or first access the address block and then enter the password as described in the following steps:

1. Press the Password key. The password dialog box appears.

Password:

2. Enter a password (00000 to 99999) using the number keys from the keypad. The LCD displays each digit entered as an @ symbol.

Password: @@@@@

3. Press the Enter key after completing the entry.

4. If a correct password has been entered, the dialog box displays a confirmation message that depends on the level password that was entered.

Password: User PW Three OK

These messages are displayed until superseded by another pickup, a trip message, a target reset, or a request by the operator to display other information.

3.3 Password Protection

A password should be used to prevent any accidental or unauthorized parameter changes. While relay information can be accessed for display without a password, all changes to parameter settings require a user password.

Note: The ISGS relay is not password protected

when making parameter changes through Wisdom software.

The ISGS relay offers three password protected access levels:

Level 1 consists of simple settings such as all protective

and setpoint settings that do not cause a reset. These simple settings include communications and time and date settings.

Level 2 consists of protective function settings such as

CT and VT ratios, the changing of which can cause a device reset.

For a level 1 or level 2 password, the word Three in the illustration above would be replaced by One and Two, respectively.

If the wrong password has been entered, the dialog box displays the following message:

Password: Rejected

5. When the confirmation message appears, press the Enter key. This action returns the display that was in use before entering the password.

For example, if the address block of the parameter to be changed was displayed prior to entering the password, the display returns to this address block and the device is ready to accept changes.

10 Siemens Energy & Automation, Inc.

User Interface

3.4 Menu

The ISGS relay menu (or memory map) is organized in a hierarchical structure that is made up of address blocks and addresses. The first level consists of address blocks. Each address block represents one complete function or two related functions and is identified by a unique four-digit number ending in two zeros (for example, 1500). Refer to Figure 3.1.

The second level consists of individual addresses confined to an address block. Each address represents a part of a functionthe changeable parameteror the measured value of a displayed parameter. The parameter is identified by a unique four-digit number that consists of the first two digits of the address block and two digits indicating the parameters number within the address block (for example, 1502). Refer to Figure 3.1.

Block Function Address Parameter

A1500 Instantaneous

Phase Overcurrent (50)

High-Set Instantaneous Phase Overcurrent (50HS)

A1900 Directional Phase

Time Overcurrent (67)

A2200 Overvoltage (59) --- ---

Figure 3.1 Example of Menu Structure Displaying Address Blocks with Two Related Functions, an Individual Function, and an Unavailable Function.

A complete ISGS relay menu with parameter listing is provided in Appendix C. The various parameter settings are shown in the respective section describing the complete function.

1501

Function 50

1502

Pickup 50

1504

Delay 50

1510

Freeze Wfm 1 50

1511

Freeze Wfm 2 50

1512

Block 50

1551

Function 50HS

1552

Pickup 50HS

1560

Freeze Wfm 1 HS

1561

Freeze Wfm 2 HS

1901

Function

1902

Curve

1903

Pickup

1905

Time Dial

1906

Filter

1907

Impedance

1908

Direction

1910

Freeze Wfm 1

1911

Freeze Wfm 2

The LCD identifies functions that include parameters configurable for A and B settings by preceding the functions address block number with the letter A or the letter B, depending on which parameter set is currently displayed. Refer to Figure 3.2.

A1500 Instantaneous Phase Overcurrent 50

Figure 3.2 LCD Display of a Function that Includes Parameters Configurable for A and B Settings.

In addition, when scrolling through the individual parameters of an ISGS relay, the LCD identifies each parameter that is configurable for A and B settings by preceding the parameters address number with the letter A or the letter B, depending on which parameter set is currently displayed. Refer to Figure 3.3

A1502 Pickup 50 110A

Figure 3.3 LCD Display of a Parameter that is Configurable for A and B Settings

When accessing the ISGS relay menu through the keypad, the Arrow keys allow scrolling through all available functions and parameters. If an option is not installed, the LCD only displays the address block that is reserved for this option. In this case, second level addresses are not available.

3.5 Standard Operating Procedures

Before attempting to display or configure any of the relay data, ensure that the relay has control power which is indicated by the system LED (green) being lit.

The steps for displaying data, configuring parameters, saving data, and switching to the alternate parameter set for either display or configuration are described in detail in Table 3.1, Standard Operating Procedures.

Only certain protective function parameters have two settings. All A settings are grouped under parameter set A, and all B settings are grouped under parameter set B. Each parameter set automatically includes all the regular parameters that can be programmed to only one setting at a time and, therefore, apply to both sets. Examples are protective function enable settings and matrixed output contacts such as waveform buffers and blocking. For more information on parameter sets, refer to Section 6.11.

Siemens Energy & Automation, Inc. 11

User Interface

Displaying function names (address blocks), parameter names and their settings or values (addresses), and subparameter settings (subaddress, where applicable), does not require a password (except for viewing the password itself). Data can be displayed by following steps 1 to 3 of the standard operating procedures described in Table 3.1. Viewing passwords requires the entry of an appropriate level user password (refer to Section 3.3 for more information on passwords).

Configuring parameters requires a password. Use steps 1 and 2 or steps 1 to 3 to display the desired parameter or its subparameters. Continue with step 4 to make changes to this parameter or subparameter.

When leaving a function or before scrolling to the waveform parameters of the same function, the relay prompts to indicate the end of the password operation and whether the changes made so far shall be saved. When the message End of Password Operation ? appears, press the Ye s key to continue to the next function. Press the No key to scroll back through the parameters of this one function. Pressing the Ye s key returns the message SAVE NEW SETTINGS ?. Press the Yes key again to save the settings, or press the No key to abort any changes made after the last saving procedure.

12 Siemens Energy & Automation, Inc.

Table 3.1 Standard Operating Procedures

Step Task Description

Display Data

1 Display data at

Address Block (xx00)

Use Double Arrow keys to scroll forward or backward between address blocks.

Press Direct Addr key; enter address of desired address block using the numeric keypad; press Enter key. To view passwords, carry out step 4 before continuing with the next step.

User Interface

2 Display data at

Address (xxxx)

3 Display data at

Subaddress (0xx)

4 Enter Password Press Password key; enter the password; press Enter key twice to return to screen displayed last before

5 Configure at

Address (xxxx)

6 Configure at

Subaddress (0xx)

Use Single Arrow keys to scroll forward or backward between parameter addresses.

Skip step 3 if function has no subaddresses.

Press Direct Addr key; enter address of desired parameter using the numeric keypad; press Enter key.

Skip step 3 if function has no subaddresses.

Press F key once to enter subaddress level; use Single Arrow keys to scroll forward or backward between subaddresses.

Press F key again to return to address level.

Configure Parameters

password entry.

Leaving an address block, leaving a function within an address block, or before scrolling to the waveform parameters within a function prompts for renewed password entry.

For password levels, proper password entry, and display messages, refer to Section 3.3.

Display cursor is blinking (otherwise repeat step 4).

Change displayed value by entering a new value using the keypad. Press Enter key.

Change displayed selection by pressing the No key to scroll forward through options until desired option appears. Press Enter key.

Skip step 6 if function has no subaddresses.

Press F key once to enter subaddress level; use Single Arrow keys to scroll forward or backward between subaddresses.

Change displayed selection by pressing No key to scroll forward through options until desired option appears. Press Enter key.

Press F key again to return to address level.

Save Changes

7 Enter Save

Procedure

Undo Changes To abort any changes made, press No key. After message SAVING PROCEDURE ABORTED appears,

Save Changes To save settings and reset relay to new parameters, press Yes key followed by Enter key. After message

8 Switch

Parameter Set

9 Display/Config-

ure Alternate Parameter Set

Press F key. At the blinking cursor position, the letter F is displayed. Press Enter key. Message SAVE NEW SETTINGS? appears.

press Enter key to return to screen displayed last before aborting settings.

Settings can be undone any time while still in the same function by simply returning to the parameter and assigning a new value.

NEW SETTINGS SAVED appears, press Enter key to return to screen displayed last before saving settings.

Leaving an address block, leaving a function within an address block, or before scrolling to the waveform parameters within a function prompts for the saving of the function settings.

Switch Parameter Set

Press F key followed by either 1 (for normal settings) or 2 (for alternate settings) on the numeric keypad. The message PARAMETER SET COPIED TO EDIT appears. Press Enter key.

Display shows address block (xx00) with either A or B prefix in address (Axx00 or Bxx00). A indicates parameter set 1; B indicates parameter set 2.

Repeat steps 1 to 3 or steps 1 to 7 to display or configure the alternate parameter set.

Siemens Energy & Automation, Inc. 13

Notes:

14 Siemens Energy & Automation, Inc.

Hardware Configuration

4 Hardware Configuration

This chapter explains the device startup and how to configure the basic ISGS relay parameters. The relay must be configured with certain system parameters, such as phase sequence and frequency. In addition, information regarding the manner in which the ISGS relay is connected in the installation must be configured.

All parameter changes require a password. Refer to Section 3.3 for instructions on how to enter your password. Viewing parameter settings does not require a password.

Note: The ISGS relay is not password protected

when making parameter changes through Wisdom software.

Perform parameter changes using steps 1 through 9 of the standard operating procedure described in Section 3.5.

4.1 Startup

Block Function Address Parameter

0000 Power On/

Configuration Display

This section describes the content of address block 0000 represented by the initial Power On display and the initial Power On Meter display.

When the relay is powered on, following a brief hardware initialization check, the green System LED illuminates and the LCD shows the contents of address 0000. First, the Power On display indicates your relay configuration. After approximately five seconds, the Power On display is replaced by the Power On Meter display showing two values. Prior to placing the relay in service, verify that the correct relay configuration was preloaded at the factory. To return to the Power On display, press the Direct Addr key and key in 0000 followed by the Enter key.

4.1.1 Power On Display

The two lines of the Power On display indicate your relay configuration. Line 1 contains the function address 0000 and the relays firmware version. Line 2 identifies the relays catalog number which depends on the options you ordered with your relay (see Figure 4.2 for catalog numbers).

Reading from left to right in Figure 4.1, line 1 shows the address block 0000 and the ISGS firmware version ISGS-3V3.00. Line 2 displays the catalog number D553100VSDF00000. The first character of this number, D, indicates a 120 VAC power supply, the fourth character, 3, voltage inputs for energy metering, and the eighth through eleventh characters, VSDF, indicate Under/Overvoltage pro- tection, Negative Sequence Voltage protection, Directional Overcurrent protection, and Under/Overfrequency protection, respectively.

--- ---

0000 ISGS-3V3.00 D553100VSDF00000

Figure 4.1 Power On Display

123 4567 891011 121314

ISGS

Nominal Supply Voltage

48 VDC 125 VDC 120VAC 250VDC

Phase CT Secondary Rating

1A 5A

Neutral or Ground CT Rating

1A 5A

Voltage Inputs, Power Metering, RS-485 Communications

Without With

Additional I/O

Without With

Under/Overvoltage Protection (27/59), Negative Sequence Voltage Protection (47/47N), Directional Overcurrent Protection (67/67N), Under/Overfrequency Protection (81 U/O)

Without With

* Voltage Inputs required.

A B D E

1 5

00 31

0000

VSDF

---

0 0 00

Figure 4.2 Relay Configuration (Catalog Number)

4.1.2 Power On Meter Display

The Power On Meter display consists of two measured values. The default setting for Line 1 displays average current, and Line 2 shows average current demand. The type of default values displayed can be changed in address block 7000, Operating Parameters, described in Chapter 7.

Iavg = xx A Idmdavg = xx A

Figure 4.3 Power On Meter Display

The Power On Meter display is replaced with other information anytime an event message is displayed or the LCD is used to set parameters or check logs. To return the LCD to the Power On Meter Display, press the Trip Log key followed by the Target Reset key.

Siemens Energy & Automation, Inc. 15

Hardware Configuration

4.2 Device Configuration

The Device Configuration function allows you to set up the ISGS relay to match line frequency, phase sequence, and breaker connection settings of your system.

4.3 Setting Binary Input Voltages

Binary inputs are jumpered to correspond to the auxiliary supply voltage of the relay in which they are installed. The inputs will correctly respond to DC or AC depending on the jumpering. The jumpers can be placed to allow the inputs to work with any of the available voltages, independent of the auxiliary supply voltage. Refer to Figure 4.5 and Table 4.1.

ISGS Relay

125 VDC Bus

BI 1

Figure 4.4 Binary Inputs Independent of Supply Voltage

Table 4.1 lists the possible jumper positions for setting

binary input voltages. The numbers in this table each refer to a pin from and to which a jumper can be moved.

Table 4.1 Jumper Positions

120 VAC

Aux Relay

120 VAC Source

to be Monitored

1000 Device Configuration

Address Parameter Options

1002 Frequency 50Hz or 60Hz

1003 Phase Sequence 123 (ABC) or 132 (ACB)

1004 Breaker

Connection

1005 Trip Time 0.01-32.00 s (0.01 s steps)

Trip 1, Trip 2, Trip 3, Trip 1 & 2, Trip 1 & 3, Trip 2 & 3, or Trip 1 & 2 & 3

The frequency parameter (1002) must be set to the nominal frequency of your system. Phase sequence (1003) selects the phase sequence of your system as it enters the ISGS relay. The breaker connection parameter (1004) selects the trip contact that your breaker is connected to. Many functions use this parameter to determine if the device is attempting to open the breaker. Breaker failure can be initiated by either one of the three trips (if the Breaker Failure function is enabled). The default is set to Trip 1.

Voltage Supply

48 V X111-X112 X23-X22 X34-X35 X46-X47

125 V (Default)

120 VAC X110-X111 X24-X23 X35-X36 X47-X48

250 VDC X111-X112 X23-X22 X34-X35 X46-X47

BI 1 Te rm in a ls 21/22

X13-X14 X25-X26 X37-X38 X49-X50

X16-X17 X28-X29 X40-X41 X52-X53

X19-X20 X31-X32 X43-X44 X55-X56

X111-X112 X23-X22 X34-X35 X46-X47

X13-X14 X25-X26 X37-X38 X49-X50

X17-X18 X29-X30 X41-X42 X53-X54

X19-X20 X31-X32 X43-X44 X55-X56

X14-X15 X26-X27 X38-X39 X50-X51

X17-X18 X29-X30 X41-X42 X53-X54

X20-X21 X32-X33 X44-X45 X56-X57

X14-X15 X26-X27 X38-X39 X50-X51

X17-X18 X29-X30 X41-X42 X53-X54

X19-X20 X31-X32 X43-X44 X55-X56

BI 2 Terminals 23/22

BI 3 Terminals 25/26

BI 4 Te rm in a ls 27/28

16 Siemens Energy & Automation, Inc.

Hardware Configuration

Figure 4.5 shows option board 2 and its jumpers. The drawing indicates the jumpers associated with each binary input. The enlarged set of pins shows an example of pin labeling and a jumper at location X17-X18.

350

Changing Jumper Positions

IMPORTANT:

The relay module contains CAMS circuits. Electrostatic discharges into or around the relay cradle or any of its components must be avoided. Use grounding straps or touch a grounded metal surface before handling the relay cradle.

1. Remove the cradle assembly from the case as

described in Section 2.6.1.

2. Set the relay on its back.

3. With a small screwdriver, remove the four screws (on the

sides of the relay) that hold the front panel to the relay cradle.

4. Lift the front panel and hang it in the slots provided on

the left side of the casing. Take care not to damage the ribbon cables that connect the electronics in the cradle to the front panel electronics.

5. Disconnect the two ribbon cables from the main board

and the option board 2. The main board is the center board which is screwed to the option board 2 on its right.

6. Withdraw these two attached boards and set them on

the workplace with the jumper side up (see Figure 4.5).

7. Each jumper is pushed over two out of three pins. Each

pin is labeled with numbers identical to those in Tab l e 4 . 1. The numbers of two side-by-side pins represent a possible jumper position.

.22 163 .22 163 .22 163 .22 163

Figure 4.5 Option Board 2 with Binary Inputs

8. With a small needle nose pliers, lift the desired jumper

off of its pins and push it down over another two pins of the same set.

Example: In Figure 4.5, the jumper is over pins X17 and X18, a default setting for a 125 V power supply. For a 48 V power supply, set this jumper to X16-X17.

Repeat this step until all desired jumpers are repositioned.

9. Insert the attached boards back into the cradle. The

connectors of each board must snap into the terminals of the casing.

10. Reattach the two ribbon cables to the main board and

the option board 2.

11. Unhook the front panel and carefully place it over the

cradle. Lift the front panel slightly to make sure that the ribbon cables connected to the front panel are positioned in their assigned space to prevent damage.

12. Insert and tighten the four front panel screws.

13. Insert the cradle into the casing as described in

Section 2.6.2.

Siemens Energy & Automation, Inc. 17

Hardware Configuration

4.4 CT Configuration

The CT Configuration function allows you to set up the ISGS relay to match the phase CT primary rating, the neutral or ground CT primary rating, and the CT inputs normal power flow setting of your system. For CT connections refer to Figure 4.8.

Main Bus

ISGS

Power

Normal Power Flow

(Into CT Polarity Mark)

Figure 4.6 Normal/Reverse Power Flow

(Out of CT Polarity Mark)

Power

Reverse Power Flow

4.5 VT Configuration

Use this address block to configure the ISGS relay to match the VT primary rating and the VT connection setting for your system. These settings are available only if the voltage input option is installed on the relay.

1100 CT Configuration

Address Parameter Options

1101 Phase CT Primary

Rating

1102 Neutral or Ground

CT Primary Rating

1104 Power Flow Normal or Reverse

The phase (1101) and neutral/ground (1102) CT primary ratings are independently configurable. However, when a residual sensing method is used for ground fault protection, the primary current ratings for the neutral CT and the phase CT must be equal. The CT secondary ratings (1A or 5A) are set at the factory and are not changeable from the front panel.

Power flow is also referred to as top feed or bottom feed. If the power enters the polarity mark on the CTs, set the Power Flow parameter (1104) to Normal. If power leaves the polarity mark, enter Reverse. Figure 4.6 illustrates examples of nor- mal and reverse power flow.

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5-8000 A (1 A steps)

Hardware Configuration

1200 VT Configuration

Address Parameter Options

1201 Primary Rating 120-138,000 V (1 V steps)

1202 VT Connect Line-to-Line or Line-to-Neutral

1203 Sec. VT Rating 100-120 V (1 V steps)

Voltage transformers may be connected in either of two ways:

 Two VTs connected open delta-open delta

 Three VTs connected wye-wye

For brevity, the open delta connection is referred to as L-L (line-to-line), while the wye connection is referred to as L-N (line-to-neutral). Wye-delta or delta-wye connection of VTs is not allowed. Figure 4.7 shows the correct VT connections and polarities.

Voltage transformers are specified with an input to output voltage ratio (for example, 12000:120). The secondary voltage rating of the VTs can be set by the Secondary Voltage Rating parameter (1203).

Before leaving the hardware configuration blocks, (only when changing parameters, not when viewing) the ISGS relay displays the message END OF PASSWORD OPERATION?. Press the No button to return to one of the configuration blocks. The message PRESS ANY KEY TO CONTINUE appears. Press any key to return to the screen displayed last before the message prompt appeared. Press the Ye s button if you are finished with the configuration changes. The device prompts you to save the settings.

 Press the Yes button to save the settings. The relay

resets and displays the Power On and Power Meter On displays.

123

Wye-Wye VT Connection

ISGS

V12

 Press the No button if you do not want to save the

changes The message SAVING PROCEDURE ABORTED appears. Press Enter to return to the last address block.

Note: For CT configuration, CTs on the neutral

must be the same rating as other CTs for residual ground sensing, directional neutral sensing, or direct ground sensing.

For VT connections, VTs must be either wye-wye or delta-delta. Wye-delta or delta-wye connections are not permissible.

Open Delta-Open Delta VT Connection

Figure 4.7 Voltage Transformer Connections

Siemens Energy & Automation, Inc. 19

V23

V31

Hardware Configuration

1 2 3

ISGS

910

52 52

Three Phase Current with Residual Ground Sensing

1 2 3

ISGS

1 2 3

ISGS

910

Three Phase Current with Direct Neutral Sensing

1 2 3

ISGS

910

Three Phase Current with Zero Sequence CT Three Phase Current with Direct Ground Sensing

52 = Power Circuit Breaker

= ISGS Internal CT

Figure 4.8 Current Transformer Configuration

20 Siemens Energy & Automation, Inc.

Protective Function Configuration

5 Protective Function Configuration

5.1 Overview

This chapter explains how to set the parameters for the protective functions of the ISGS relay.

Password

All parameter changes require a password. Refer to Section 3.3 on how to enter your password. Viewing parameter settings does not require a password.

Note: The ISGS relay is not password protected

when making parameter changes through Wisdom software.

Configuration Steps

Perform parameter changes using steps 1 through 9 of the standard operating procedures described in Section 3.5.

Parameter Sets

Many protective functions can be set to two different parameter setsset A and set B. These functions are indicated by the letter A or B preceding the address block number. Alternate sets are useful for seasonal settings or for special operating periods. Either set can be selected (in address block

7100) to be the active set that controls the relay operation. The parameters for both sets are entered in the relevant address blocks. Waveform capture buffer settings apply to both parameter sets. Unless you do not desire an alternate set, configure both sets when configuring the relay.

Note: The settings for parameter sets A and B are

entered in the address block. However, the parameter set which the ISGS relay is actively using is selected at address block

7100. Refer to Section 6.11 for discussion of parameter sets.

Actions on Pickup or Trip

Protective functions can be set to have actions occur on pickup or on trip. Binary outputs can be set to be actuated on pickup of a protective function. A protective function is set to trip a breaker by assigning the trip contact that is connected to the breaker (default is Trip 1). Binary outputs can also be assigned to trip a breaker. It is possible, however to have a protective function enabled and not assigned to any output. Events and their sequences are entered in the trip log as usual, but the breaker will not be affected. This setting is useful for monitoring and alarming without tripping, and for waveform capture. For more information on the control of inputs and outputs, refer to Chapter 6.

Pickup

When testing induction disk relays, an established practice is to set the pickup value to 1.0 A of secondary CT output. The time overcurrent curves will show a pickup, but the relay will not trip in a predefined repeatable manner until it reaches 1.3 to 1.5 A. With numerical relays like the ISGS, however, a sustained pickup indication means definite operation. To account for measurement inaccuracies, and to guarantee that the relay will never trip at 100% of pickup or below, the pickup point is set at 106% of the pickup setting to avoid any unintended nuisance trips.

Neutral or Ground

The availability of protective functions for neutral or ground depends on how the external CTs are connected. If a ground or zero-sequence CT is used and connected to the fourth internal CT, the ground or neutral protective function is a ground function. If the fourth CT is connected in the common return of the other three internal CTs (residual), the function is indicated as being neutral. There does not need to be an explicit selection of neutral or ground.

Custom Curve

The custom curve is one user-defined curve that can be used by one or more protective functions that have the custom curve option in the curve list.

Wisdom Software

While the ISGS relay protective functions can be completely configured manually using the LCD and the keypad, Wisdom software allows faster and easier configuration when it is used on a PC connected to either data port. For data port connections refer to Section 2.5.

5.2 Instantaneous Phase Overcurrent (50)

The Instantaneous Phase Overcurrent function consists of a phase instantaneous overcurrent function and an adjustable delay. This function begins timing when any individual phase current exceeds the pickup at 100% of set pickup point and drops out at 95% of the pickup point.

A1500 Instantaneous Phase Overcurrent (50)

Address Parameter Option

1501 Function Enabled or Disabled

1502 Pickup 5 A CTs: 1-120 A

1 A CTs: 0.2-24 A (0.1 A steps)

1504 Time Delay 0-60 s (0.01 s steps)

1510 Freeze Wfm1 on Pickup, on Trip, or None

1511 Freeze Wfm2 on Pickup, on Trip, or None

1512 Blocked by None, 50HS & 50HSN, 50 HSN,

or 50HS

The function can be enabled or disabled (1501).

The range of the pickup value (1502) depends on the secondary phase CT rating (1 A or 5 A), and the value is in secondary amperes.

The time delay (1504) represents the time between pickup and trip and can be adjusted from 0 to 60 seconds in steps of 0.1 second. If the function remains in pickup for longer than the time delay, the function causes a trip. The delay can also be set to infinity so that the function never times out.

Each of the two waveform capture buffers (1510 and 1511) can be independently programmed to freeze snapshots on pickup or trip.

The function is able to actuate any binary output contact on pickup, and any trip or binary output contact on trip.

Siemens Energy & Automation, Inc. 21

Protective Function Configuration

5.3 High-Set Instantaneous Phase Overcurrent (50HS)

The High-Set Instantaneous Phase Overcurrent function causes an undelayed trip when any individual measured phase current exceeds the preprogrammed threshold (pickup value). The relay will trip at 100% of the set pickup point.

A1500 High-SetInstantaneous Phase Overcurrent (50HS)

Address Parameter Option

1551 Function Enabled or Disabled

1552 Pickup 5A CTs: 5-120 A or

1A CTs: 0.2-24 A (0.1 A steps)

1560 Freeze Wfm1 on Trip, or None

1561 Freeze Wfm2 on Trip, or None

The function can be enabled or disabled (1551). The range of the pickup value (1552) depends on the secondary phase CT rating (1 A or 5 A) and the value is in secondary amperes.

Each of the two waveform capture buffers (1560 and 1561) can be independently programmed to freeze snapshots on trip.

The function is able to actuate any binary output contact on pickup, and any trip or binary output contact on trip.

The Instantaneous Neutral or Ground Overcurrent function can be enabled or disabled (1601). The form of protection provided depends on the manner in which the external CTs are connected to the ISGS relay. Figure 4.5 in Chapter 4 shows correct CT connections and polarities.

The range of the pickup value (1602) depends on the secondary neutral CT rating (1 A or 5 A) and the value is in secondary amperes.

The time delay (1604) represents the time between pickup and trip and can be adjusted from 0 to 60 seconds in steps of 0.1 second. If the function remains in pickup for longer than the time delay, this parameter causes a trip. The delay can also be set to infinity so that the function never times out.

Each of the two waveform capture buffers (1610 and 1611) can be independently programmed to freeze snapshots on pickup or trip.

The function is able to actuate any binary output contact on pickup, and any trip or binary output contact on trip.

5.5 High-Set Instantaneous Neutral or Ground Overcurrent (50HSN)

The High-Set Instantaneous Neutral or Ground Overcurrent function causes an undelayed trip when any individual measured phase current exceeds the preprogrammed threshold (pickup value). The relay will trip at 100% of the set pickup point.

5.4 Instantaneous Neutral or Ground Overcurrent (50N)

The Instantaneous Neutral or Ground Overcurrent function has an adjustable delay whose input is the current measured by the neutral CT. It begins timing when the neutral or ground current exceeds the pickup value. The ISGS relay will pickup at 100% of set pickup point and drop out at 95% of the pickup point.

A1600 Instantaneous Neutral or Ground Overcurrent

(50N)

Address Parameter Option

1601 Function Enabled or Disabled

1602 Pickup 5 A CTs: 1-120 A or

1 A CTs: 0.2-24 A (0.1 A steps)

1604 Time Delay 0-60 s (0.01 s steps)

1610 Freeze Wfm1 on Pickup, on Trip, or None

1611 Freeze Wfm2 on Pickup, on Trip, or None

1612 Blocked by None, 50HS & 50HSN, 50HSN,

or 50HS

A1600 High-Set Instantaneous Neutral or Ground

Overcurrent (50HSN)

Address Parameter Option

1651 Function Enabled or Disabled

1652 Pickup 5 A CTs: 5-120 A or

1 A CTs: 0.2-24 A (0.1 A steps)

1660 Freeze Wfm1 on Trip, or None

1661 Freeze Wfm2 on Trip, or None

The High-Set Instantaneous Neutral or Ground Overcurrent function can be enabled or disabled (1651).

The range of the pickup value (1652) depends on the secondary phase CT rating (1 A or 5 A) and the value is in secondary amperes.

Each of the two waveform capture buffers (1660 and 1661) can be independently programmed to freeze snapshots on trip.

The function is able to actuate any binary output contact on pickup, and any trip or binary output contact on trip.

22 Siemens Energy & Automation, Inc.

Protective Function Configuration

5.6 Phase Time Overcurrent (51)

The Phase Time Overcurrent function uses a selected time overcurrent characteristic curve to determine the trip time for the applied phase currents. The defined characteristic curves are valid over a range of multiple of pickup values. The function also includes the ability to select a customer defined curve. This function is always enabled. Refer to Appendix A for detailed trip curve information.

A1700 Phase Time Overvurrent (51)

Address Parameter Option

1702 Curve Inverse

1703 Pickup 5 A CTs: 0.5-20 A or

1705 Time Dial 0.1-9.9 (0.1 steps)

1706 Filter rms or fundamental

1709 Reset Instantaneous or Disk Emulation

1710 Freeze Wfm1 on Pickup, on Trip, or None

1711 Freeze Wfm2 on Pickup, on Trip, or None

1712 Blocked by None, 50HS, 50HSN, or

The Curve parameter (1702) allows the selection of the preprogrammed characteristic curve used by this function. The ISGS relay comes with nine standard and one custom overcurrent characteristic curves that can be adjusted with the Time Dial parameter. The custom curve is a user-definable protective curve that integrates with instantaneous reset. The lower limit of the custom curve is 1.10. The maximum time to trip is the time at 1.10.

The range of the pickup value (1703) depends on the secondary phase CT rating (1 A or 5 A) and the value is in secondary amperes. The function begins timing when any individual phase current exceeds the pickup current setting.

Note: The pickup point is 1.06 of the pickup set-

ting. Refer also to paragraph on Pickup in Section 5.1.

Short Inverse Long Inverse Moderately Inverse Custom Very Inverse Extremely Inverse Definite Inverse Slightly Inverse

T Without Limit

1 A CTs: 0.1-4 A (0.1 A steps)

50HS & 50 HSN

The Reset parameter (1709) offers instantaneous or disk emulation settings. Selecting Instantaneous causes the relay to clear the timer when the current drops below the pickup threshold. Selecting Disk Emulation causes the relay to simulate the integrating disk characteristics of electromechanical relays, where the delay time decays over time. With disk emulation, a relay that continuously picks up and drops out will eventually trip. Set this parameter to Instantaneous when using a custom curve.

Each of the two waveform capture buffers (1710 and 1711) can be independently programmed to freeze snapshots on pickup or trip.

The function is able to actuate any binary output contact on pickup, and any trip or binary output contact on trip.

5.7 Neutral Time Overcurrent (51N)

The Neutral Time Overcurrent function uses a selected time overcurrent characteristic curve to determine the trip time for the applied current at the fourth current input. The defined characteristic curves are valid over a range of multiple of pickup values. The function also includes a customer defined curve. Refer to Appendix A for detailed trip curve information.

A1800 Neutral Time Overcurrent (51N)

Address Parameter Option

1801 Function Enabled or Disabled

1802 Curve Inverse

1803 Pickup 5 A CTs: 0.5-20 A or

1805 Time Dial 0.1-9.9 (0.1 steps)

1806 Filter rms or fundamental

1809 Reset Instantaneous or Disk Emulation

1810 Freeze Wfm1 on Pickup, on Trip, or None

1811 Freeze Wfm2 on Pickup, on Trip, or None

1812 Blocked by None, 50HS, 50HSN, or

Short Inverse Long Inverse Moderately Inverse Custom Very Inverse Extremely Inverse Definite Inverse Slightly Inverse

T Without Limit

1 A CTs: 0.1-4 A (0.1 A steps)

50HS & 50 HSN

The Time Dial parameter (1705) used for the selected curve allows the time-to-trip of the curve to be raised or lowered The dial can be adjusted from 0.1 to 9.9 in steps of 0.1.

The Filter parameter (1706) sets the sensing method used by the function in its pickup calculations. The rms filter uses fundamental current plus harmonics, while the fundamental filter ignores harmonics.

The Neutral or Ground Time Overcurrent function can be enabled and disabled (1801).

Siemens Energy & Automation, Inc. 23

Protective Function Configuration

protective curve that integrates with instantaneous reset. The lower limit of the custom curve is 1.10. The maximum time to trip is the time at 1.10.

The range of the pickup value (1803) depends on the secondary phase CT rating (1 A or 5 A) and the value is in secondary amperes.

The Time Dial parameter (1805) used for the selected curve allows the time-to-trip of the curve to be raised or lowered. The dial can be adjusted from 0.1 to 9.9 in steps of 0.1.

The Filter parameter (1806) sets the sensing method used by the function in its pickup calculations. The rms filter uses fundamental current plus harmonics, while the fundamental filter ignores harmonics.

Figure 5.1 Blocking Capability Diagram

Each of the two waveform capture buffers (1810 and 1811) can be independently programmed to freeze snapshots on pickup or trip.

The function is able to actuate any binary output contact on pickup, and any trip or binary output contact on trip.

5.8 Blocking Capability for Breaker or Interrupter Saving

High-set instantaneous phase overcurrent (50HS) and highset instantaneous neutral or ground overcurrent (50HSN) functions have the capability to block 50, 51, 50N, and 51N selectively to prevent opening an interrupting device should the fault current exceed the rating of the device.

This function is used to keep an electrically-operated load break switch, recloser, or aging circuit breaker from attempting to interrupt current beyond its capability or rating. It must be used in conjunction with a slight delay (25 ms) in 50 so that 50HS can pickup or trip before 50 times out and trips. Should these parameters be set, a fault large enough to cause 50HS to pickup or trip before 50 has timed out will prevent 50 and/or 51, 50N, and 51N from tripping.

50HS/N can also be matrixed to an output contact to block differential tripping of a transformer differential relay when a fault is between the interrupter and the high side (bushings) of the transformer.

5.9 Directional Phase Time Overcurrent (67)

The Directional Phase Time Overcurrent function uses a selected time overcurrent characteristic curve to determine the trip time for the applied phase currents, utilizing the voltages present on the VTs to determine current direction. The defined characteristic curves are valid over a range of multi- ple of pickup values. The function also includes a customer defined curve. Refer to Appendix A for detailed trip curve information. This function is only available if the voltage input option is installed.

A1900 Directional Phase Time Overcurrent (67)

Address Parameter Option

1901 Function Enabled or Disabled

1902 Curve Inverse

1903 Pickup 5 A CTs: 0.5-20 A or

1905 Time Dial 0.1-9.9 (0.1 steps)

1906 Filter rms or fundamental

1907 Impedance 0-90°

1908 Direction Forward or Reverse

1910 Freeze Wfm 1 on Pickup, on Trip, or None

1911 Freeze Wfm 2 on Pickup, on Trip, or None

Short Inverse Long Inverse Moderately Inverse Custom Very Inverse Extremely Inverse Slightly Inverse Definite Inverse

T Without Limit

1 A CTs: 0.1-4 A (0.1 A steps)

24 Siemens Energy & Automation, Inc.

Protective Function Configuration

The Directional Phase Time Overcurrent function can be enabled or disabled (1901).

The Curve parameter (1902) allows the selection of the preprogrammed characteristic curve used by this function. The ISGS relay comes with nine standard overcurrent characteristic curves that can be adjusted with the Time Dial parameter. The custom curve is a user-definable protective curve that integrates with instantaneous reset. The lower limit of the custom curve is 1.10. The maximum time to trip is the time at 1.10.

The range of the pickup value (1903) depends on the secondary phase CT rating (1 A or 5 A) and the value is in secondary amperes. The function begins timing when any individual phase current exceeds the pickup current setting.

The Time Dial parameter (1905) used for the selected curve allows the time-to-trip of the curve to be raised or lowered The dial can be adjusted from 0.1 to 9.9 in steps of 0.1.

The Filter parameter (1906) sets the sensing method used by the function in its pickup calculations. The rms filter uses fundamental current plus harmonics, while the fundamental filter ignores harmonics.

Impedance (1907) sets the angle used by this function. Impedance determines the direction of current flow being measured and can be set from 0 to 90 degrees. The directional characteristic (line) in the complex impedance plane is shown in Figure 5.2. The directional characteristic is always perpendicular to the line impedance vector.

The sensing direction (1908) can be set to forward or reverse. The forward setting allows the directional protection element to pickup on fault current only in the direction opposite to normal power flow.

Each of the two waveform capture buffers (1910 and 1911) can be independently programmed to freeze snapshots on pickup or trip.

The function is able to actuate any binary output contact on pickup, and any trip or binary output contact on trip.

5.10 Directional Neutral or Ground Time Overcurrent (67N)

The Directional Neutral or Ground Time Overcurrent function uses a selected time overcurrent characteristic curve to determine the trip time for the applied current at the fourth current input, utilizing the voltages present on the VTs to determine current direction. The defined characteristic curves are valid over a range of multiple of pickup values. The function also includes a customer defined curve. Refer to Appendix A for detailed trip curve information. This func- tion is only available if the voltage input option is installed.

A2000 Directional Neutral or Ground Time Overcurrent

Address Parameter Option

(67N)

2001 Function Enabled or Disabled

2002 Curve Inverse

2003 Pickup 5 A CTs: 0.5-20 A or

2005 Time Dial 0.1-9.9 (0.1 steps)

2006 Filter rms or fundamental

2007 Impedance 0-90°

2008 Direction Forward or Reverse

2010 Freeze Wfm1 on Pickup, on Trip, or None

2011 Freeze Wfm2 on Pickup, on Trip, or None

Short Inverse Long Inverse Moderately Inverse Custom Very Inverse Extremely Inverse Definite Inverse Slightly Inverse

T Without Limit

1 A CTs: 0.1-4 A (0.1 A steps)

The Directional Neutral or Ground Time Overcurrent function can be enabled or disabled (2001).

The Curve parameter (2002) allows the selection of the preprogrammed characteristic curve used by this function. The ISGS relay comes with nine standard overcurrent characteristic curves that can be adjusted with the time dial parameter (see below). The custom curve is a user-definable protective curve that integrates with instantaneous reset. The lower limit of the custom curve is 1.10. The maximum time to trip is the time at 1.10.

Figure 5.2 Directional Characteristic

Siemens Energy & Automation, Inc. 25

Protective Function Configuration

The range of the pickup value (2003) depends on the secondary phase neutral CT rating (1 A or 5 A) and the value is in secondary amperes. The function begins timing when any individual neutral current exceeds the pickup current setting.

Note: The pickup point is 1.06 of the pickup set-

ting. Refer also to paragraph on Pickup in Section 5.1.

The Time Dial (2005) used for the selected curve allows the time-to-trip of the curve to be raised or lowered The dial can be adjusted from 0.1 to 9.9 in steps of 0.1.

The Filter (2006) sets the sensing method used by the function in its pickup calculations. The rms filter uses fundamental current plus harmonics, while the fundamental filter ignores harmonics.

Impedance (2007) sets the angle used by this function. It determines the direction of current flow being measured and can be set from 0 to 90 degrees. The directional characteristic (line) in the complex impedance plane is shown in Figure 5.2. The directional characteristic is always perpendicular to the line impedance vector.

The sensing direction (2008) can be set to forward or reverse. The forward setting allows the directional protection element to pickup on fault current only in the direction of normal power flow.

Each of the two waveform capture buffers (2010 and 2011) can be independently programmed to freeze snapshots on pickup or trip.

The Directional Neutral or Ground Time Overcurrent function is able to actuate any binary output contact on pickup, and any trip or binary output contact on trip.

The Overvoltage function can be enabled or disabled (2201).

The Curve parameter (2202) allows the selection of a definite time delay or a characteristic curve. When the definite time characteristic is selected, the time delay begins as soon as the device goes into pickup. The inverse time characteristic utilizes a moderate inverse curve using the time dial.

The Pickup Source Voltage parameter (2203) indicates the VT connection. If the VTs are connected line-to-ground, the device can pickup on line-to-line or line-to-ground voltages. If the VTs are connected line-to-line, the VTs can only pickup on line-to-line voltages. The maximum continuous voltage across a VT input is 150 VAC.

The pickup value (2204) is in secondary volts ranging from 60 to 250 V. The function begins timing when any individual phase voltage exceeds the pickup voltage setting.

The time delay (2205) represents the time between pickup and trip and can be set when definite time is selected. The delay can be adjusted from 0.1 to 60.0 seconds in steps of

0.01 second. If the function remains in pickup for longer than the time delay, the function causes a trip. The delay can also be set to infinity so that the function never times out.

The Time Dial parameter (2206) is used for the characteristic curve. The dial allows the time-to-trip of the curve to be raised or lowered. It can be adjusted from 0.1 to 9.9 in steps of 0.1.

Each of the two waveform capture buffers (2210 and 2211) can be independently programmed to freeze snapshots on pickup or trip.

The function is able to actuate any binary output contact on pickup, and any trip or binary output contact on trip.

5.11 Overvoltage (59)

The Overvoltage function causes a trip if the rms value of any of the line voltages exceeds a set level. This function is only available if the voltage input option is installed.

A2200 Overvoltage (59)

Address Parameter Option

2201 Function Enabled or Disabled

2202 Curve Definite

Inverse Moderately Inverse Very Inverse

2203 Pickup Source V Line-to-ground

Line-to-line

2204 Pickup 60-250 V (0.1 V steps)

2205 Time Delay (Def.) 0.1-60 s (0.01 s steps),

or infinity

2205 Time Dial (Inverse) 0.1-9.9 (0.1 steps)

2210 Freeze Wfm2 on Pickup, on Trip, or None

2211 Freeze Wfm2 on Pickup, on Trip, or None

5.12 Undervoltage (27)

The Undervoltage function causes a trip if the rms value of any of the line voltages falls below a set level and can be useful for capturing power quality disturbances. This function is only available if the voltage input option is installed.

2300 Undervoltage 27

Address Parameter Option

2301 Function Enabled or Disabled

2302 Curve Definite

Inverse Moderately Inverse Very Inverse

2303 Pickup Source V Line-to-Neutral or Line-to-Line

2304 Pickup 40-230 V (0.1 V steps)

2305 Time Delay (Def.) 0.1-60 s (0.01 s steps),

or infinity

2305 Time Dial (Inverse) 0.1-9.9 (0.1 steps)

2310 Freeze Wfm 2 on Pickup, on Trip, or None

2311 Freeze Wfm 2 on Pickup, on Trip, or None

26 Siemens Energy & Automation, Inc.

Protective Function Configuration

The Undervoltage function can be enabled or disabled (2301).

The Curve parameter (2302) allows the selection of a definite time delay or a characteristic curve. When the definite time characteristic is selected, the time delay begins as soon as the device goes into pickup. The inverse time characteristic utilizes a moderate inverse curve using the time dial.

The Pickup Source Voltage parameter (2303) indicates the VT connection. If the VTs are connected line-to-ground, the device can pickup on line-to-line or line-to-ground voltages. If the VTs are connected line-to-line, the VTs can only pickup on line-to-line voltages. The maximum continuous voltage across a VT input is 150 VAC.

The pickup value (2304) is in secondary volts ranging from 60 to 250 V. The function begins timing when any individual phase voltage exceeds the pickup voltage setting.

The time delay (2305) represents the time between pickup and trip and can be set when definite time is selected. The delay can be adjusted from 0.1 to 60.0 seconds in steps of

0.01 second. If the function remains in pickup for longer than the time delay, the function causes a trip. The delay can also be set to infinity so that the function never times out.

The Time Dial parameter (2306) is used for the characteristic curve. The dial allows the time-to-trip of the curve to be raised or lowered. It can be adjusted from 0.1 to 9.9 in steps of 0.1.

Each of the two waveform capture buffers (2310 and 2311) can be independently programmed to freeze snapshots on pickup or trip.

The function is able to actuate any binary output contact on pickup, and any trip or binary output contact on trip.

5.13 Phase Sequence Voltage (47)

The Phase Sequence Voltage function operates instantaneously if the correct system voltage phase sequence defined in the hardware configuration is not present at the device voltage inputs. This function will not respond if the input to the device is less than 40 V line-to-line or 23.1 V lineto-neutral. The function operates without delay or inverse time characteristic. It responds in 100 ms or less.

The Phase Sequence Voltage function can be used to prevent closure of a breaker. The assigned output contact would be wired to open a contact in the breaker-close circuit and remain activated until the line rotation is normal.

A2400 Phase Sequence Protection (47)

Address Parameter Option

2401 Function Enabled or Disabled

2410 Freeze Wfm 1 on Trip, or None

2411 Freeze Wfm 2 on Trip, or None

The 47 Phase Sequence Voltage function can be enabled or disabled (2401).

Each of the two waveform capture buffers (2410 and 2411) can be independently programmed to freeze snapshots on trip.

The function is able to actuate any binary output contact on pickup, and any trip or binary output contact on trip.

5.14 Negative Sequence Voltage (47N)

The Negative Sequence Voltage function operates when the percent negative sequence voltage exceeds the preset value for a specified time. This function resets instantaneously when the negative sequence voltage drops below pickup.

A2400 Negative Sequence Voltage (47N)

Address Parameter Option

2451 Function Enabled or Disabled

2452 Curve Definite or Inverse

2453 Pickup 4-40% negative sequence

(1% steps)

2454 Time Delay (Def.) 0-100 s (0.01 s steps),

or infinity

2455 Time Dial (Inverse) 0.1-9.9 (0.1 steps)

2456 Max Time (Inverse) 1-250 s (1 s steps)

2457 Blocked at 40-120 V (1 V steps)

2460 Freeze Wfm 2 on Pickup, on Trip, or None

2461 Freeze Wfm 2 on Pickup, on Trip, or None

The Negative Sequence Voltage function can be enabled or disabled (2451).

The Curve parameter (2452) allows the selection of a definite time delay or an inverse curve. The inverse time characteristic utilizes a moderate inverse curve using the time dial.

The pickup value (2453) ranges from 4% to 40% of negative sequence voltage. The function begins timing when the percent of negative sequence voltage exceeds the preset value for a specified time.

The time delay (2454) represents the time between pickup and trip and can be set when definite time is selected. The delay can be adjusted from 0 to 100 seconds in steps of

0.01 second. The delay can also be set to infinity so that the

function never times out.

The Time Dial parameter (2455) is used for the characteristic curve. The dial allows the time-to-trip of the curve to be raised or lowered. It can be adjusted from 0.1 to 9.9 in steps of 0.1.

Siemens Energy & Automation, Inc. 27

Protective Function Configuration

When the curve is set to inverse, the Max Time parameter (2456) sets an absolute maximum amount of time that the function will remain in pickup regardless of the inverse curve. The value ranges from 1 to 250 seconds and can be set in steps of 1 second.

Blocking (2457) can be set from 40 to 120 V. Regardless of the setting, the function is automatically blocked if the voltage drops below 40 V. An event will be generated when this function is blocked due to an undervoltage condition.

Each of the two waveform capture buffers (2460 and 2461) can be independently programmed to freeze snapshots on pickup or trip.

The function is able to actuate any binary output contact on pickup, and any trip or binary output contact on trip.

5.15 Overfrequency (81O)

The Overfrequency function has only a definite time characteristic and causes a time-delayed trip if the system line frequency rises above a set level.

A2500 Overfrequency (81O)

Address Parameter Option

2501 Function Enabled or Disabled

2502 Pickup Nominal frequency

60.1-65.0 Hz (0.1 Hz steps)

2504 Time Delay 0-100 s (0.01 s steps),

or infinity

2505 Blocked at 40-120 V (at VT input)

(1 V steps)

2510 Freeze Wfm1 on Pickup, on Trip, or None

2511 Freeze Wfm2 on Pickup, on Trip, or None

5.16 Underfrequency (81U)

The Underfrequency (81U) function has only a definite time characteristic and causes a time-delayed trip if the system line frequency drops below a set level. This function can be useful for load shedding applications.

A2500 81U Underfrequency

Address Parameter Option

2551 Function Enabled or Disabled

2553 Pickup Nominal frequency

55.0-59.9 Hz (0.1 Hz steps)

2554 Time Delay 0-100 s (0.01 s steps),

or infinity

2556 Blocked at 40-120 V (at VT input)

(1 V steps)

2560 Freeze Wfm1 on Pickup, on Trip, or None

2561 Freeze Wfm2 on Pickup, on Trip, or None

The Underfrequency function can be enabled or disabled (2551).

The function begins timing when the frequency drops below the pickup frequency setting (2553).

The time delay (2554) represents the time between pickup and trip. The delay can be adjusted from 0 to 100 seconds in steps of 0.1 second. The delay can also be set to infinity so that the function never times out.

Blocking (2556) can be set from 40 to 120 V. Regardless of the setting, the function is automatically blocked if the voltage drops below 40 V. An event will be generated when this function is blocked due to an undervoltage condition.

The Overfrequency function can be enabled or disabled (2501).

The function begins timing when the frequency exceeds the pickup frequency setting (2503).

The time delay (2504) represents the time between pickup and trip. The delay can be adjusted from 0 to 100 seconds in steps of 0.1 second. The delay can also be set to infinity so that the function never times out.

Blocking (2506) can be set from 40 to 120 V. Regardless of the setting, the function is automatically blocked if the voltage drops below 40 V. An event will be generated when this function is blocked due to an undervoltage condition.

Each of the two waveform capture buffers (2510 and 2511) can be independently programmed to freeze snapshots on pickup or trip.

The function is able to actuate any binary output contact on pickup, and any trip or binary output contact on trip.

28 Siemens Energy & Automation, Inc.

Each of the two waveform capture buffers (2560 and 2561) can be independently programmed to freeze snapshots on pickup or trip.

The function is able to actuate any binary output contact on pickup, and any trip or binary output contact on trip.

5.17 Breaker Failure (50BF)

The Breaker Failure function responds to a fault condition where any phase current being measured by the CTs does not drop below a programmable level. Whenever another protective function activates the contact identified by the breaker parameter, (usually Trip 1), this function will wait until the set amount of time has expired. Then it checks the phase currents. If they are not equal to or less than the set pickup value, the function executes its defined actions.

Protective Function Configuration

2800 50BF Breaker Failure

Address Parameter Option

2801 Function Enabled or Disabled

2802 Pickup 5 A CTs: 0.25-5 A

1 A CTs: 0.05-1 A (0.01 A steps)

2804 Delay 8-254 cycles

2805 Check current, breaker opened,

current or breaker opened

The 50BF Breaker Failure function can be enabled and disabled (2801). When enabled, the protective function begins monitoring the current flow in the circuit following a trip command by the relay. Simultaneously, the protective function starts a timer. If the current flow does not drop below the pickup value specified (2802) and before the set time delay (2804) has elapsed, a breaker failure is assumed. At this point, another trip command can be issued to a different breaker (via a different output ocntact if available).

The condition of a breaker failure trip depend on the method chosen, the value of the current after the time has run out, and the position of the a and b switches.

The range of the pickup value (2802) is based on the secondary phase CT rating and is in secondary amperes.

The time delay (2804) represents the time between pickup and trip. The delay can be adjusted from 8 to 254 line cycles of delay. The function operates if it remains in pickup for longer than the time delay.

Breaker failure protection monitors the current flow only following a trip by the contact identified at address 1004 (see Section 4.2). This is the contact matrixed to the overcurrent protection.

Exceptions to the normal operating conditions include the presence of push-to-test switches across either the a-switch, b-switch, or both. A push-to-test switch across the b-switch will produce a false indication of a breaker mechanism error when the breaker is actually closed. A push-to test switch across the a-switch (and hence across the trip solenoid) will produce a false indication of a breaker mechanism error when the breaker is actually closed.

The Breaker Mechanism function (8305), when enabled, senses an error in the mechanism that controls the position of one or both switches (breaker mechanism error), causes an action to be taken, and an event to be logged if the switches are ever both closed for more than 100 ms. No other time delay is implemented. When this function detects an error, it is considered to be in pickup until the condition is no longer present.

The ISGS relay considers the b-switch to be more reliable. If it senses the switches both open at the same time, the breaker is considered to have a trip coil continuity error or to be withdrawn. The 52a switch closed and the 52b switch open are interpreted as a closed breaker. If the relay senses the 52a switch open and the 52b switch closed, the breaker is considered to be open. Refer also to Table 5.3.

5.18 Demand Setpoints

The ISGS relay is capable of activating outputs and sending events when predefined demand calculations exceed the set thresholds. These setpoints can be enabled or disabled and are capable of activating any output. Measurement and setpoint parameters in address block 3100 set the alarm reporting threshold for the ISGS relay.

The Demand Parameters function selects the time periods for demand calculations performed by the relay and allows the user to enable overcurrent demand and kilowatt demand protection.

Breaker position is sensed through dedicated binary inputs that monitor the 52a and 52b switches on the breaker mechanism (breaker mounted). The 52a and 52b switches have a total of four possible position combinations which can be decoded as illustrated in Table 5.3. The 52a and 52b switches referred to are those which traditionally provide indication of circuit breaker position (52b) and trip coil continuity (52a). All error reporting can be enabled and disabled, and the actions to be taken are configurable. Refer to

Section 6.6.

Table 5.3 52a and 52b Switches Decoding

52a Switch Position

Open Open Trip Coil Continuity Error, or

Open Closed Circuit Breaker Open

Closed Open Breaker Closed

Closed Closed Circuit Breaker Mechanism Error

52b Switch Position

Condition Registered

Breaker Withdrawn

3100 Demand Parameters

Address Parameter Option

3101 Demand Interval 15, 30, 60 minutes

3102 Sync Time 0, 15, 30, or 45 after hour

3103 Subperiods 60 1, 2, 3, 4, 6, or 12

3104 Subperiods 30 1, 2, 3, or 6

3105 Subperiods 15 1 or 3

3106 I Av Dmd Function Enabled or Disabled

3107 I Av Dmd Pickup 0-9999 A (1 A steps)

3108 KW Dmd Function Enabled or Disabled

3109 KW Dmd Pickup 0-999,999 kW (1 kW steps)

Demand intervals (periods) are set to 15, 30, or 60 minutes (3101). Demand calculations are updated at the end of every demand period.

Demand period calculations can begin on the hour or at any quarter hour afterwards. The intervals are indicated as 0, 15, 30, or 45 minutes and are set in the Sync Time parameter (3102).

Siemens Energy & Automation, Inc. 29

Protective Function Configuration

Demand calculations are made every subperiod (3103, 3104, or 3105). The number of subperiods depends on the length of the demand interval and is based on 10, the minimum number of monitoring intervals in a subperiod. For example, a 15 minute interval can have one or three subperiods, a 30 minute interval can have 1, 2, 3, or 6 subperiods. The length of a subperiod is your demand period divided by the number of subperiods.

The Average Current Demand function can be enabled or disabled (3106) in this Demand Setpoints function. When enabled, the Overcurrent Demand function causes an alarm if the average current demand value exceeds the setpoint.

The pickup value for the Average Current Demand function (3107) ranges from 0 to 9999 A.

The Kilowatt Demand function (3108) can be enabled or disabled. When enabled, the Kilowatt Demand function causes an alarm if the kilowatt demand value exceeds the setpoint.

The pickup value for the Kilowatt Demand function (3109) ranges from 0 to 999,999 kW.

5.19 Power Setpoints

The ISGS relay is capable of activating outputs and sending events when predefined power measurements exceed the set thresholds. These setpoints can be enabled or disabled and are capable of activating any output. Measurement and setpoint parameters in address block 3200 set the alarm reporting threshold for the ISGS relay.

The kVAR and the kVA functions (3201 and 3203) can be enabled or disabled. If enabled, the functions cause an alarm if the kVAR or the kVA value exceeds the setpoint for the preset time delay.

The kVAR and the kVA function pickup value (3202 and

3204) ranges from 0 to 999,999 kVAR or kVA.

The time delay for kVAR and kVA can be adjusted from 0 to 3600 seconds in steps of 1 second.

The leading or lagging power factor function can be enabled or disabled (3207 and 3211). If one of the functions is enabled, it causes an alarm if the power factor value leads or lags the setpoint.

The threshold for both leading and lagging power factors (3208 and 3212) ranges from 0.2 to 1.0 in steps of 0.1.

The sign for the leading or lagging power factor (3209 and

3213) can be set to lead or lag.

The time delay for both leading and lagging power factors can be adjusted from 0 to 3600 seconds in steps of 1 second.

The leading setpoint will react if the measured power factor leads the setpoint for the set delay time. The lagging setpoint will react if the measured power factor lags the setpoint for the set delay time.

The Power Setpoints function allows the setting of all power setpoints.

3200 Power Setpoints

Address Parameter Selection

3201 KVAR Function Enabled or Disabled

3202 KVAR Pickup 0-999,999 kVAR (1 kVAR steps)

3203 KVAR Time Delay 0-3600 s (1 s steps)

3204 KVA Function Enabled or Disabled

3205 KVA Pickup 0-999,999 kVA (1 kVA steps)

3206 KVA Time Delay 0-3600 s (1 s steps)

3207 PF Lead Function Enabled or Disabled

3208 PF Lead Pickup 0.2-1.0 (0.1 steps)

3209 PF Lead Sign lag or lead

3210 PF Lead Delay 0-3600 s (1 s steps)

3211 PF Lag Function Enabled or Disabled

3212 PF Lag Pickup 0.2-1.0 (0.1 steps)

3213 PF Lag Sign lag or lead

3214 PF Lag Delay 0-3600 s (1 s steps)

(default is 100000)

(default is 1800)

(default is 0.8)

(default is 1800)

(default is 0.8)

(default is 1800)

30 Siemens Energy & Automation, Inc.

6 Control & Communications

6.1 Matrixing Events to Outputs

One of the powerful functions of the ISGS relay is its ability to send control outputs based on inputs from the real world. This process of assigning various outputs to various inputs is called matrixing. Utilities in Europe call this marshalling. Since most customers in America are not familiar with this term and because the word configuring is used in too many other contexts, we use the more specific word matrixing. The inputs that can be used to control outputs can be binary (on/off) inputs and communication events. The binary inputs determine if a certain type of protection is being violated and can close a trip contact or binary output based on the intelligence of the relay. The outputs can be trip contacts or binary outputs. Figure 6.1 shows in general form how the outputs can be controlled by various inputs. The outputs can also be controlled by a command from an external communication device on the network; this input is called a Communication Event. The ISGS relay offers four binary inputs (BI 1, BI 2, BI 3, and BI 4), two binary outputs (BO 1, BO 2), and three trip contacts (Trip 1, Trip 2, and Trip 3). Matrixing is used for blocking and event-driven functions as well as for binary input and setpoint functions.

A physical input is a hardware connection to the relay such as binary input 1 (BI 1). A logical input is an input to a function internal to the relay such as the blocking input for undervoltage (protective function, 27) (see Section 5.12). The logical input can only be activated if it is matrixed to the physical input. Connecting the physical input BI 1 to the logical input for function number 27 allows BI 1 to block PF27 when active. Up to 10 logical inputs can be matrixed to each output contact.

Control & Communications

Events

Event 1

50HS

Event 2

Event 3

50N

Comm Event

Figure 6.1 Matrixing Inputs to Outputs

Outputs

Output Contact

Trip Contact

Binary Output

Output 1

Output 2

Output 3

or or

A physical output is a trip contact or binary output (BO). A logical output is the output of a function internal to the relay such us Pickup, which is active when function 27 is in pickup. Connecting a logical output to a physical output allows function 27 to trip (actuate a contact). Up to 20 logical outputs can be matrixed to each output contact.

Note: Matrixing includes defining which protective

functions actuate an output contact, and which output contact they actuate. Matching the output connections of the relay with the wiring connections of the protective circuit, including the connections to the circuit breaker, is extremely important. If the matrixing of the ISGS relay is changed, doublecheck the wiring of the protective circuit, and always test that the operation of a protective function results in the circuit breaker tripping.

Without matrixing, an event will cause an entry in the Event Log, but nothing will happen with the outputs and no control activity will occur. With matrixing, an event can cause the relay to trip a breaker (for example) as well as causing an entry in the Event Log.

Siemens Energy & Automation, Inc. 31

Control & Communications

Matrixing Procedure

The following steps provide a detailed description on how to matrix the ISGS relay manually using the front panel LCD and keypad. Before matrixing the relay, ensure that power is applied to the relay which is indicated by the lit system LED (green).

Table 6.1 Matrixing Procedure

How to Matrix Inputs to Outputs

Step Description

Press Direct Addr key; enter block address of one of the matrix functions (6100, 6200, or 6400) using the numeric keypad; press Enter key.

Press Direct Addr key; enter the address of the desired

parameter using the numeric keypad; press Enter key. Skip to step 4.

A complete list of ISGS relay parameters is provided in Appendix C.

Use Single Arrow keys to scroll to the desired address.

Press F key once; use Single Arrow keys to scroll to the

desired matrix position (001-020)

Press Password key; enter your level 3 password followed by Enter key. The message PW THREE ACCEPTED appears. Press Enter key again to return to

the screen displayed last before password entry.

For password levels, proper password entry, and display messages, refer to Section 3.3.

The display cursor located next to the address is blinking (otherwise repeat step 4). Press No key until the desired parameter option appears on display. Press Enter key to set the displayed option.

Your settings can be undone any time while still in the

same address block by simply returning to the parameter and assigning a new value.

Use Single Arrow keys to move to the next matrix position to change additional parameters, or proceed to the next step.

Press F key. At the blinking cursor position, the letter F is displayed. Press Enter key. Message SAVE NEW SET-

TINGS? appears.

Press Yes key followed by Enter key to save settings and reset relay to new parameters. Message NEW SETTINGS SAVED appears.

Press No key to abort any changes made. Message SAVING PROCEDURE ABORTED appears.

Press Enter key to return to screen displayed last before

starting saving procedure.

Wisdom Software

While the ISGS relay can be matrixed manually using the keypad and LCD, Wisdom configuring and analysis software allows faster and easier configuration by connecting a PC installed to either data port. For data port connections refer to Section 2.5.1. All binary inputs, binary outputs, and the trip contacts can be simply checked off inside the configuration window of protective and other functions. Refer to Chapter 8 for more description of how this can be done with Wisdom software.

32 Siemens Energy & Automation, Inc.

Control & Communications

6.2 Binary Inputs

Binary inputs are optically-isolated voltage level sensors with a fixed threshold. The input is considered activated if voltage above the threshold is applied and de-activated if no voltage or voltage below the threshold is applied.

The status of the binary inputs is monitored whether they are configured or not. As a result, the relay logs events when any binary input changes state (from active to de-active or vice versa).

Actions matrixed to binary inputs have the choice of being performed when the binary input is activated (Hi) or deactivated (Lo). For example, BI1 >blk 50 Hi means that 50 is blocked when BI1 is activated. And BI1 >blk 50 Lo means that 50 is blocked when BI1 is de-activated.

The ISGS relay displays the options at each matrix position in the sequence listed in the table below.

6100 Binary Inputs

Address

Parameter

6101 Input 1 001

6102 Input 2 001-010 (same as Input 1 above)

6103 Input 3 001-010 (same as Input 1 above)

6104 Input 4 001-010 (same as Input 1 above)

Matrix Position

to 010

(Options apply to each matrix position)

Option Option (cont.)

not matrixed Frz.Buff1 Hi Frz.Buff1 Lo Frz.Buff2 Hi Frz.Buff2 Lo blk 47N Hi blk 47N Lo blk 47 Hi blk 47 Lo blk 81U Hi blk 81U Lo blk 81O Hi blk 81O Lo blk 50 Hi blk 50 Lo blk 50N Hi blk 50N Lo blk 50HS Hi blk 50HS Lo blk 50HSN Hi blk 50HSN Lo blk 51N Hi blk 51N Lo

blk 59 Hi blk 59 Lo blk 27 Hi blk 27 Lo blk 67 Hi blk 67 Lo blk 67N Hi blk 67N Lo blk 50BF Hi blk 50BF Lo blk ComEvt Hi blkComEvt Lo SwitchPara Hi SwitchPara Lo BI1 Hi BI1 Lo BI2 Hi BI2 Lo BI3 Hi BI3 Lo BI4 Hi BI4 Lo

6.3 Binary Outputs

The ISGS relay offers two binary outputs. The options at each matrix position are displayed in the sequence listed in the table below.

6200 Binary Outputs

Address

6201 Output 1

6202 Output 2

Parameter

(BO 1)

(BO 2)

Matrix Position

001 to 020

(Options apply to each matrix position)

001-020 (same as Output 1 above)

Option Option (cont.)

not matrixed BI1 BI2 BI3 BI4 Error Sum I Error Sym I Error Sym V OC Pickup OC Trip Non OC PU Non OC Trip Relay Pickup Relay Tripped no f f <> 50HS Trip 50HSN Trip 81O Pickup 81O Trip UV blks 81O 81U Pickup 81U Trip UV blks 81U 47N Pickup 47N Trip UV blks 47N 50HS blks 50 50HSN blks 50 50 Pickup 50 Trip 50HS blks 50N 50HSN blks

50N 50N Pickup 50N Trip 50HS blks 51 50HSN blks 51

51 Pickup 51 Trip 50HS blks 51N 50HSN blks

51N Pickup 51N Trip 67 Pickup 67 Trip 67N Pickup 67N Trip 27 Pickup 27 Trip 59 Pickup 59 Trip 47 Trip OvrBrOps PU OvrBrAmps PU OvrAmpsDmd

PU OvrkWDmd PU OvrkVAR PU OvrkVA Pickup PFLag Pickup PFLead Pickup 50BF Pickup 50BF Trip TrScMon PU TrCoilCont PU BrMech PU CommEvent 1 CommEvent 2 CommEvent 3 CommEvent 4 CommEvent 5

51N

On power-on or reset, the relay creates an internal state change of all binary inputs to determine whether they are active or inactive, and it performs all actions corresponding to their condition and matrixing accordingly.

Binary inputs can be matrixed to disable the acceptance of communication events.

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Control & Communications

6.4 Trip Contacts

The ISGS relay offers up to three trip contacts which are monitored by the microprocessor. Trip contacts may be configured by the user to trip the relay based on any of a number of functions. Trip contact reaction time is about 4.5 ms.

The relay displays the options at each matrix position in the sequence listed in the table below.

6400 Trip Contacts

Address

Parameter

6401 Contact 1 001

6402 Contact 2 001-020 (same as Contact 1 above)

6403 Contact 3 001-020 (same as Contact 1 above)

Matrix Position

to 020

(Options apply to each matrix position)

Option Option (cont.)

not matrixed BI1 BI2 BI3 BI4 OC Trip NonOC Trip Relay Tripped 50HS Trip 50HSN Trip 81O Trip 81U Trip 47N Trip 50 Trip 50N Trip 51 Trip 51N Trip 67 Trip 67N Trip 27 Trip

59 Trip 47 Trip OvrBrOps PU OBrAmps PU OvrAmps-

Dmd PU OkWDmd PU OvrkVAR PU OvrkVA PU PFLag PU PFLead PU 50BF Trip TrScMon PU TrCoilCont PU BrMech PU CommEvent 1 CommEvent 2 CommEvent 3 CommEvent 4 CommEvent 5

6.5 Comm Events

Protective functions are internally generated events that can trip a relay. For the protection to function properly, the processor interprets these events (inputs) and makes a decision. Communication (Comm) events are externally generated messages that can trip a relay without any interpretation. This remote communication allows Comm events to control outputs (contacts), such as opening a breaker; or switch parameter sets if matrixed to a binary input. Comm events are sent from a PC or other devices on the RS-232 or RS-485 networks.

Comm events can be blocked (disabled) with binary inputs to prevent remote parameterization during service periods or as a general safety measure. Refer to the list of binary inputs in

Section 6.2.

6.6 Breaker Monitoring

To increase the security of the protective system, it is helpful to monitor several parameters directly from the switchgear. The ISGS relay can monitor the components such as the 52a and the 52b switches, the traditional circuit breaker position lamps, and the tripping voltage supply.

The 52a and 52b switches have a total of four possible position combinations which can be decoded as illustrated in Tab l e 6 .1. The 52a and 52b switches referred to are those which traditionally provide indication of circuit breaker position (52b) and trip coil continuity (52a). All error reporting can be enabled and disabled, and the actions to be taken are configurable.

Table 6.1 52a and 52b Switches Decoding

52a Switch Position

Open Open Trip Coil Continuity Error, or

Open Closed Circuit Breaker Open

Closed Open Breaker Closed

Closed Closed Circuit Breaker Mechanism Error

The ISGS relay monitors:

 breaker position

 trip coil continuity

 trip source impedance.

Breaker position is sensed through dedicated binary inputs that monitor the 52a and 52b switches on the breaker mechanism (breaker mounted). Trip coil continuity is monitored by continually sensing a current that flows through the trip coil. Trip source impedance is checked using a switchable electronic load across the trip voltage supply.

8300 Breaker Monitoring

Address Function/

8301 TripSrcImp Enabled or Disabled

8302 TripSrcFail Yes or No

8303 TrpCoil Cont Enabled or Disabled

8304 TrpCoilFail Yes or No

8305 BrkrMech Enabled or Disabled

52b Switch Position

Parameter

Condition Registered

Breaker Withdrawn

Options

34 Siemens Energy & Automation, Inc.

Control & Communications

The Trip Source Impedance parameter (8301) can be enabled or disabled. When enabled, the circuit periodically monitors the trip supply voltage (auxiliary voltage, station battery) and will perform an action (for example, close a binary output) should the voltage drop below ANSI minimum values. Monitoring the trip source (auxiliary power) to detect bad connections and weak batteries is done by periodically drawing a small current from the trip supply and monitoring the subsequent sag in the voltage. Using averaging techniques, the trip source impedance can be estimated. Based on this estimate, an error message is given if the source voltage drops below ANSI minimum values during a trip event. When the function is enabled, it can cause the actuation of any of the output contacts. This circuit can function only in true DC trip systems. It should be disabled and the inputs left disconnected when the device is used in AC trip systems.

The Trip Source Fail parameter of the Trip Source Impedance function (8302), when set to yes, allows the relay fail contact to be asserted when the monitoring function detects an error. When set to no, the relay fail contact is not affected.

The Trip Coil Continuity function (8303), when enabled, senses a trip coil continuity error, causes an action to be taken, and logs the event if the 52a and 52b switches are ever both open at the same time for more than 100 ms. No other time delay is implemented. When the function detects the error, the function is considered to be in pickup until the condition is no longer present.

The Trip Coil Fail parameter of the Trip Coil Continuity function (8304), when set to yes, allows the relay fail contact to be asserted when the monitoring function detects an error. When set to no, the relay fail contact is not affected.

6.7 Logs and Breaker Monitor Reset

With the Reset function, the user can independently reset logs and breaker monitoring functions. Performing the reset operation for an individual category will reset all values within that category to zero, but new values are tracked immediately. The Resets address block also includes functions to set the number of breaker operations and the sum of interrupted current on each phase.

8200 Resets

Address Function Option/Display

8201 Trip Log yes, in progress, successful

8202 Min/Max Values yes, successful

8203 Energy yes, successful

8204 Breaker Ops yes, successful

8205 Sum I interrupted yes, in progress, successful

8211 Breaker Ops

(Counter)

8212 Sum IL1 0-99999 kA (0.01 kA steps)

8213 Sum IL2 0-99999 kA (0.01 kA steps)

8214 Sum IL3 0-99999 kA (0.01 kA steps)

The Trip Log reset function (8201) can be set to yes to reset the values in all trip logs. This function requires a password. When the parameter is activated by setting it to yes, the LCD displays the message IN PROGRESS followed by the message SUCCESSFUL.

0-65535

Because the 52b switch does not need to interrupt the current through the trip coil, it provides a reliable indication of breaker position: when it is open, the breaker is considered closed. The practice (in DC trip systems) of placing a red status indicator lamp in series with the trip coil allows a convenient method for monitoring the continuity of the trip coil. When the circuit breaker is closed, the 52a switch is closed and the voltage across them and the trip coil is small because most of the voltage drop occurs across the indicating lamp circuit. If the trip coil is open or the a-switch is defective, an error condition exists and an alarm can be generated. An exception is a breaker withdrawn for servicing.

Resetting the minimum and maximum logs with the Min/Max Values reset function (8202) discards all current values, but new minimum and maximum values are tracked immediately.

The Energy reset function (8203) resets all demand values.

The Breaker Operations reset function (8204) resets the breaker operations counter.

The sum of interrupted current reset function resets the sum of interrupted current for each phase (8205).

The Breaker Operations (Counter) reset function (8211) sets the number of breaker operations, for example, when moving the breaker to a cubicle protected by an ISGS relay where the previous breaker had a different operations count.

The Sum of Interrupted Current for phases A, B, and C reset functions (8212, 8213, 8214) can be set from 0 to 99999 kA.

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Control & Communications

6.8 Breaker Operations Count

Breaker Operations refers to the number of times the device has opened the breaker. The Breaker Operation function allows the setting of the breaker monitoring parameters.

The Sum of Interrupted Current is the total sum of the cur- rents that were interrupted by these breaker openings. The setpoint is triggered when any phase exceeds the set limit.

3500 Breaker Operation

Address Parameter Selection

3501 Int. I Function Enabled or Disabled

3502 Int. I Pickup 0-9999.90 kA

(0.01 kA steps)

3503 Brks Ops Function Disabled or Enabled

3504 Brks Ops Counter 0-65535

The Interrupted I (current) Function (3501) can be enabled or disabled. When enabled, the function generates an event (which can be matrixed to an output contact) when the interrupted current exceeds the pickup value. The interrupted current pickup value (3502) can be set to any value from 0 to

9999.90 kA in steps of 0.01 kA.

The Circuit Name (7401) identifies a relay, breaker, bus, or feeder which your ISGS relay is protecting. This string (up to 16 characters) is user-definable with Wisdom software. Accessing this parameter through the keypad allows only the display of this string.

All circuit boards installed in your ISGS relay are provided with a serial number and a special identification number. These numbers can be displayed by accessing addresses 7403 to 7407.

Similar to the firmware version identification number of your ISGS relay described in Section 4.1, the serial and identification numbers of your main board and optional board(s) help Siemens track the versions and options available on your boards.

Binary Inputs (7408) displays the status of the binary inputs as illustrated in Figure 6.2. The status updates automatically as they change.

The Breaker Operations Function (3503) can be enabled or disabled. When enabled, the function counts the breaker operations since the last reset.

The Breaker Operations Counter (3504) can be set from 0 to

65535.

6.9 Hardware Status (Relay Data)

The Relay Data function provides additional hardware information on the ISGS relay, shows all set binary inputs and outputs, and displays a relay identification string.

7400 Relay Data

Address Data Description

7401 Circuit Name String of up to 16 characters

7402 MainBd S/N Serial number of main board

7403 MainBd ID ID number of main board

7404 OptBd1 S/N Serial number of option board 1

7405 OptBd1 ID ID number of option board 1

7406 OptBd2 S/N Serial number of option board 2

7407 OptBd2 ID ID number of option board 2

7408 Bin. Inputs Binary input status

7409 Bin. Outputs Output contact status

Figure 6.2 Binary Input Status

36 Siemens Energy & Automation, Inc.

Binary Outputs (7409) displays the output contact status as illustrated in Figure 6.3. The status updates automatically as they change.

Control & Communications



V125 V>





AND V



0.33 V

 

Figure 6.3 Output Contact Status

6.10 Self-Monitoring (Value Supervision)

Value supervision refers to the relays ability to monitor its own input and measurement functions for problems. The complete chain, from input transformers up to and including the A/D converter internal to the ISGS, is monitored by a plausibility check on the measured values. These checks consist of voltage balance checks, current balance checks, and current summation checks.

Voltage or current balance checks can be performed to detect open or short circuits in the external transformers and their connections. Current summation checks are performed on the instantaneous samples of the A/D converter.

A useful application of the current and voltage balance and monitoring functions is the detection of blown VT fuses. A blown fuse condition can be said to exist when the following conditions are present:

Voltage is present but unbalanced,

AND

current is present but NOT unbalanced.



AND I20.167 I

where V1 = positive sequence voltage

Therefore, a voltage balance alarm in the absence of a current unbalance alarm is a good indication that a fuse is blown. If a current unbalance alarm were also active, it would indicate the presence of negative sequence current and therefore a fault rather than a blown VT fuse.

3400 Value Supervision

Address Parameter Selection

3401 Function V Bal Enabled or Disabled

3402 Pickup V Bal 40-120 V (0.1 V steps)

3404 Factor V Bal 0.58-0.95 (0.01 steps)

3411 Function I Sum Enabled or Disabled

3412 Pickup I Sum 5 A CTs: 0.5-5 A

3414 Factor I Sum 0.10-0.95 (0.01 steps)

3421 Function I Bal Enabled or Disabled

3422 Pickup I Bal 5 A CTs: 0.5-5 A

3424 Factor I Bal 0.10-0.95 (0.01 steps)

Voltage Balance

The Voltage Balance function can be enabled or disabled (3401). When enabled, the function monitors the phase voltages to see if they are approximately balanced (of equal magnitude). Balance is defined as the ratio of minimum to maximum voltage, where the maximum voltage is the largest and the minimum voltage the smallest of the three voltages determined by the way the relay is connected (line-to-line or line-to-neutral).



I2 = negative sequence current

I1 = positive sequence current

IN = nominal current (1 or 5 A)



OR I10.1 I

(default is 100)

(default is 0.8)

1 A CTs: 0.1-1 A (0.1 A steps)

(default is 0.1)

1 A CTs: 0.1-1 A (0.1 A steps)

(default is 0.8)



Siemens Energy & Automation, Inc. 37

Control & Communications

∑

Figure 6.4 Voltage Balance Threshold

Monitoring is done when the maximum voltage is larger than the voltage balance pickup value. The voltage is considered balanced and will not cause an alarm if the voltage min/max ratio is larger than the voltage balance factor. The voltage is unbalanced and will cause an alarm if the min/max ratio is smaller than the voltage balance factor.

Failure of this check will cause an event Voltage Balance Error. This event can activate an output contact.

The voltage balance pickup value (3402) can be set from 40 to 120 V in steps of 1 V. If one of the three phase voltages is above the preset threshold, the function checks for balance.

The voltage balance factor indicates the amount of unbalance tolerated before the function generates an alarm (3404). It ranges from 0.58 to 0.95 and can be set in steps of

0.01.

Current Summation

The Current Summation function can be enabled or disabled (3411). When enabled, it monitors the instantaneous samples of the A/D converter using the currents flowing into all four relay CTs regardless of whether there are four primary CTs connected or not. The calculation is therefore valid for systems with both residual connections or explicit neutral/ ground/zero sequence CTs.

Figure 6.5 Current Sum Threshold

Failure of this check will cause an event Current Summation Error. This event can activate an output contact.

The pickup value (3412) for the current summation check depends on the secondary phase CT rating and the value is in secondary amperes. The value for 5 A CTs ranges from

0.5 A to 5.0 A; and the value for 1 A CTs ranges from 0.1 to

1.0 A. Both values can be set in steps of 0.1 A. If one of the three phase currents is above the preset threshold, the monitoring function is activated.

The current summation factor indicates allowable compensation for differences between primary CTs (3414). It ranges from 0.1 to 0.95 and can be set in steps of 0.01. This factor is important under high fault currents or when CTs are operated closely to their rated current.

Current Balance

The Current Balance function can be enabled or disabled (3421). When enabled, the function monitors the phase currents to see if they are approximately balanced (of equal magnitude). Balance is defined as the ratio of minimum to maximum current, where the maximum current is the largest and the minimum current the smallest of the three phase currents.

Current balance monitoring is done when the maximum current is larger than the current balance pickup value. The current is considered balanced and will not cause an alarm if the current min/max ratio is larger than the current balance factor. The current is unbalanced and will cause an alarm if the min/max ratio is smaller than the current balance factor.

38 Siemens Energy & Automation, Inc.

Figure 6.6 Current Balance Threshold

Failure of this check will cause an event Current Balance Error. This event can activate an output contact.

Control & Communications

6.11 Parameter Sets

The ISGS relay can be programmed to operate with either of two parameter setsset A or set B. Separate parameter sets are programmed to satisfy separate user defined conditions, such as seasonal considerations or special operating periods. For example, set A may be used for protective settings used in the summertime, whereas set B might comprise the settings appropriate to winter, when lower ambient temperatures could allow higher loading than in the summer. Alternatively, set A might be configured for normal production periods, with set B reserved for construction or periodic shutdown periods. The choice of two separate parameter sets prevents the need to reconfigure the relay when conditions change and different parameter settings are desired.

Figure 6.2 shows the use of these parameter sets. The values in set A or B may be chosen as the active set, and are thus put in the relays memory for easy access. The default set includes all the factory default values and these values are stored in long-term memory.

Default

Set

Copy

The pickup value (3422) for the current balance check depends on the secondary phase CT rating and the value is in secondary amperes. For 5 A CTs, the value ranges from

0.5 to 5.0 A; and the value for 1 A CTs ranges from 0.1 to

1.0 A. Both values can be set in steps of 0.1 A. If one of the three phase currents is above the preset threshold, the monitoring function is activated.

The current balance factor indicates the amount of unbalance tolerated before the function generates an alarm (3424). This factor is provided to compensate for differences between primary CTs. It ranges from 0.1 to 0.95 and can be set in steps of 0.01.

Set B

Save

Set A

Activate

Active

Set

Figure 6.2 Parameter Set Actions

7101 Parameter Set

Address Parameter Description

7101 Active Set Displays active parameter set

7103 Activation Activate set A or set B

7104 Copy Default to A Copy default set to set A

7105 Copy Default to B Copy default set to set B

7106 Copy A to B Copy set A to set B

7107 Copy B to A Copy set B to set A

(A or B)

Siemens Energy & Automation, Inc. 39

Control & Communications

and, therefore, apply to both sets. Examples are protective function enable settings and matrixed output contacts such as waveform buffers and blocking. All parameter set functions require a password.

6.11.1 Active Set

The active parameter set refers to the parameter set that is currently used by the ISGS relayset A or set B. The Active Set parameter (7101) indicates which set is currently active on the LCD using the letter A or B.

Refer to Section 6.11.3 on how to make a parameter set the active set.

6.11.2 Default Set

The default set refers to factory default parameter settings. These are stored in read-only memory (ROM) and cannot be overwritten. The default set cannot become an active set in itself, it has to be copied to either set A or set B (7104 and

7105).

6.11.3 Switching Sets

A parameter set can be made active by selecting the desired set in the Activation parameter (7103). Switching between sets requires 4.5 seconds.

Note: Switching the parameter sets could cause a

trip if the pickups are set lower than in the previous set. View the settings before activating the new set.

Switching between parameter sets for viewing and configuring parameter settings is possible regardless of address or address level currently displayed by the LCD, or whether the parameter can be configured to an alternate setting.

2. Press Enter. The parameter set has switched to the

alternate set. The LCD displays the same address and function as before the switch, but the address prefix has changed to the letter representing the displayed parameter set. The alternate parameter may or may not contain a value depending on whether the alternate parameter had been configured before.

B1502 Pickup 50

If the parameter was not configurable to an alternate set (had no prefix), the display will not have changed.

Note: Switching the parameter sets for viewing

and configuration does not make the alternate set active.

For detailed descriptions on how to display, configure, save, and switch parameters, and when to use a password, refer to the standard operating procedures in Section 3.5.

Exceptions to the switching of sets are binary inputs, binary outputs, and the trip contacts in the 6000 address blocks. For these parameter settings, the relay retains these values regardless of the parameter set. For example, if the output contact is set while set A is active, switching to set B will not change the output contact setting.

6.11.4 Copying Sets

Parameter settings for set A can be copied to set B and vice versa (7106 and 7107). Factory default settings can also be copied to either set A or set B (7104 and 7105), but no parameter set can override the default settings.

A1502 Pickup 50

110 A

1. At any address, press the F key

A1502FPickup 50

110 A

followed by either 1 (set A) or 2 (set B).

The LCD displays the following message:

PARAMETER SET

COPIED TO EDIT

40 Siemens Energy & Automation, Inc.

Control & Communications

6.12 Communications Port

The Configure Communications Port function lets the user change the communications parameters for the ISGS relay.

7200 Configure Communications Port

Address Parameter Options

7201 Local Port (front) 2400, 4800, 9600, 19,200 baud

7202 System Port (rear) 2400, 4800, 9600, 19,200 baud

7203 Parameter Change Enabled or Disabled

7204 Comm Events Enabled or Disabled

7207 Local Address 1-254

The ISGS relay can connect at 2400, 4800, 9600, and 19,200 baud at both ports (7201 and 7202). Higher baud rates will improve response and update rate, but slower PCs may lose characters due to the high rate. Both ports can be operated at different baud rates and simultaneously.

The Parameter Change function can be enabled or disabled. When enabled, this function allows the remote change of the parameter sets (A or B).

The Comm Events function can be enabled or disabled (7204). When enabled, this function allows remote activation of the breaker and binary outputs. The function can be disabled to prevent remote access during service periods or as a general security measure. For more information on Comm Events, refer to Section 6.5.

The Local Address parameter (7207) can be changed by entering a value from 1 to 254 to assign the local SEAbus address. Make sure that the new address does not represent a duplicate address of another device connected to the communications loop.

6.13 Passwords

The Configure Passwords function allows the change or display of the three passwords. This function requires your old password before you can access the individual parameters. All passwords can consist of one to five digits.

7300 Configure Passwords

Address Parameter Range

7301 CW-Level 1 1 to 5 digits

7302 CW-Level 2 1 to 5 digits

7303 CW-Level 3 1 to 5 digits

A lower level password does not allow you to scroll to a higher level password parameter. But the higher level password always lets you move to the lower level(s). For example, entering the level 2 password allows you to view and change the passwords for level 2 and level 1, but the same password does not provide access to view or change the level 3 password.

6.14 Date and Time Setting

The Date and Time Setting function sets the date and time of the ISGS relay to match it with other connected devices and to provide an accurate setting for event and trip information.

8100 Date and Time Setting

Address Data Range

8101 Current Date 01/01/1970 00:00:00

8102 Set Date mm.dd.yyyy

8103 Set Time hh.mm.ss

The Current Date parameter (8101) displays the present date and time on the clock in the ISGS relay. The date and time is used to stamp the event and trip logs.

The date can be changed with the Set Date parameter (8102). To enter the date, separate the month, day, and year with a decimal point. Each field must contain two digits with the exception of the year field which must contain four digits (mm.dd.yyyy).

The time can be changed with the Set Time parameter (8103). To enter the time, separate hours, minutes, and seconds with a decimal point. Each field must contain two digits (hh.mm.ss).

Note: The clock in an ISGS relay is not a real-time

clock. It has no battery backup and will drift over time.

If the relay is connected to an ACCESS system, the supervisory software used for this system, for example, WinPM, reads all relays and synchronizes their clocks. If the relay is not connected to an ACCESS system, date and time should be set periodically, at least once a day, for accurate event and trip information. Date and time must always be reset after a loss of control power.

When reading events, the time can be off as much as 10 ms because events (inputs) are not interrupt driven; they are polled about every 10 ms. Binary inputs are also slower than protective functions; events can be reported later even if they occurred earlier.

Only the level 3 password (7303) can set all passwords. Use this level if you intend to change all passwords. Level 1 and level 2 passwords (7301 and 7302) can be displayed and changed by entering the respective level password.

Siemens Energy & Automation, Inc. 41

Notes:

42 Siemens Energy & Automation, Inc.

7 Data Acquisition

The ISGS relay provides several forms of data acquisition and display to give the user the most comprehensive picture of the power system. This data includes:

 event log for monitoring functions and status changes

 trip logs, including date and time of trip

 minimum/maximum logs for storing metering data

 individual metering data

 waveform captures

7.1 Event Log

The event log is a chronological record of the last 127 significant events that occur during operation of the relay and is stored in nonvolatile memory. These events include operational events, such as enabling or disabling protective elements; and fault events, such as pickup and trip. Each entry in the log provides a description of the event and its time (to nearest millisecond) and date of occurrence.

Data Acquisition

Figure 7.2 Sample Trip Log Data Display (from Wisdom)

The event log cannot be viewed through the ISGS relay operator panel. It can only be viewed after being retrieved through one of the relay communication ports using either Wisdom or WinPM software.

Figure 7.1 Sample Event Log (viewed with Wisdom)

Events that require special attention appear in the event log in red when displayed on a PC. The entire event log can be saved to a file (for later viewing or printing) using Wisdom software. For information on Wisdom software, refer to Chapter 8.

Whenever the ISGS relay resets, such as when changing parameter sets or output control actions, the event log is considered invalid and all events are re-read by communications.

7.2 Trip Logs

The Trip Logs function stores times and measured data present at the time of pickup and trip for the last eight trip events. The information for each trip is stored in its own log. These eight logs are located at address blocks 5100 through

5800. The most recent trip event is stored under address 5100 and the oldest of the eight trip events is stored in address 5800. Pressing the Trip Log key takes you directly to the trip log address block. The first trip to be sensed is the trip to be logged

5100 to

Address Data Description

* If VTs are connected line-to-line (see address 1202,

Section 4.5), the line-to-line voltage is displayed.

Trip Logs

5800

001 Trip Number Date and event record number

002 Pickup Time Time of the event to the nearest

millisecond

003 Pickup The function that picked up

004 Phase The phase that picked up

005 I1 Current at pickup for phase 1

006 I2 Current at pickup for phase 2

007 I3 Current at pickup for phase 3

008 IN Ground current at pickup

009 V1 Voltage at pickup phase 1 (1-2*)

010 V2 Voltage at pickup phase 2 (2-3*)

011 V3 Voltage at pickup phase 3 (3-1*)

012 Trip The function that caused the trip

013 Phase The phase that caused the trip

014 I1 Secondary current at trip for phase 1

015 I2 Secondary current at trip for phase 2

016 I3 Secondary current at trip for phase 3

017 IN Secondary Ground current at trip

018 V1 Secondary voltage at trip phase 1

(1-2*)

019 V2 Secondary voltage at trip phase 2

(2-3*)

020 V3 Secondary voltage at trip phase 3

(3-1*)

021 TinPU Total time in pickup

022 End of Table Last entry in this log

Siemens Energy & Automation, Inc. 43

Data Acquisition

For each log the following applies:

 The ISGS relay keeps a lifetime count of protective func-

tion trips. The trip number (address 001) is the count at the time of the trip. The trip number cannot be reset unless the relay is returned to the factory.

 The pickup time (002) consists of the date and time of

the event to the nearest millisecond.

 The pickup parameter (003) refers to the protective

function that caused the trip. Only protective function trips are stored in the log (no breaker monitoring, setpoints, or communications trips are logged).

 The phase parameter (004) stores the current or voltage

phase(s) that violated protective function settings.

 I1, I2, I3, and IN parameters (005 to 008) give the cur-

rents at pickup for phases A, B, C, and the ground current.

 V1, V2, and V3 (009 to 011) indicate the voltage at

pickup for phases A, B, and C. If VTs are connected lineto-line (refer to address 1202, Section 4.5, the line-to- line voltage is displayed for phases A-B, B-C, and C-A.

 Trip (012) displays the function that caused the trip.

 Phase (013) indicates the phase that caused the trip.

 I1, I2, I3, and IN (014 to 017) give the secondary cur-

rents at trip for phases A, B, C, and the ground current.

 V1, V2, and V3 (018 to 020) indicate the voltage at

pickup for phases A, B, and C. If VTs are connected lineto-line (refer to address 1202, Section 4.5, the line-to- line voltage is displayed for phases A-B, B-C, and C-A.

 Total time in pickup (021) is the total time that the relay

read the voltage above the pickup value, not the time the breaker is told to open or actually opens. The timer is only reset when no function is in pickup.

Events that require special attention appear in the event log in red when displayed on a PC. For information on Wisdom software, refer to Chapter 8.

7.3 Min/Max Logs

7.3.1 Current Minimum/Maximum Log

The Current Minimum/Maximum Log function allows the display of minimum and maximum values measured by the relay. The collected information is compared against previously stored values and the log is updated. All logged values are time stamped and resetting the log (see Section 6.7) will reset all log values.

4600 Current Minimum/Maximum Log

Address Data Description

4601 I1 min Phase A minimum current

4602 I1 max Phase A maximum current

4603 I2 min Phase B minimum current

4604 I2 max Phase B maximum current

4605 I3 min Phase C minimum current

4606 I3 max Phase C maximum current

4607 IN min Ground minimum current

4608 IN max Ground maximum current

4609 IAv min Average minimum current

4610 IAv max Average maximum current

4611 I1 dmin Phase A minimum demand

current

4612 I1 dmax Phase A maximum demand

current

4613 I2 dmin Phase B minimum demand

current

4614 I2 dmax Phase B maximum demand

current

4615 I3 dmin Phase C minimum demand

current

4616 I3 max Phase C maximum demand

current

4617 IAv dmin Average minimum demand

current calculated

4618 IAv dmax Average maximum demand

current calculated

4619 MinTHD Minimum value of estimated

total harmonic distortion

4620 MaxTHD Maximum value of estimated

total harmonic distortion

The MinTHD and MaxTHD parameters (4619 and 4620) display the minimum or maximum total harmonic distortion calculation for the average current. The calculation is an estimate of the harmonics on the system rather than an exact measurement.

44 Siemens Energy & Automation, Inc.

Data Acquisition

7.3.2 Voltage Minimum/Maximum Log

The Voltage Minimum/Maximum Log function allows the display of minimum and maximum values measured by the relay. The collected information is compared against previously stored values and the log is updated. All logged values are time stamped and resetting the log (see Section 6.7) will reset all log values. No voltages are metered unless the VT option is installed.

4700 Voltage Minimum/Maximum Log

Address Data Description

4701 V12 min Minimum phase voltage

between phases A and B

4702 V12 max Maximum phase voltage

between phases A and B

4703 V23 min Minimum phase voltage

between phases B and C

4704 V23 max Maximum phase voltage

between phases B and C

4705 V31 min Minimum phase voltage

between phases C and A

4706 V31 max Maximum phase voltage

between phases C and A

4713 VAv min Minimum average voltage

4714 VAv max Maximum average voltage

4717 MinTHD Minimum value of estimated

total harmonic distortion

4718 MaxTHD Maximum value of estimated

total harmonic distortion

The MinTHD and MaxTHD parameters (4717 and 4718) display the minimum or maximum total harmonic distortion calculation for the average current. The calculation is an estimate of the harmonics on the system rather than an exact measurement.

4800 Power Minimum/Maximum Log

Address Data Description

4801 kW min Minimum power value

4802 kW max Maximum power value

4803 kW dem min Minimum active power demand

value

4804 kW dem max Maximum active power demand

value

4805 kVA min Minimum kilovolt-ampere value

4806 kVA max Maximum kilovolt-ampere value

4807 kVAR min Minimum kilovolt-ampere

reactive value

4808 kVAR max Maximum kilovolt-ampere

reactive value

4809 PF max Maximum power factor value

4810 PF min Minimum power factor value

7.3.4 Frequency Minimum/Maximum Log

The Frequency Minimum/Maximum Log function allows the display of minimum and maximum values measured by the relay. The collected information is compared against previously stored values and the log is updated. All logged values are time stamped, and resetting the log (see Section 6.7) will reset all log values.

4900 Frequency Metering

Address Data Description

4901 Fmin Minimum frequency value

4902 Fmax Maximum frequency value

7.3.3 Power Minimum/Maximum Log

The Power Minimum/Maximum Log function allows the display of minimum and maximum values measured by the relay. The collected information is compared against previously stored values and the log is updated. All logged values are time stamped, and resetting the log (see Section 6.6) will reset all log values. No voltages are metered unless the VT option is installed.

Siemens Energy & Automation, Inc. 45

Data Acquisition

7.4 Metered Data

Metered data is stored by the ISGS relay and can be displayed by accessing address blocks 4100 to 4900. The display of this data does not require a password. You can display the same data more conveniently by using Wisdom software described in Chapter 8.

7.4.1 Current Values

The Current Metering function stores the metered current and current demand values for the ISGS relay. The relay will measure and display the rms values of the current for the three phases and ground or neutral. The ISGS relay also shows total harmonic distortion as a percentage of the fundamental for the three phase current inputs. This function displays undefined when the measured components are below the total harmonic distortion threshold.

4100 Current Metering

Address Data Range

4101 I Phase A 0-250% I

4102 I Phase B 0-250% I

4103 I Phase C 0-250% I

4104 I Neutral 0-250% I

4105 I Average 0-250% I

4106 I Demand Phase A 0-250% I

4107 I Demand Phase B 0-250% I

4108 I Demand Phase C 0-250% I

4109 I Demand Average 0-250% I

4110 THD Current 0-250% I

ICT = primary CT rating

7.4.2 Voltage Values

The Voltage Metering function allows the display of metered voltage data for the ISGS relay. The rms voltage measurements for this function depend on the selected VT connection method, either line-to-ground or line-to-line. The relay also shows total harmonic distortion as a percentage of the fundamental for the three phase voltage inputs. It displays undefined when the measured components are below the total harmonic distortion threshold. This function is only available if the voltage input option is installed.

4200 Voltage Metering

Address Data Range

4201 V Phases A-B 10-125% V

4202 V Phases B-C 10-125% V

4203 V Phases C-A 10-125% V

4204 V L-L Average 10-125% V

4209 THD Volts 10-125% V

IVT = primary VT rating

7.4.3 Power Values

The Power Metering function stores the metered voltage data for the ISGS relay. This function is only available if the voltage input option is installed.

4300 Power Metering

Address Data Range

4301 kW 3-Phase 0-999,999.99 kW

4302 kW Hours 0-999,999.99 kWHR

4303 kW Demand 0-999,999.99 kWD

4304 kVA 3-Phase 0-999,999.99 kVA

4305 kVAR 3-Phase 0-999,999.99 kVAR

4306 kVAR Hours 0-999,999.99 kVARH

4307 PF -1  0  +1

7.4.4 Frequency Values

The Frequency Metering function allows the display of the system frequency. This function is only available if the voltage input option is installed.

4400 Frequency Metering

Address Data Range

4401 Frequency 45-65 Hz

46 Siemens Energy & Automation, Inc.

7.5 Meter Display

The Operating Parameters function allows the user to determine what appears in Line 1 and Line 2 of the Power On Meter display described in Chapter 4.

7000 Operating Parameters

Address Parameter Options

7005 LCD Line 1 I avg, Idmd1, Idmd2, Idmd3,

Idmdavg, V1-2, V2-3, V3-1, VLLavg, V1-N, V2-N, V3-N, VLNavg, W, WH, Wdmd, VA, VAR, VARH, PF, f, I1, I2, I3, IN

7006 LCD Line 2 I avg, Idmd1, Idmd2, Idmd3,

Idmdavg, V1-2, V2-3, V3-1, VLLavg, V1-N, V2-N, V3-N, VLNavg, W, WH, Wdmd, VA, VAR, VARH, PF, f, I1, I2, I3, IN

The operating parameters can be set to provide you with a quick and constantly updated overview of your most important data.

Data Acquisition

7.6 Waveform Capture

The Waveform Capture function sets the pre-trigger time of the two waveform buffers. You can configure the ISGS relay to capture waveforms on a variety of events. For example, waveforms can be captured for protective functions on pickup or trip, or for communication events.

8400 Configure Waveform Capture

Address Parameter Range

8401 Wfm1Pretrp 100-900 ms, default is 800 ms,

8402 Wfm2Pretrp 100-900 ms, default is 800 ms,

Each buffer stores one full second of data for each wave. This second always includes the event that caused the trip. The pre-trip parameter of each buffer (8401 and 8402) lets you specify where in the buffer the event appears. By setting a time in milliseconds, you indicate how much data of this one second wave data you want included in the buffer prior to the trip.

For example, if buffer 1 is configured to be captured on trip (see also Chapter 5 and its protective functions with wave- form capture), and the activity that led up to the trip is of great interest, buffer 1 can be configured to contain 900 ms of pre-trigger data. These first 900 ms of pre-trigger data represent the signal before the actual trip. The remaining 100 ms show the signal after the trip.

(1 ms steps)

A waveform stored in a buffer will be lost after a loss of control power. Exporting an important waveform immediately to a file will prevent unexpected data loss.

Siemens Energy & Automation, Inc. 47

Notes:

48 Siemens Energy & Automation, Inc.

8 ISGS Wisdom Software

8.1 Overview

The ISGS relay is an extremely advanced protective relay for medium voltage switchgear applications. In order to reduce the complexity of configuring the relay, reading the metered values, and retrieving stored data, Siemens developed ISGS Wisdom software. Wisdom software is a Windows-based tool that monitors and controls an ISGS relay. Wisdom software provides a flexible, easy to use interface allowing the performance of a wide variety of tasks such as

 remote configuration via network, local port, or modem

 offline configuration in DEMO mode

 configuration file storage

 custom curve creation

 display and retrieval of captured waveforms

 event log retrieval

 real-time data and status display

8.2 Setup

Using Wisdom software requires Microsoft® Windows®. To make full use of the Waveform Capture display, a color monitor is highly recommended. Setting up Wisdom software requires two basic operations:

1. Installing the program on a PC

Wisdom software is provided on a floppy diskette. The setup program on this diskette will install Wisdom software on your hard drive and will create a Windows program group icon.

2. Connecting the relay to the PC

For local connection of the PC, install an RS-232 interface cable between the serial communications port on the PC and the front port on the relay.

For remote connection of the PC, use an RS-232 to RS-485 converter for direct connection and null-modem connectors for modem use.

Wisdom software offers five main menus from which to select the various tasks or operations to be performed and one help menu.

8.3 Menus

In the main window, you can choose from the following main menus: Relay, Breaker, Configure, View, Logs, and Help. The Main Window also displays the Event Log which is automatically updated (refer to Figure 8.1). The Event Log can be saved or re-read. These commands can be found in the Logs menu.

Figure 8.1 Wisdom Main Window

Note: For a free copy of Wisdom software, fax a

request to 919-365-2552. Please include your name, company, phone number, fax number, mailing address, and e-mail address (if applicable). The software can also be downloaded from the World Wide Web at http://www.sea.siemens.com. Search for Wisdom Software using the Search function.

Relay Menu

From the Relay menu, you can connect or disconnect the ISGS relay, save or load device data, select parameter sets, and synchronize the internal time of your device with the time of your computer.

Breaker Menu

From the Breaker menu, you can control breakers and reset targets.

The Control submenu opens or closes the breaker and asserts or releases the communication events. Refer to

Figure 8.2.

Figure 8.2 Breaker Control

Siemens Energy & Automation, Inc. 49

8 ISGS Wisdom Software

Configure Menu

The Configure menu provides an easy way to set the parameters for the following areas:

 Communications

 Protection Functions

 Breaker Monitoring

 ISGS Hardware

 Demand

 Alarms

 Value Supervision

 I/O Setup

 Passwords

Each function or task offers an individual window with an overview of the complete set of parameters available and their default or user-defined settings. A simple click with the mouse selects your choices from check boxes, option buttons, or list boxes. A slider lets you adjust ranges in predefined steps within minimum and maximum values. Refer to Figure 8.3.

The Realtime Data submenu allows a complete data display at one glance (refer to Figure 8.4).

Figure 8.4 Real-Time Data Display

The Waveform Capture submenu opens a color display that allows you to freeze and then retrieve all waveform data, selectively or together from either of the two buffers. The curves are color coded for easy identification. From the same window, you can configure your waveform settings, view your trip logs and display a buffer summary. Refer to

Figure 8.5.

Figure 8.3 Configuring a Protection Function

View Menu

The View menu offers functions for processing and displaying various forms of data stored in the relay.

The Info submenu displays device data such as CT and VT ratings.

50 Siemens Energy & Automation, Inc.

Figure 8.5 Waveform Capture

The Marshalling display provides an overview of all trip and binary input settings. Refer to Figure 8.6.

Figure 8.6 Marshalling Display

Logs Menu

The Logs menu allows a complete data display of the Trip Logs and the Min/Max Log at one glance (see Figure 8.7 and Figure 8.8. This menu also contains the commands for saving or re-reading the Event Log.

8 ISGS Wisdom Software

Figure 8.8 Min/Max Log Data Display

Help Menu

The Help menu provides detailed information on how to use Wisdom software. The menu allows searching for and printing of specific help topics. The Help menu contains an ISGS relay settings worksheets that can be printed and used for manual configuration of the device if desired.

8.4 Demo Mode

To evaluate the software offline, a demonstration mode is provided that allows all of the program functions to be exercised without actual connection to an ISGS relay. Information on the methods and equipment required to connect the personal computer to the relay are included in the Help function.

Figure 8.7 Trip Log Data Display

In addition to allowing experimentation, the demo mode permits the user to create relay configuration files that can be saved and used at a later time to configure an actual relay.

Siemens Energy & Automation, Inc. 51

Notes:

52 Siemens Energy & Automation, Inc.

Appendix A: Trip Curves & Equations

A Trip Curves & Equations

This section provides equations and curve characteristics for current and voltage to show the relationship between trip time and threshold levels. Determine which curve closely follows the requirements of your system and select this curve in the applicable protective functions.

A.1 Instantaneous Curve

The Instantaneous response characteristics can be used with protection functions 50, 50N, 50HS, and 50HSN.

0.1

Time to Trip (Seconds)

0.01 11050

Multiples of Pickup

Trip Characteristic

For

---- -

1 : T

------------------------BD0.028++=>



---i

1–



Reset Characteristic

---- -

For

1 : T

T = time to trip, in seconds



---- -

= multiple of pickup setting





D = time dial setting, 0.1 to 9.9 in steps of 0.1

------------------------



----



A, B, N, tr = constants

1–

Figure A.1 Instantaneous Curve

A.2 Standard Time Overcurrent Equation

The ISGS comes with nine standard overcurrent characteristic curves that can be adjusted with a time dial parameter. Seven of the nine curves are based on suggested IEEE standards for approximation of electromechanical relays. Table A.1 describes the first seven curves (SEA1 to SEA7) listed below.

Standard Overcurrent Coefficients

Curve Type Des.

Inverse SEA 1 8.9341 0.17966 2.0938 8.8

Short Inverse SEA 2 0.2663 0.03393 1.2969 0.831

Long Inverse SEA 3 5.6143 2.18592 1.0000 12.9

Moderately Inverse

Very Inverse SEA 5 5.4678 0.10814 2.0469 5.741

Extremely Inverse

Slightly Inverse

The A, B, and N coefficients are for the standard relay formula

SEA 4 0.3022 0.12840 0.5000 1.07

SEA 6 7.7624 0.02758 2.0938 7.432

SEA 7 0.4797 0.21359 1.5625 1.5625

Equation A.1 Standard Inverse Curves Equation

1000

100

Time to Trip (Seconds)

0.1

0.01 11050

Multiples of Pickup

Time Dial

9.9

7.0

5.0

3.0

1.5

0.5

0.1

Table A.1 Standard Overcurrent Coefficients

Figure A.2 Inverse Curve (SEA1)

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Appendix A: Trip Curves & Equations

100

Time Dial

Time to Trip (Seconds)

0.1

0.01 11050

9.9

7.0

5.0

3.0

1.5

0.5

0.1

Time to Trip (Seconds)

0.1

0.01 11050

Multiples of Pickup

Time Dial

9.9

7.0

5.0

3.0

1.5

0.5

0.1

Multiples of Pickup

Figure A.3 Short Inverse Curve (SEA2)

1000

100

Time to Trip (Seconds)

0.1 11050

Multiples of Pickup

Time Dial

9.9

7.0

5.0

3.0

1.5

0.5

0.1

Figure A.5 Moderately Inverse Curve (SEA4)

1000

100

Time to Trip (Seconds)

0.1

0.01 11050

Multiples of Pickup

9.9

7.0

5.0

3.0

1.5

0.5

0.1

Time Dial

Figure A.4 Long Inverse Curve (SEA3)

Figure A.6 Very Inverse Curve (SEA5)

54 Siemens Energy & Automation, Inc.

Appendix A: Trip Curves & Equations

1000

100

Time to Trip (Seconds)

0.1

0.01 11050

Multiples of Pickup

Time Dial

9.9

7.0

5.0

3.0

1.5

0.5

0.1

Equation A.2 The ISGS provides an emulation of the popular CO-6 Definite Inverse characteristic. This curve is defined by the equations shown in Equation A.3.

For

A.3 Definite Inverse Equation

---- -

1.5

T 785

For1.0

T 785

Trip Characteristic

671

-------------------------------



----



---- -

1.5:

671

-------------------------------



----



6.33D 0.37+

-------------------------------

×=

24000

1.19–

6.33D 0.37+

--------------------------------- -

24000

1.19–

Figure A.7 Extremely Inverse Curve (SEA6)

100

Time to Trip (Seconds)

0.1

0.01 11050

Multiples of Pickup

Time Dial

9.9

7.0

5.0

3.0

1.5

0.5

0.1

Reset Characteristic

---- -

For

1 : T

T = time to trip, in seconds



---- -

= multiple of pickup setting





D = time dial setting, 0.1 to 9.9 in steps of 0.1

tr = reset constant = 1.0394

N = inverse constant = 2.54096

------------------------



----



1–

Equation A.3 Definite Inverse Equation

In Equation A.3, the time dial term 6.33D + 0.37 is neces- sary to convert the time dial range defined by Westinghouse and the range that Siemens is using.

Equation (1) is valid for values of I/Ip greater than 1.5 and equation (2) is valid for values of I/Ip between 1.0 and 1.5 (note that the equation is undefined at I/Ip = 1.0).

Figure A.8 Slightly Inverse Curve (SEA7)

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Appendix A: Trip Curves & Equations

100

Time to Trip (Seconds)

0.1

0.01 11050

Multiples of Pickup

Figure A.9 Definite Inverse Curve (SEA8)

Time Dial

9.9

7.0

5.0

3.0

1.5

0.5

0.1

1000

100

Time to Trip (Seconds)

0.1

0.01 1

Multiples of Pickup

Figure A.10 I-Squared-T Curve

Time Dial

9.9

7.0

5.0

3.0

1.5

0.5

0.1

A.4 I-Squared-T Curve

The ISGS provides an I-Squared-T characteristic in addition to the standard inverse curves.

Trip Characteristic

50.7D 10.14+

-------------------------------------=

Reset Characteristic

---- -

For

1 : T

T = time to trip, in seconds



---- -

= multiple of pickup setting





D = time dial setting, 0.1 to 9.9 in steps of 0.1

= reset constant = 7.4



--- -



-----------------------



----

1–



A.5 Custom Protective Curve

The custom curve consists of up to 60 current-time pairs corresponding to points on the time-current characteristic curve. Current refers to multiple-of-pickup value (I/Ip) on the horizontal axis, and time refers to time-to-trip values on the vertical axis. Each point consists of two values (I/Ip and t), loaded in order from lowest to highest value of I/Ip via the SEAbus or local ports. Siemens Wisdom software is required in order to load a custom curve. Time-to-trip has a range of

0.00 to 655.35 seconds in steps of 0.01 seconds. I/Ip has a range of 1.1 to 20.00 in steps of 0.01. The first point in the data set must be I/Ip=1.1, the last point must be I/Ip=20. Points in between these two limits can be for any values of I/ Ip and t as long as the slope ( described by the points is between 0 (horizontal) and -

∆t/(∆I/Ip)) of the curve

∞ (ver-

tical). For input current in excess of 20 x Ip, the relay will enter a definite time mode and the curve will be considered to be flat (constant time) at the time value associated with I/ Ip=20. Once loaded, a custom curve is not adjustable, that is there is no time dial adjustment.

A.6 Over/Undervoltage Curves

The ISGS provides a moderately inverse overvoltage and a moderately inverse undervoltage protection defined by the equation in Equation A.5 and Equation A.6. Their characteristics are provided in Figure A.11 and Figure A.12.

Equation A.4 I-Squared-T Equation

56 Siemens Energy & Automation, Inc.

Appendix A: Trip Curves & Equations

Over/Undervoltage Coefficients

Curve Type Des.

Inverse 0.51 -1.75 0.50 ---

Mod. Inverse 0.51 -0.45 0.50 ---

Very Inverse 0.51 1.75 0.50 ---

The A, B, and N coefficients are for the standard relay formula

Table A.2 Under/Overvoltage Coefficients

For1.01

For

-----

1.5: T



-----

1.5: T





T = time to trip, in seconds v = measured input voltage

= pickup value (tap setting)



------

= multiple of pickup setting





D = time dial setting, 0.1 to 9.9 in steps of 0.1

= constants for inverse curves

A, B, N

-------------------------BD+=≤≤





-----



--------------------------BD+=>

)(

1.5

1–



1–

1000

100

Time to Trip (Seconds)

0.1 1 1.1 1.2 1.3 1.4 1.5 1.6

Multiples of Pickup

Time Dial

9.9

5.0

2.0

1.0

0.5

0.2

0.1

Figure A.11 Moderately Inverse Overvoltage Curve

1000

Equation A.5 Overvoltage Equation

For 0.5

For

-----

1.5: T



-----

0.5:





--------------------------BD+=≤

1.5

T = time to trip, in seconds v = measured input voltage

= pickup value (tap setting)



------

= multiple of pickup setting





D = time dial setting, 0.1 to 9.9 in steps of 0.1

= constants for inverse curves

A, B, N

Equation A.6 Undervoltage Equation

-------------------------BD+=≤≤

 

----v

)(



1–



1–

Time Dial

9.9

5.0

2.0

1.0

0.5

0.2

0.1

0.4 0.5 0.6 0.7 0.8 0.9 1.0

Multiples of Pickup

100

Time to Trip (Seconds)

0.1

Figure A.12 Moderately Inverse Undervoltage Curve

Siemens Energy & Automation, Inc. 57

Appendix B: Metering

B Metering

B.1 Accuracy

Table B.1 Metering Accuracies

Parameter Range Accuracy

rms Current (L & G) 0-250% I

Average rms Current 0-250% In Displayed in Amperes ±1% of measurement from 50-125% of I

Ampere Demand per Phase 0.. 250% In Displayed in Amperes ±1% of measurement from 50-125% of In

Average Ampere Demand 0-250% In Displayed in Amperes ±1% of measurement from 50-125% of In

rmsVoltage (L-L and L-N) 10-125% Vn Displayed in kV ±1% of measurement from 50-125% of Vn

Average rms Voltage 10-125% Vn Displayed in kV ±1% of measurement from 50-125% of Vn

Active Power (kW) 0-999,999.99 kW ±2% of measurement from 50-125% of Pn

kW Demand 0-999,999.99 kWD ±2% of measurement from 50-125% of Pn

kW Hours 0-999,999.99 kWHR ±2% of measurement from 50-125% of Pn

Apparent Power (kVA) 0-999,999.99 kVA ±2% of measurement from 50-125% of Pn

Volt-Amperes Reactive (kVAR) 0-999,999.99 kVAR ±2% of measurement from 50-125% of Pn

kVAR Hours 0-999,999.99 kVARH ±2% of measurement from 50-125% of Pn

Power Factor -1- 0-+1

Frequency 45-65 Hz ±0.1% of reading providing voltage is 50% VT primary rating

Displayed in Amperes ±1% of measurement from 50-125% of In

±0.5% of I

from 10- 50% of I

±0.5% of In from 10-50% of I

±0.5% of I

±0.5% of V

±0.1% of V

±0.04

from 10-50% of I

from 10-50% of V

from 10-50% of P

1, 5

1, 3, 5

1, 5

1, 2, 5

1, 2, 3, 5

Measured at PF=1. For |PF|<1, ±2% + angle error (±2% for |PF|≥0.7)

Measured at PF=0. For |PF|>0, ±2% + angle error (±2% for |PF|≤0.7)

Energy is accumulated in either kHR or MHR, selectable (parameter).

For power factor, 1 is considered perfect, negative is leading and positive is lagging.

Pn = Vn x In, where Vn = VT rating (120 V) and In = CT rating (5A).

Note for all values: Stated accuracy applies only when the device is not in pickup. These measurements are valid over a frequency range of 45- 65Hz and include fundamental, second harmonic, and all odd harmonics up to the 13th harmonic of the fundamental line frequency.

58 Siemens Energy & Automation, Inc.

B.2 Power Conventions

Line Load

Appendix B: Metering

Export

Reverse

Negative

(kW/kVAR supplied

by the load)

Ø=90 to 180° Power Factor Lead

Ø=180°, -kW, kWh Exported, Power Factor = 1

Ø=90°, +kVAR, kVARh Imported, Power Factor = 0

Phase Angle Ø

Import Forward Positive

(kW/kVAR consumed

by the load)

Ø=0 to 90° Power Factor Lag

Ø=0°, +kW, kWh Imported, Power Factor = 1

Ø=180 to 270° Power Factor Lag

Ø=270°, -kVAR, kVARh Exported, Power Factor = 0

Figure B.1 Complex Power Plane

Siemens Energy & Automation, Inc. 59

Ø=270 to 360° Power Factor Lead

Appendix C: Menu Structure

C Menu Structure

The following table provides a complete list of addresses and parameters available to the ISGS in its standard and optional configuration.

Functions that set the device, the CTs, or the VTs, or functions that require a change in the matrix are indicated by and asterisk (*) next to the address. Observe the warning label below when changing the settings of these functions.

Block Function Address Parameter

0000 Power On/Configu-

ration Display

1000 * Device

Configuration

1100 * CT Configuration 1101

1200 * VT Configuration 1201

--- ---

1002

Frequency

1003

Phase Seq.

1004

Brkr Conn.

1005

Trip Time

Ph Pri Rtg

1102

Neu Pri Rtg

1104

Norm Pwr Flo

Pri Rating

1202

VT Mode

1203

Secondary Rating

Block Function Address Parameter

A1500 Instantaneous

Phase Overcurrent (50)

High-Set Instantaneous Phase Overcurrent (50HS)

A1600 Instantaneous Neu-

tral or Ground Overcurrent (50N)

High-Set Instantaneous Neutral or Ground Overcurrent (50HSN)

A1700 Phase Time Over-

current (51)

A1800 Neutral Time Over-

current (51N)

A1900 Directional Phase

Time Overcurrent (67)

A2000 Directional Neutral

Time Overcurrent (67N)

A2200 Overvoltage (59) 2201

1501

Function 50

1502

Pickup 50

1504

Delay 50

1510

Freeze Wfm 1 50

1511

Freeze Wfm 2 50

1512

Block 50

1551

Function 50HS

1552

Pickup 50HS

1560

Freeze Wfm 1 HS

1561

Freeze Wfm 2 HS

1601

Function 50N

1602

Pickup 50N

1604

Time Delay 50N

1610

Freeze Wfm 1 50N

1611

Freeze Wfm 2 50N

1612

Block 50N

1651

Function HSN

1652

Pickup HSN

1660

Freeze Wfm 1HSN

1661

Freeze Wfm 2HSN

1702

Curve

1703

Pickup

1705

Time Dial

1706

Filter

1709

Reset

1710

Freeze Wfm 1

1711

Freeze Wfm 2

1712

Block 51

1801

Function

1802

Curve

1803

Pickup

1805

Time Dial

1806

Filter

1809

Reset

1810

Freeze Wfm 1

1811

Freeze Wfm 2

1812

Block 51N

1901

Function

1902

Curve

1903

Pickup

1905

Time Dial

1906

Filter

1907

Impedance

1908

Direction

1910

Freeze Wfm 1

1911

Freeze Wfm 2

2001

Function

2002

Curve

2003

Pickup

2005

Time Dial

2006

Filter

2007

Impedance

2008

Direction

2010

Freeze Wfm 1

2011

Freeze Wfm 2

Function

2202

Curve

2204

Pickup

2205

Delay (Definite)

2206

Dial (Inverse)

2210

Freeze Wfm 1

2211

Freeze Wfm 2

60 Siemens Energy & Automation, Inc.

Appendix C: Menu Structure

Block Function Address Parameter

A2300 Undervoltage (27) 2301

A2400 Phase Sequence

Voltage (47)

Negative Sequence Voltage (47N)

A2500 Overfrequency

(810)

Underfrequency (81U)

2800 Breaker Failure

(50B)F

3000 Alarm Setpoints --- ---

3100 Demand Setpoints 3101

3200 Power Setpoints 3201

Function

2302

Curve

2304

Pickup

2305

Delay (Definite)

2306

Dial (Inverse)

2310

Freeze Wfm 1

2311

Freeze Wfm 2

2401

Function 47

2410

Freeze Wfm1 47

2411

Freeze Wfm2 47

2451

Function 47N

2452

Curve 47N

2453

Pickup 47N

2454

Delay 47N

2455

Time Dial 47N

2456

Max Time 47N

2457

Block 47N

2460

Freeze Wfm1 47N

2461

Freeze Wfm2 47N

2501

Function 810

2503

Pickup 81O

2504

Time Delay 81O

2506

Block 81O

2510

Freeze Wfm1 81O

2511

Freeze Wfm2 81O

2551

Function 81U

2553

Pickup 81U

2554

Time Delay 81U

2556

Block 81U

2560

Freeze Wfm1 81U

2561

Freeze Wfm2 81U

2801

Function

2802

Pickup

2804

Time Delay

2805

Check

Demand Interval

3102

Sync Time

3103

Subperiods 60

3104

Subperiods 30

3105

Subperiods 15

3106

ADmd Function

3107

ADmd Pickup

3108

KWDmdFunction

3109

KWDmdPickup

KVAR Enable

3202

KVAR Pickup

3203

KVARTime Delay

3203

KVA Enable

3204

KVA Pickup

3206

KVA Delay

3207

PF Lead Enable

3208

PF Lead Pickup

3209

PF Lead Sign

3210

PF Lead Delay

3211

PF Lag Enable

3212

PF Lag Pickup

3213

PF Lag Sign

3214

PF Lag Delay

Block Function Address Parameter

3400 Analog Monitoring

(Value Supervision)

3500 Breaker Operation 3501

4000 Metering --- ---

4100 Current Metering 4101

4200 Voltages 4201

4300 Power Metering 4301

4400 Frequency

Metering

4600 Current Minimum/

Maximum Log

3401

Function V Bal

3402

Pickup V Bal

3404

Factor V Bal

3411

Function I Sum

3412

Pickup I Sum

3414

Factor I Sum

3421

Function I Bal

3422

Pickup I Bal

3424

Factor I Bal

Int. I Enable

3502

Int. I Pickup

3503

Brkr Ops Enable

3504

Brkr Ops Pickup

I Phase A

4102

I Phase B

4103

I Phase C

4104

I Neutral

4105

I Average

4106

I Demand, Phase A

4107

I Demand, Phase B

4108

I Demand, Phase C

4109

I Demand, Average

4110

I THD

V 1-2

4202

V 2-2

4203

V 3-1

4204

V L-L Average

4209

V THD

KW 3-Phase

4302

KW Hours

4303

KW Demand

4304

KVA 3-Phase

4305

KVAR 3-Phase

4306

KVAR Hours

4307

Power Factor

4401 Frequency

4601

I1 min

4602

I1 max

4603

I2 min

4604

I2 max

4605

I3 min

4606

I3 max

4607

IN min

4608

IN max

4609

IAv min

4610

IAv max

4611

I1 dem min

4612

I1 dem max

4613

I2 dem min

4614

I2 dem max

4615

I3 dem min

4616

I3 dem max

4617

IAv dem min

4618

IAv dem max

4619

MinTHD?

4620

MaxTHD

Siemens Energy & Automation, Inc. 61

Appendix C: Menu Structure

Block Function Address Parameter

4700 Voltage Minimum/

Maximum Log

4800 Power Minimum/

Maximum Log

4900 Frequency Mini-

mum/Maximum Log

5000 Trip Logs --- ---

5100

Trip Log

(most

thru

5800

Information

Note: Access address block first, then scroll to desired 3-digit address

recent)

(oldest)

6000 * Matrixing --- ---

6100 * Binary Inputs 6101

6200 * Binary Outputs 6201

6400 * Trip Contacts 6401

4701

V1-2 min

4702

V1-2 max

4703

V2--3 min

4704

V2-3 max

4705

V3-1 min

4706

V3-1 max

4713

VAv min

4714

VAv max

4717

Min THD

4718

Max THD

4801

kW min

4802

kW max

4803

kW dem min

4804

kW dem max

4805

kVA min

4806

kVA max

4807

kVAR min

4808

kVAR max

4809

PF max

4810

PF min

4901

Frequency min

4902

Frequency max

(001)

Trip #

(002)

Time in Pickup

(003)

Pickup Function

(004)

Phase (at Pickup)

(005)

I1 (at Pickup)

(006)

I2 (at Pickup)

(007)

I3 (at Pickup)

(008)

IN (at Pickup)

(009)

V1 (at Pickup)

(010)

V2 (at Pickup)

(011)

V3 (at Pickup)

(012)

Trip Function

(013)

Phase (at Trip)

(014)

I1 (at Trip)

(015)

I2 (at Trip)

(016)

I3 (at Trip)

(017)

IN (at Trip)

(019)

V1 (at Trip)

(020)

V2 (at Trip)

(021)

V3 (at Trip)

(022)

TinPU

(023)

Trip Log full

Input 1

6102

Input 2

6103

Input 3

6104

Input 4

Output 1

6202

Output 2

Contact 1

6402

Contact 2

6403

Contact 3

Block Function Address Parameter

7000 Operating

Parameters

7100 Parameter Set 7101

7200 Configure Comm

Port SEAbus

7300 Configure

Passwords

7400 Relay Data 7401

8000 Other Settings --- ---

8100 Date and Time

Setting

8200 Reset 8201

8300 Breaker Monitoring 8301

8400 Waveform Capture 8401

7005

LCD Line 1

7006

LCD Line 2

Active Set

7103

Activation

7104

Copy? Defaults to A

7105

Copy? Defaults to B

7106

Copy? A to B

7107

Copy? B to A

7201

Local Port

7202

System Port

7203

ParaChange

7204

Com Events

7207

Local Address

7301

CW Level 1

7302

CW Level 2

7303

CW Level 3

Circuit Name

7402

MainBd S/N

7403

MainBd ID

7404

OptBd 1 S/N

7405

OptBd 1 ID

7406

OptBd 2 S/N

7407

OptBd 2 ID

7408

Bin. Inputs

7409

Bin. Outputs

8101

Current Date

8102

Date

8103

Time

Trip Log

8202

Min/Max Values?

8203

Energy

8204

Breaker Ops

8205

SumCurrInter

8211

Breaker Ops

8212

Sum IL1

8213

Sum IL2

8214

Sum IL3

TripSrcImp

8302

TripSrcFail

8303

TrpCoil Cont

8304

TrpCoilFail

8305

BrkrMech

Wfm1 Pre-Trip

8402

Wfm2 Pre-Trip

62 Siemens Energy & Automation, Inc.

Appendix D: Acceptance Test Procedures

D Acceptance Test Procedures

When performing the acceptance tests, follow the sequence listed here; first test protective function 51, then 50, etc.)

Note: The following procedures should be performed using accurately calibrated test equipment connected to a source free of harmonics. Refer to Figure D.1 for connection diagram.

ISGS Acceptance Test

Set the ISGS as follows:

Parameter Set A 7103 5000:5 Current Transformer (CT) 1101 Curve SEA 5, Very Inverse 1702 1 A Nominal Pickup 1703 Time Dial per Chart 1705 Trip Matrixed to Trip 1 Contact 6401 Disable Other Conflicting Functions 1501, 1551, 1601, 1651, 1801, 1901, 2001, 2301

Phase

A B C Connections

1. Connect the appropriate source of control voltage to terminals 13 (+) and 12 (-).

Relay Disabled contact on terminals 19 and 20 opens.

2. Connect suitable variable source current to phase A, terminals 3 and 4,

to phase B, terminals 5 and 6,

to phase C, terminals 7 and 8,

Phase Time Overcurrent (51) Function

to neutral, terminals 9 and 10.

3. Connect timer to Trip 1 contacts, terminals 1 and 2.

Pickup

4. Increase current until relay picks up (this should occur at 1.06 x pickup.

Pickup LED illuminates.

Wisdom software records pickup in event log.

Return current to zero and reset timer.

Timing

Apply appropriate value of current for the test. The results match Table D.1.

Pickup LED illuminates.

Display shows PICKUP 51 P1 (2, 3).

Wisdom software records pickup in event log.

Siemens Energy & Automation, Inc. 63

Appendix D: Acceptance Test Procedures

ISGS Acceptance Test (continued)

Phase

ABC

Relay times out per Table D.1

Trip LED illuminates.

Timer stops as Trip 1 contacts close.

Trip log indicates trip current value and time in pickup.

Wisdom software records trip on overcurrent.

Return current to zero and reset timer.

7. Remove control power from relay for five seconds, then restore it.

Trip LED re-illuminates after relay is powered up again.

8. Reset relay target.

Trip LED resets.

Phase Time Overcurrent (51) Function

Repeat above steps for phase B and phase C; repeat the same steps also for Parameter Set B. Testing may also be done for each phase at the user settings following the same procedure.

Table D.1 Test Points for Very Inverse Curve Characteristics

Multiple of Pickup Time Band 2 (seconds) Time Band 5 (seconds) Time Band 9.9 (seconds)

2X 3.73 9.30 18.38

4X 0.92 2.27 4.46

8X 0.40 0.96 1.87

Accuracy of the time curve for 2 ≤ I/Ip ≤ 20 is 5% from the defined value, or 30 ms, whichever is greater.

64 Siemens Energy & Automation, Inc.

Appendix D: Acceptance Test Procedures

ISGS Acceptance Test

Set the ISGS as follows:

Parameter Set A 7103 5000:5 Current Transformer (CT) 1102 Curve SEA 5, Very Inverse 1802 1 A Nominal Pickup 1803 Time Dial per Chart 1805 Trip Matrixed to Trip 1 Contact 6401 Enable 51N 1801 Disable Other Conflicting Functions 1501, 1551, 1601, 1651, 1901, 2001, 2301 Raise 51 Pickup to Maximum 1703

Phase N Connections

1. Connect the appropriate source of control voltage to terminals 13 (+) and 12 (-).

Relay Disabled contact on terminals 19 and 20 opens.

2. Connect suitable variable source current to neutral, terminals 9 and 10.

3. Connect timer to Trip 1 contacts, terminals 1 and 2.

Neutral Time Overcurrent (51N) Function

Pickup

4. Increase current until relay picks up (this should occur at 1.06 A x pickup).

Pickup LED illuminates.

Wisdom software records pickup in event log.

Return current to zero and reset timer.

Timing

5. Apply appropriate value of current for the test. The results match Table D.2.

Pickup LED illuminates.

Display shows PICKUP 51N PN.

Wisdom software records pickup in event log.

Siemens Energy & Automation, Inc. 65

Appendix D: Acceptance Test Procedures

ISGS Acceptance Test (continued)

Phase N

6. Relay times out per Table D.2

Trip LED illuminates.

Timer stops as Trip 1 contacts close.

Trip log indicates trip current value and time in pickup.

Wisdom software records trip on overcurrent.

Return current to zero and reset timer.

7. Remove control power from relay for five seconds, then restore it.

Trip LED re-illuminates after relay is powered up again.

8. Reset relay target.

Trip LED resets.

Repeat the same steps also for Parameter Set B. Testing may also be done for the user settings following the same procedure.

Neutral Time Overcurrent (51N) Function

Table D.2 Test Points for Very Inverse Curve Characteristics

Multiple of Pickup Time Band 2 (seconds) Time Band 5 (seconds) Time Band 9.9 (seconds)

2X 3.73 9.30 18.38

4X 0.92 2.27 4.46

8X 0.40 0.96 1.87

Accuracy of the time curve for 2 ≤ I/Ip ≤ 20 is 5% from the defined value, or 30 ms, whichever is greater.

66 Siemens Energy & Automation, Inc.

Appendix D: Acceptance Test Procedures

ISGS Acceptance Test

Set the ISGS as follows:

Parameter Set A 7103 5000:5 Current Transformer (CT) 1102 Curve SEA 5, Very Inverse 1702 20 A Nominal Pickup 1703 Time Dial 9.9 1705 Instantaneous Pickup 1 A 1501, 1502, 1503 Instantaneous Time Delay 0.0 1504 Trip Matrixed to Trip 1 Contact 6401

Phase

A B C Connections

1. Connect the appropriate source of control voltage to terminals 13 (+) and 12 (-).

2. Connect suitable variable source current

to phase A on terminals 3 and 4,

to phase B on terminals 5 and 6,

to phase C on terminals 7 and 8.

Instantaneous Phase Overcurrent (50) Function

3. Connect a timer to the trip contacts on terminals 1 and 2.

Pickup

4. Apply a current approximately 75% of the instantaneous pickup.

5. Raise the current and note the value of current at which the relay trips.

Trip LED illuminates.

Timer stops on trip.

Display shows TRIP 50 P1 (2, 3).

Trip log shows TRIP 50 P1 (2, 3) and the correct date and time.

Trip log shows value of current at trip.

Wisdom software records trip in event log.

Return current to zero and reset timer.

6. Set value of current slightly above Instantaneous Overcurrent pickup and record time required to trip.

Repeat above steps for phase B and phase C; repeat the same steps also for Parameter Set B. Tests may be repeated at required settings.

CAUTION: Extended testing at high current levels may damage the relay. Note ratings (Maximum Input Current) in Chapter 1, Section 1.5, Test Specifications.

Siemens Energy & Automation, Inc. 67

Appendix D: Acceptance Test Procedures

ISGS Acceptance Test

Set the ISGS as follows:

Parameter Set A 7103 Voltage Primary Rating 120 V 1201 Connection Line to Neutral 1202 Enable Function 2301 Time Characteristic: Inverse Time 2302 Trip on Line to Neutral 2303 Pickup Level 100 V 2304 Time Dial 5.0 2306 Trip Matrixed to Trip 1 Contact 6401

Phase

A B C Connections

1. Connect the appropriate source of control voltage to terminals 13 (+) and 12 (-).

Relay Disabled contact on terminals 19 and 20 opens.

With 27 enabled, pickup LED is illuminated; relay may trip on Undervoltage before VT source is applied.

2. Connect suitable variable voltage source to terminals 41, 43, and 45 with

Undervoltage (27) Function

neutral connected to 42, 44, and 46.

3. Connect timer to Trip 1 contacts on terminals 1 and 2.

Pickup

4. Apply nominal to neutral system voltage.

Pickup LED extinguishes.

Trip LED may be reset.

5. Slowly reduce voltage until relay picks up.

Pickup LED illuminates.

Display shows PICKUP 27 P1 (2, 3).

Wisdom software records pickup in event log.

6. Return voltage to nominal value.

Pickup LED extinguishes.

Wisdom software records end of pickup.

68 Siemens Energy & Automation, Inc.

Appendix D: Acceptance Test Procedures

ISGS Acceptance Test (continued)

Phase

A B C Timing

Set voltage per Table D.3.

Pickup LED illuminates.

Display shows PICKUP 27 P1 (2, 3).

Wisdom software records pickup in event log.

Relay times out per Table D.3.

Trip LED illuminates.

Timer stops as Trip 1 contacts close.

Trip log indicates trip voltage value and time in pickup.

Wisdom software records relay trip on Undervoltage.

Return voltage to nominal and reset timer.

9. Remove control power from relay for five seconds; then restore it.

Undervoltage (27) Function

Trip LED re-illuminates after relay is powered up again.

10. Reset the relay target.

Trip LED resets.

Repeat above steps for phase B and phase C; repeat the same steps also for Parameter Set B. Testing may also be done at the user settings following the same procedure.

Table D.3 Test Points for Inverse Undervoltage Curve Characteristics

Percent of Pickup Time Band 2 (seconds) Time Band 5 (seconds) Time Band 9.9 (seconds)

90 20.00 50.00 99.00

75 7.74 19.35 38.32

50 3.64 9.10 18.01

0 1.56 3.91 7.73

Accuracy of the time curve for 2 ≤ I/Ip ≤ 20 is 5% from the defined value, or 30 ms, whichever is greater.

Siemens Energy & Automation, Inc. 69

Appendix D: Acceptance Test Procedures

ISGS Acceptance Test

Set the ISGS as follows:

Parameter Set A 7103 Voltage Primary Rating 120 V 1201 Connection Line to Neutral 1202 Enable Function 2201 Time Characteristic: Inverse Time 2202 Trip on Line to Neutral 2203 Pickup Level 100 V 2204 Time Dial per Table 2206 Trip Matrixed to Trip 1 Contact 6401

Phase

A B C Connections

1. Connect the appropriate source of control voltage to terminals 13 (+) and 12 (-).

Relay Disabled contact on terminals 19 and 20 opens.

2. Connect suitable variable voltage source to terminals 41, 43, and 45 with

Overvoltage (59) Function

neutral connected to 42, 44, and 46.

3. Connect a timer to the Trip 1 contacts on terminals 1 and 2.

Pickup

4. Apply nominal to neutral system voltage.

Pickup LED extinguishes.

Trip LED may be reset.

5. Slowly increase voltage until relay picks up.

Pickup LED illuminates.

Display shows PICKUP 59 P1 (2, 3).

Wisdom software records pickup in event log.

6. Return voltage to nominal value.

Pickup LED extinguishes.

Wisdom software records end of pickup.

70 Siemens Energy & Automation, Inc.

Appendix D: Acceptance Test Procedures

ISGS Acceptance Test (continued)

Phase

A B C Timing

Set voltage per Table D.4.

Pickup LED illuminates.

Display shows PICKUP 59 P1 (2, 3).

Wisdom software records pickup in event log.

Relay times out per Table D.4.

Trip LED illuminates.

Timer stops as Trip 1 contacts close.

Trip log indicates trip voltage value and time in pickup.

Wisdom software records relay trip on Overvoltage.

Return voltage to nominal and reset timer.

9. Remove control power from relay for five seconds; then restore it.

Overvoltage (59) Function

Trip LED re-illuminates after relay is powered up again.

10. Reset relay target.

Trip LED resets.

Repeat above steps for phase B and phase C; repeat the same steps also for Parameter Set B. Testing may also be done at the user settings following the same procedure.

Table D.4 Test Points for Inverse Overvoltage Curve Characteristics

Percent of Pickup Time Band 2 (seconds) Time Band 5 (seconds) Time Band 9.9 (seconds)

110 20.00 50.00 99.00

125 7.74 19.35 38.32

150 3.64 9.10 18.01

>150 1.56 3.91 7.73

Accuracy of the time curve for 2 ≤ I/Ip ≤ 20 is 5% from the defined value, or 30 ms, whichever is greater.

Siemens Energy & Automation, Inc. 71

Appendix D: Acceptance Test Procedures

ISGS Acceptance Test

Directional Phase Time Overcurrent (67) Function

(Phase-Neutral Connected VTs)

Set the ISGS as follows:

Parameter Set A 7103 5000:5 Current Transformer (CT) 1101 Curve SEA 5, Very Inverse 1902 1 A Nominal Pickup 1903 Time Dial per Chart 1905 Impedance to 45° 1907 Direction to Reverse 1908 Trip Matrixed to Trip 1 Contact 6401 Enable 67 1901 Disable Other Conflicting Functions 1501, 1551, 1601, 1651, 1801, 1901, 2001, 2301 Raise 51 Pickup to Maximum 1703

Phase

A B C Connections

1. Connect the appropriate source of control voltage to terminals 13 (+) and 12 (-).

Relay Disabled contact on terminals 19 and 20 opens.

2. Connect suitable variable source current to phase A, terminals 3 and 4,

to phase B, terminals 5 and 6,

to phase C, terminals 7 and 8,

3. Connect suitable AC voltage to phase A, terminals 41 and 42,

to phase B, terminals 43 and 44,

to phase C, terminals 45 and 46,

Connect timer to Trip 1 contacts, terminals 1 and 2.

Pickup

4. Apply nominal voltage to the relays voltage inputs, for example, 69 V

Apply 2x pickup current to phase A and B in forward direction, for example, 2.0 A

-relay should not go into pickup,

-reset test current to zero A,

∠ 0 to phase A, ∠ 240 to phase B,

69 V 69 V

∠ 120 to phase C.

∠ 30 to phase A and 2.0 A ∠ 210 to phase B, or ∠ 270 to phase B and 2.0 A ∠ 90 to phase C, or

2.0 A

∠150 to phase C and 2.0 A ∠ 330 to phase A.

2.0 A

-increase phase A and phase B current in reverse direction until relay picks up (at 1.06 x pickup) for example, 1.06 A

72 Siemens Energy & Automation, Inc.

∠ 210 to phase A and 1.06 A ∠ 30 to phase B, or ∠ 90 to phase B and 1.06 A ∠ 270 to phase C, or

1.06 A

∠ 330 to phase C and 1.06 A ∠ 150 to phase A.

Appendix D: Acceptance Test Procedures

ISGS Acceptance Test

(continued)

Phase

ABC

Pickup LED illuminates.

Wisdom software records pickup in event log.

Return current to zero and reset timer.

Timing

Apply appropriate value of current in reverse direction for the test. The results match Table D.5.

Pickup LED illuminates.

Display shows PICKUP 67 P12 (23, 31).

Wisdom software records pickup in event log.

Relay times out per Table D.5

Trip LED illuminates.

Timer stops as Trip 1 contacts close.

Directional Phase Time Overcurrent (67) Function

(Phase-Neutral Connected VTs)

Trip log indicates trip current value and time in pickup.

Wisdom software records trip on directional overcurrent.

Return current to zero and reset timer.

7. Remove control power from relay for five seconds, then restore it.

Trip LED re-illuminates after relay is powered up again.

8. Reset relay target.

Trip LED resets.

Repeat above steps for phase B-C and phase C-A; repeat the same steps also for Parameter Set B. Testing may also be done for each phase at the user settings following the same procedure.

Table D.5 Test Points for Very Inverse Curve Characteristics

Multiple of Pickup Time Band 2 (seconds) Time Band 5 (seconds) Time Band 9.9 (seconds)

2X 3.73 9.30 18.38

4X 0.92 2.27 4.46

8X 0.40 0.96 1.87

Accuracy of the time curve for 2 ≤ I/Ip ≤ 20 is 5% from the defined value, or 30 ms, whichever is greater.

Siemens Energy & Automation, Inc. 73

Appendix D: Acceptance Test Procedures

ISGS Acceptance Test

Directional Phase Time Overcurrent (67) Function

(Phase-Phase Connected VTs)

Set the ISGS as follows:

Phase

A B C Connections

1. Connect the appropriate source of control voltage to terminals 13 (+) and 12 (-).

Relay Disabled contact on terminals 19 and 20 opens.

2. Connect suitable variable source current to phase A, terminals 3 and 4,

to phase B, terminals 5 and 6,

to phase C, terminals 7 and 8,

to neutral, terminals 9 and 10,

3. Connect suitable AC voltage to phase A-B, terminals 41 and 42,

to phase B-C, terminals 43 and 44,

to phase C-A, terminals 45 and 46,

Connect timer to Trip 1 contacts, terminals 1 and 2.

Pickup

4. Apply nominal voltage to the relays voltage inputs, for example, 69 V

Apply 2x pickup current to phase A and B in forward direction, for example, 2.0 A

-relay should not go into pickup,

∠ 30 to phase A-B,

69 V

∠ 270 to phase B-C, ∠ 150 to phase C-A.

69 V

∠ 30 to phase A and 2.0 A ∠ 210 to phase B, or ∠ 270 to phase B and 2.0 A ∠ 90 to phase C, or

2.0 A

∠150 to phase C and 2.0 A ∠ 330 to phase A.

-reset test current to zero A,

74 Siemens Energy & Automation, Inc.

Appendix D: Acceptance Test Procedures

ISGS Acceptance Test

(continued)

Phase

ABC

-increase phase A current in the reverse direction until relay picks up. This should occur at 1.06 x pickup, for example, 1.06 A

1.06 A

Pickup LED illuminates.

Wisdom software records pickup in event log.

Return current to zero and reset timer.

Timing

Apply appropriate value of current in reverse direction for the test. The results match Table D.6.

Pickup LED illuminates.

Display shows PICKUP 67 P12 (23, 31).

Wisdom software records pickup in event log.

Directional Phase Time Overcurrent (67) Function

(Phase-Phase Connected VTs)

∠ 210 to phase A and 1.06 A ∠ 30 to phase B, or ∠ 90 to phase B and 1.06 A ∠ 270 to phase C, or ∠ 330 to phase C and 1.06 A ∠ 150 to phase A.

Relay times out per Table D.6

Trip LED illuminates.

Timer stops as Trip 1 contacts close.

Trip log indicates trip current value and time in pickup.

Wisdom software records trip on directional overcurrent.

Return current to zero and reset timer.

7. Remove control power from relay for five seconds, then restore it.

Trip LED re-illuminates after relay is powered up again.

8. Reset relay target.

Trip LED resets.

Repeat above steps for phase B-C and phase C-A; repeat the same steps also for Parameter Set B. Testing may also be done for each phase at the user settings following the same procedure.

Table D.6 Test Points for Very Inverse Curve Characteristics

Multiple of Pickup Time Band 2 (seconds) Time Band 5 (seconds) Time Band 9.9 (seconds)

2X 3.73 9.30 18.38

4X 0.92 2.27 4.46

8X 0.40 0.96 1.87

Accuracy of the time curve for 2 ≤ I/Ip ≤ 20 is 5% from the defined value, or 30 ms, whichever is greater.

Siemens Energy & Automation, Inc. 75

Appendix D: Acceptance Test Procedures

ISGS Acceptance Test

Set the ISGS as follows:

Parameter Set A 7103 5000:5 Current Transformer (CT) 1102 Curve SEA 5, Very Inverse 2002 1 A Nominal Pickup 2003 Time Dial per Chart 2005 Impedance to 45° 1907 Direction to Reverse 1908 Trip Matrixed to Trip 1 Contact 6401 Enable 67 2001 Disable Other Conflicting Functions 1501, 1551, 1601, 1651, 1801, 1901, 2001, 2301 Raise 51 Pickup to Maximum 1703

Phase N Connections

1. Connect the appropriate source of control voltage to terminals 13 (+) and 12 (-).

2. Relay Disabled contact on terminals 19 and 20 opens.

3. Connect suitable variable source current to phase A, terminal 3,

Directional Neutral Time Overcurrent (67N)

(Only Available with Phase-Neutral Connected VTs)

Function

to phase B, terminal 5,

to phase C, terminal 7,

Connect terminals 4, 6, and 8 to terminal 9.

Connect terminal 10 to the common of the current sources.

4. Connect suitable AC voltage to phase A, terminals 41 and 42,

to phase B, terminals 43 and 44,

to phase C, terminals 45 and 46,

Connect timer to Trip 1 contacts, terminals 1 and 2.

Pickup

5. Apply nominal voltage to the relays voltage inputs, for example, for example, 69 V

Apply 2x pickup current to phase A in forward direction, for example, for example, 2.0 A

-relay should not go into pickup,

∠ 0 to phase A,

69 V

∠ 240 to phase B, ∠ 120 to phase C.

69 V

∠ 0 to phase A, ∠ 240 to phase B,

2.0 A

∠120 to phase C.

-reset test current to zero A,

76 Siemens Energy & Automation, Inc.

Appendix D: Acceptance Test Procedures

ISGS Acceptance Test

(continued)

Phase N

-increase phase A current in the reverse direction until relay picks up. This should occur at 1.06 x pickup, for example, 1.06 A

Pickup LED illuminates.

Wisdom software records pickup in event log.

Return current to zero and reset timer.

Timing

Apply appropriate value of current in reverse direction for the test. The results match Table D.7.

Pickup LED illuminates.

Display shows PICKUP 67N PN.

Wisdom software records pickup in event log.

∠ 180 to phase A,

∠ 60 to phase B,

1.06 A

∠ 300 to phase C.

Directional Neutral Time Overcurrent (67N)

Function

(Only Available with Phase-Neutral Connected VTs)

Relay times out per Table D.7

Trip LED illuminates.

Timer stops as Trip 1 contacts close.

Trip log indicates trip current value and time in pickup.

Wisdom software records trip on directional overcurrent.

Return current to zero and reset timer.

8. Remove control power from relay for five seconds, then restore it.

Trip LED re-illuminates after relay is powered up again.

9. Reset relay target.

Trip LED resets.

Repeat above steps for phase B and phase C; repeat the same steps also for Parameter Set B. Testing may also be done for each phase at the user settings following the same procedure.

Table D.7 Test Points for Very Inverse Curve Characteristics

Multiple of Pickup Time Band 2 (seconds) Time Band 5 (seconds) Time Band 9.9 (seconds)

2X 3.73 9.30 18.38

4X 0.92 2.27 4.46

8X 0.40 0.96 1.87

Accuracy of the time curve for 2 ≤ I/Ip ≤ 20 is 5% from the defined value, or 30 ms, whichever is greater.

Siemens Energy & Automation, Inc. 77

Appendix D: Acceptance Test Procedures

50/

50/51

51N

ISGS Relay

Test Equipment

CT 1-1 CT 1-2

CT 2-1 CT 2-2 CT 3-1 CT 3-2 CT N-1 CT N-2

VT 1+

VT 1VT 2+

VT 2VT 3+

VT 3-

3 4 5 6 7 8 9 10

42 43

44 45

22 23

24 25

26 27

Binary Input 1

Binary Input 2

Binary Input 3

Binary Input 4

Trip 1

Trip Common

Trip 2

Trip 3

Binary Output 1

Binary Output 2

2 1 11

29 30

31 32

33 34

ISGS Relay

Figure D.1 Terminal Connections for Test Procedures

78 Siemens Energy & Automation, Inc.

E Schematics

E.1 DC Trip System

The following diagram illustrates a typical connection scheme for the ISGS relay when using a DC trip system.

Appendix E: Schematics

11718

(see below)

Optional

RS-485

Communications

IN1

Impedance

Sense

Impedance

Source

Trip

Common

Trip 1 Trip 2

Case

Ground

Power

Supply

(DC-DC)

Impedance

Trip Source

Sense Circuit

BI BSW

Monitors

b-contacts

Relay

Disabled*

IN2

Ground

Monitor

211

Trip

15 16 12

closed when

relay is out of service

ISGS Relay

*Contact is

95C

Monitors

a-contacts

and trip coil

Optional

Remote

Closing

Incoming

RS-485

Shield

Data +

Bus

Data -

Outgoing

RS-485

Bus

Shield

Data + Data +

Data - Data -

Optional

RS-485

Communications

52a

52T

SRC

52b

52a

15 2 14

Breaker

Fuse

Aux Switch (open when breaker is open)

Aux Switch (closed when breaker is open)

Opening Solenoid (Trip)

Spring Release Solenoid

Spring Charging Motor

Control Switch/Close

Control Switch/TripRRed Lamp (breaker open)

Green Lamp (breaker open)

Interposing Relay

???

Key

52a

52b

52T

52SRC

CS/C

CS/T

95C

RES

Fuse

95C

(Station

Battery)

313 161 4

DC Supply

Figure E.1 Wiring for DC Trip Systems

Siemens Energy & Automation, Inc. 79

Appendix E: Schematics

E.2 AC (Capacitor) Trip Systems

The following diagram illustrates a typical connection scheme for the ISGS relay when using an AC trip system.

Key

52a

52b

52T

52SRC

CS/C

CS/T

95C

CTD

AC0

(120 VAC

Only)

AC Supply

AC1

Spring Charging Motor

Control Switch/Close

Control Switch/TripRRed Lamp (breaker open)

Green Lamp (breaker open)

Interposing Relay

Capacitor Trip Device

???

Optional

RS-485

Communications

Aux Switch (open when breaker is open)

Aux Switch (closed when breaker is open)

Opening Solenoid (Trip)

Spring Release Solenoid

ground monitor (16), and impedance

sense (18) to AC0.

Slug

*Not used with AC configuration.

Tie impedance source (terminal 17),

Slug

15 214

Breaker

Closing

SRC

CTD

52a

52T

Optional

Remote

52a

95C

313 16 1114

95C

Trip 1 Trip 2

1-Fuse

RES

1-Fuse

Trip

Common

17 18

Sense Circuit*

Trip Source

Impedance

494848

Data - Data -

Shield

RS-485

Bus

Data + Data +

Outgoing

Data +

Data -

RS-485

Bus

Shield

Incoming

52b52a

RES

IN2

Trip

1516 12

BSW

14211

*Contact is

relay is out of service

ISGS Relay

closed when

Disabled*

Relay

(AC-DC)

Supply

Power

Case

Ground

IN1

Optional

RS-485

Communications

(see below)

Figure E.2 Wiring for AC (Capacitor) Trip System

80 Siemens Energy & Automation, Inc.

ISGS Settings Worksheet for Date: Set A

This ISGS settings worksheet allows easy recording of the desired ISGS parameter settings when configuring the device manually with the keypad controls.

Functions and parameters are listed in numerical sequence of their address blocks and addresses just as they appear on the LCD. Where applicable, value ranges and resolution are provided for easy reference. Only configurable functions and parameters are listed. For a complete list refer to the ISGS relay menu in Appendix C.

Before configuring the device, copy this form and enter the desired configuration data. Include the device identification number (device version number and its catalog number on front panel label; or line 1 and line 2 of Power On display) and the date of configuration. Then simply circle the desired set-

0000 Power On Display (enter display)

----

Line 1

----

Line 2

tings and enter numerical values in the blank spaces provided. Boldfaced settings indicate factory defaults. For indicating matrix settings, draw a line from the matrix position number to the desired setting and circle the setting.

Take special care in copying lines 1 and 2 of the relays Power On display (refer to Section 4.1). The information displayed in these two lines provides Siemens with detailed information about the device in the event you encounter a problem and have to contact Siemens customer service.

After entering all data on this configuration form, take it to the device and enter the information into the relay. This form allows for the recording of both parameter sets. After completing this form, file it for future reference.

1000 Device Configuration

1002

Frequency

1003

Phase Sequence

1004

Breaker Connection

1005

Trip T im e

1100 Current Transformer Configuration

1101 Phase CT Primary Rating 1200 A

1102 Neutral CT Primary Rating 1200 A

1104 Power Flow Normal Reverse

1200 Voltage Transformer Configuration

1201 Primary Rating 12000 V

1202 VT Mode Line-to-Line Line-to-Neutral

60 Hz 50 Hz

123 (ABC) 132 (ACB)

Trip1 Trip2 Trip3 Trips 1&2 Trips1&3 Trips 123

0.1 s

Range: 0.01-32 s (0.01 s steps)

Range: 5-8000 A (1 A steps)

Range: 120-138000 V (1 V steps)

1203 Secondary VT Rating 120 V Range: 100-120 V (1 V steps) V

Siemens Energy & Automation, Inc. S-1

ISGS Settings Worksheet for Date: Set A

A1500

A1501 Function 50 Enabled Disabled

A1502

A1504 Time Delay 50 0.00 s Range: 0-60 s (0.01 s steps) s

A1512 Block 50 by None 50HS & 50HSN 50HS 50HSN

A1551 Function 50HS Enabled Disabled

A1552

Instantaneous Phase Overcurrent (50) High-Set Instantaneous Phase Overcurrent (50HS)

Pickup 50 5 A CT 1.0 A Range: 1-120 A (0.1 A steps) A

1 A CT 0.2 A Range: 0.2-24 A (0.1 A steps) A

1510 Freeze Waveform 1 50 on pickup on Trip None

1511 Freeze Waveform 2 50 on pickup on Trip None

Pickup 50HS 5 A CT 5.0 A Range: 5-120 A (0.1 A steps) A

1 A CT 0.2 A Range: 0.2-24 A (0.1 A steps) A

1560 Freeze Waveform 1 50HS --- on Trip None

1561 Freeze Waveform 2 50HS --- on Trip None

A1600

A1601 Function 50N Enabled Disabled

A1602

A1604 Time Delay 50N 0.00 s Range: 0-60 s (0.01 s steps) s

A1612 Block 50N by None 50HS & 50HSN 50HS 50HSN

A1651 Function 50HSN Enabled Disabled

A1652

Instantaneous Neutral or Ground Overcurrent (50N) High-Set Instantaneous Neutral or Ground Overcurrent (50HSN)

Pickup 50N 5 A CT 1.0 A Range: 1-120 A (0.1 A steps) A

1 A CT 0.2 A Range: 0.2-24 A (0.1 A steps) A

1610 Freeze Waveform 1 50N on Pickup on Trip None

1611 Freeze Waveform 2 50N on Pickup on Trip None

Pickup 50HSN 5 A CT 5.0 A Range: 5-120 A (0.1 A steps) A

1 A CT 0.2 A Range: 0.2-24 A (0.1 A steps) A

1660 Freeze Waveform 1 50HSN --- on Trip None

1661 Freeze Waveform 2 50HSN --- on Trip None

S-2 Siemens Energy & Automation, Inc.

ISGS Settings Worksheet for Date: Set A

A1700 Phase Time Overcurrent (51)

A1702

A1703

A1705 Time Dial 51 0.1 Range: 0.1-9.9 (0.1 steps)

A1706 Filter 51 rms fundamental

A1709 Reset 51 Disk Emulation Instantaneous

A1712 Block 51 by None 50HS & 50HSN 50HS 50HSN

A1800 Neutral Time Overcurrent (51N)

Curve 51 Inverse Short Inverse Long Inverse

Custom Very Inverse Extremely Inverse Definite Inverse

Slightly Inverse

Pickup 51 5 A CT 0.5 A Range: 0.5-20 A (0.1 A steps) A

(PU point is 1.06 1 A CT of PU setting).

1710 Freeze Waveform 1 51 on Pickup on Trip None

1711 Freeze Waveform 2 51 on Pickup on Trip None

0.1 A Range: 0.1-4 A (0.1 A steps) A

T without Limit

Moderately Inverse

A1801 Function 51N Enabled Disabled

A1802

A1803

A1805 Time Dial 51N 0.1 Range: 0.1-9.9 (0.1 steps)

A1806 Filter 51N rms fundamental

A1809 Reset 51N Disk Emulation Instantaneous

A1812 Block 51N by None 50HS & 50HSN 50HS 50HSN

Curve 51N Inverse Short Inverse Long Inverse

Custom Very Inverse Extremely Inverse Definite Inverse

Slightly Inverse

Pickup 51N 5 A CT 0.5 A Range: 0.5-20 A (0.1 A steps) A

1 A CT 0.1 A Range: 0.1-4 A (0.1 A steps) A

1810 Freeze Waveform 1 51N on Pickup on Trip None

1811 Freeze Waveform 2 51N on Pickup on Trip None

T without Limit

Moderately Inverse

Siemens Energy & Automation, Inc. S-3

ISGS Settings Worksheet for Date: Set A

A1900 Directional Phase Time Overcurrent (67)

A1901 Function 67 Enabled Disabled

A1902 Curve 67 Inverse Short Inverse Long Inverse

Custom Very Inverse Extremely Inverse Definite Inverse

Slightly Inverse

A1903

A1905 Time Dial 67 0.10 Range: 0.1-9.9 (0.1 steps)

A1906 Filter 67 rms fundamental

A1907 Impedance 67 45° Range: 0-90° (1° steps) °

A1908 Direction 67 Normal Reverse

A2000 Directional Neutral Time Overcurrent (67N)

Pickup 67 5 A CT 0.5 A Range: 0.5-20 A (0.1 A steps) A

1 A CT 0.1 A Range: 0.1-4 A (0.1 A steps) A

1910 Freeze Waveform 1 67 on Pickup on Trip None

1911 Freeze Waveform 2 67 on Pickup on Trip None

T without Limit

Moderately Inverse

A2001 Function 67N Enabled Disabled

A2002 Curve 67N Inverse Short Inverse Long Inverse

Custom Very Inverse Extremely Inverse Definite Inverse

Slightly Inverse

A2003

A2005 Time Dial 67N 0.10 Range: 0.1-9.9 (0.1 steps)

A2006 Filter 67N rms fundamental

A2007 Impedance 67N 45° Range: 0-90° (1 ° steps) °

A2008 Direction 67N Normal Reverse

Pickup 67N 5 A CT 0.5 A Range: 0.5-20 A (0.1 A steps) A

(PU point is 1.06 1 A CT of PU setting).

2010 Freeze Waveform 1 67N on Pickup on Trip None

2011 Freeze Waveform 2 67N on Pickup on Trip None

0.1 A Range: 0.1-4 A (0.1 A steps) A

T without Limit

Moderately Inverse

S-4 Siemens Energy & Automation, Inc.

ISGS Settings Worksheet for Date: Set A

A2200 Overvoltage (59)

A2201 Function 59 Enabled Disabled

A2202 Curve 59 Inverse

A2203

A2204 Pickup 59 130 V Range: 60-250 V (0.1 V steps) V

A2205 Time Delay 59 (Definite) 0.10 s

A2206 Time Dial 59 (Inverse) 0.1 Range: 0.1-9.9 (0.1 steps)

A2300 Undervoltage (27)

A2301 Function 27 Enabled Disabled

A2302 Curve 27 Inverse

A2303

A2304 Pickup 27 50 V Range: 40-230 V (0.1 V steps) V

Pickup Source Voltage 59 (if VT mode is (L-N)

2210 Freeze Waveform 1 59 on Pickup on Trip None

2211 Freeze Waveform 2 59 on Pickup on Trip None

PU Source V 27 (if VT mode is (L-N)

Line-to-Line Line-to-Neutral

Moderately Inverse

Range: 0-60 s (0.01 s steps),

∞

Moderately Inverse

Very Inverse Definite Inverse

A2305 Time Delay 27 (Definite) 0.10 s

A2306 Time Dial 27 (Inverse) 0.1 Range: 0.1-9.9 (0.1 steps)

2310 Freeze Waveform 1 27 on Pickup on Trip None

2311 Freeze Waveform 2 27 on Pickup on Trip None

Range: 0-60 s (0.01 s steps),

∞

Siemens Energy & Automation, Inc. S-5

ISGS Settings Worksheet for Date: Set A

A2400

A2401 Function 47 Enabled Disabled

A2451 Function 47N Enabled Disabled

A2452 Curve 47N Inverse Definite Inverse

A2453 Pickup 47N 10% Range: 4-40% (1% steps) %

A2454 Time Delay 47N(Defin.) 0.00 s

A2455 Time Dial 47N (Inverse) 0.10 Range: 0.1-9.9 (0.1 steps)

A2456 Maximum Time (Inverse) 120 s Range: 1-250 s (1 s steps) s

A2457 Block 47N by 40 V Range: 40-120 V (1 V steps) V

Phase Sequence Voltage (47) Negative Sequence Voltage (47N)

2410 Freeze Waveform 1 47 --- on Trip None

2411 Freeze Waveform 2 47 --- on Trip None

Range: 0-100 s (0.01 s steps),

∞

2460 Freeze Waveform 1 47N on pickup on Trip None

2461 Freeze Waveform 2 47N on pickup on Trip None

S-6 Siemens Energy & Automation, Inc.

ISGS Settings Worksheet for Date: Set A

A2500

A2501 Function 81O Enabled Disabled

A2502 Pickup 81O 62.0 Hz

A2504 Time Delay 81O 0.10 s

A2551 Function 81U Enabled Disabled

A2553 Pickup 81U 58.0 Hz

A2554 Delay 81U 0.10 s

A2556 Block 81U 40 V Range: 40-120 V (1 V steps) V

Overfrequency (81O) Underfrequency (81U)

Range: 60.1-65.0 Hz (0.1 Hz steps)

Range: 0-100 s (0.01 s steps), or

∞

2506 Block 81O 40 V Range: 40-120 V (1 V steps) V

2510 Frz. Wfm1 81O on Pickup on Trip None

2511 Frz. Wfm2 81O on Pickup on Trip None

Range: 55.0-59.9 Hz (0.1 Hz steps)

Range: 0-100 s (0.01 s steps),

∞

2560 Freeze Waveform 1 81U on pickup on Trip None

2561 Freeze Waveform 2 81U on pickup on Trip None

2800 Breaker Failure (50BF)

2801 Function 50BF Enabled Disabled

2803 Pickup 50BF 5 A CT 0.25 A

1 A CT 0.1 A

2804 Delay 50BF 10 cycles Range: 8-254 cycles cycles

2805 Monitor 50BF current breaker both

Range: 0.25-5.0 A (0.01 A steps)

Range: 0.02-1.0 A (0.01 A steps)

Siemens Energy & Automation, Inc. S-7

ISGS Settings Worksheet for Date: Set A

3000 Alarm Setpoints

3100 Demand Setpoints

3101 Demand Interval 15 30 60 minutes

3102 Sync time 0 15 30 45 minutes after hour

3103 Subperiods 60 1 234612

3104 Subperiods 30 1 236

3105 Subperiods 15 1 3

3106 Current Average Demand Enabled Disabled

3107 Current Average Demand Pickup 3000 A Range: 0-9999 A (1 A steps) A

3108 KW Demand Enabled Disabled

3109 KW Demand Pickup 100000 kW

3200 Power Setpoints

3201 KVAR Function Enabled Disabled

3202 KVAR Pickup 100000 kVAR

3203 KVAR Time Delay 1800 s Range: 0-3600 s (1 s steps) s

3204 KVA Function Enabled Disabled

3205 KVA Pickup 100000 kVA

3206 KVA Time Delay 1800 s Range: 0-3600 s (1 s steps) s

3207 PF Lead Function Enabled Disabled

3208 PF Lead Pickup 0.8 Range: 0.2-1.0 (0.1 steps)

3209 PF Lead Sign Lag Lead

3210 PF Lead Delay 1800 s Range: 0-3600 s (1 s steps) s

Range: 0-999,999 kW (1 kW steps)

Range: 0-999,999 kVAR (1 kVAR steps)

Range: 0-999,999 kVA (1 kVA steps)

kVAR

kVA

3211 PF Lag Function Enabled Disabled

3212 PF Lag Pickup 0.8 Range: 0.2-1.0 (0.1 steps)

3213 PF Lag Sign Lag Lead

3214 PF Lag Delay 1800 s Range: 0-3600 s (1 s steps) s

S-8 Siemens Energy & Automation, Inc.

ISGS Settings Worksheet for Date: Set A

3400 Value Supervision

3401 Voltage Balance Function Enabled Disabled

3402 Voltage Balance Pickup 100 V Range: 40-120 V (0.1 V steps) V

3404 Voltage Balance Factor 0.80

3411 Current Sum Function Enabled Disabled

3412 Current Sum Pickup 5 A CT 0.5 A Range: 0.5-5 A (0.1 A steps) A

1 A CT 0.1 A Range: 0.1-1 A (0.1 A steps) A

3414 Current Sum Factor 0.10

3411 Current Balance Function Enabled Disabled

3412 Current Balance Pickup 5 A CT 2.5 A Range: 0.5-5 A (0.1 A steps) A

1 A CT 0.1 A Range: 0.1-1 A (0.1 A steps) A

3414 Current Balance Factor 0.80

3500 Breaker Operation

3501 Interrupted Current Function Enabled Disabled

3502 Interrupted Current Pickup 1000.00 kA

Range: 0.58-0.95 (0.01 teps)

Range: 0.10-0.95 (0.01 steps)

Range: 0-9999.9 kA (1 kA steps)

3503 Breaker Operations Functions Enabled Disabled

3504 Breaker Operations Counter 100 Range: 0-65535

Siemens Energy & Automation, Inc. S-9

ISGS Settings Worksheet for Date: Set A

6000 Matrixing

6100 Binary Inputs

001

6101

Input 1

Frz.Buff1 Hi Frz.Buff1 Lo Frz.Buff2 Hi Frz.Buff2 Lo

blk 47N Hi blk 47N Lo blk 47 Hi blk 47 Lo

002

blk 81U Hi blk 81U Lo blk 81O Hi blk 81O Lo

003

blk 50 Hi blk 50 Lo blk 50N Hi blk 50N Lo

004

blk 50HS blk 50HS Lo blk 50HSN Hi blk 50HSN Lo

005

blk 51N Hi blk 51N Lo blk 59 Lo blk 59 Hi

blk 27 Hi blk 27 Lo blk 67 Hi blk 67 Lo

006

blk 67N Hi blk 67N Lo blk 50BF Hi blk 50BF Lo

007

blk ComEvt Hi blkComEvt Lo SwitchPara Hi SwitchPara Lo

008

BI1 Hi (001) BI1 Lo BI2 Hi BI2 Lo

6102

Input 2

009

BI3 Hi BI3 Lo BI4 Hi BI4 Lo

not matrixed

010

001

Frz.Buff1 Hi Frz.Buff1 Lo Frz.Buff2 Hi Frz.Buff2 Lo

blk 47N Hi blk 47N Lo blk 47 Hi blk 47 Lo

002

blk 81U Hi blk 81U Lo blk 81O Hi blk 81O Lo

003

blk 50 Hi blk 50 Lo blk 50N Hi blk 50N Lo

004

blk 50HS blk 50HS Lo blk 50HSN Hi blk 50HSN Lo

005

blk 51N Hi blk 51N Lo blk 59 Lo blk 59 Hi

blk 27 Hi blk 27 Lo blk 67 Hi blk 67 Lo

006

blk 67N Hi blk 67N Lo blk 50BF Hi blk 50BF Lo

007

blk ComEvt Hi blkComEvt Lo SwitchPara Hi SwitchPara Lo

008

BI1 Hi BI1 Lo BI2 Hi (001) BI2 Lo

009

BI3 Hi BI3 Lo BI4 Hi BI4 Lo

not matrixed

010

S-10 Siemens Energy & Automation, Inc.

ISGS Settings Worksheet for Date: Set A

6100 Binary Inputs (continued)

001

6103

Input 3

Frz.Buff1 Hi Frz.Buff1 Lo Frz.Buff2 Hi Frz.Buff2 Lo

blk 47N Hi blk 47N Lo blk 47 Hi blk 47 Lo

002

blk 81U Hi blk 81U Lo blk 81O Hi blk 81O Lo

003

blk 50 Hi blk 50 Lo blk 50N Hi blk 50N Lo

004

blk 50HS blk 50HS Lo blk 50HSN Hi blk 50HSN Lo

005

blk 51N Hi blk 51N Lo blk 59 Lo blk 59 Hi

blk 27 Hi blk 27 Lo blk 67 Hi blk 67 Lo

006

blk 67N Hi blk 67N Lo blk 50BF Hi blk 50BF Lo

007

blk ComEvt Hi blkComEvt Lo SwitchPara Hi SwitchPara Lo

008

BI1 Hi BI1 Lo BI2 Hi BI2 Lo

6104

Input 4

009

BI3 Hi (001) BI3 Lo BI4 Hi BI4 Lo

not matrixed

010

001

Frz.Buff1 Hi Frz.Buff1 Lo Frz.Buff2 Hi Frz.Buff2 Lo

blk 47N Hi blk 47N Lo blk 47 Hi blk 47 Lo

002

blk 81U Hi blk 81U Lo blk 81O Hi blk 81O Lo

003

blk 50 Hi blk 50 Lo blk 50N Hi blk 50N Lo

004

blk 50HS blk 50HS Lo blk 50HSN Hi blk 50HSN Lo

005

blk 51N Hi blk 51N Lo blk 59 Lo blk 59 Hi

blk 27 Hi blk 27 Lo blk 67 Hi blk 67 Lo

006

blk 67N Hi blk 67N Lo blk 50BF Hi blk 50BF Lo

007

blk ComEvt Hi blkComEvt Lo SwitchPara Hi SwitchPara Lo

008

BI1 Hi BI1 Lo BI2 Hi BI2 Lo

009

BI3 Hi BI3 Lo BI4 Hi (001) BI4 Lo

not matrixed

010

Siemens Energy & Automation, Inc. S-11

ISGS Settings Worksheet for Date: Set A

6200 Binary Outputs

001

6201

Output 1

BI1 BI2 BI3 BI4

002

Error Sum I Error Sym I Error Sym V OC Pickup

003

OC Trip Non OC PU Non OC Trip Relay Pickup

004

Relay Tripped no f f <> 50HS Trip

005

50HSN Trip 81O Pickup 81O Trip UV blks 81O

006

81U Pickup 81U Trip UV blks 81U 47N Pickup

007

47N Trip UV blks 47N 50HS blks 50 50HSN blks 50

008

50 Pickup 50 Trip 50HS blks 50N 50HSN blks 50N

009

50N Pickup 50N Trip 50HS blks 51 50HSN blks 51

010

011

51 Pickup 51 Trip 50HS blks 51N 50HSN bl. 51N

012

51N Pickup 51N Trip 67 Pickup 67 Trip

013

67N Pickup 67N Trip 27 Pickup 27 Trip

014

59 Pickup 59 Trip 47 Trip OvrBrOps PU

015

OvrbrAmpsPU

016

OvrkVA Pickup PFLag Pickup PFLead Pickup 50BF Pickup

017

50BF Trip TrScMon PU TrCoilCont PU BrMech PU

018

CommEvent 1 CommEvent 2 CommEvent 3 CommEvent 4

019

CommEvent 5 not matrixed

020

OvrAmpsDmd PU

OvrkWDmdPU OvrkVAR PU

S-12 Siemens Energy & Automation, Inc.

ISGS Settings Worksheet for Date: Set A

6200 Binary Outputs (continued)

001

6202

Output 2

BI1 BI2 BI3 BI4

002

Error Sum I Error Sym I Error Sym V OC Pickup

003

OC Trip Non OC PU Non OC Trip Relay Pickup

004

Relay Tripped no f f <> 50HS Trip

005

50HSN Trip 81O Pickup 81O Trip UV blks 81O

006

81U Pickup 81U Trip UV blks 81U 47N Pickup

007

47N Trip UV blks 47N 50HS blks 50 50HSN blks 50

008

50 Pickup 50 Trip 50HS blks 50N 50HSN blks 50N

009

50N Pickup 50N Trip 50HS blks 51 50HSN blks 51

010

011

51 Pickup 51 Trip 50HS blks 51N 50HSN bl. 51N

012

51N Pickup 51N Trip 67 Pickup 67 Trip

013

67N Pickup 67N Trip 27 Pickup 27 Trip

014

59 Pickup 59 Trip 47 Trip OvrBrOps PU

015

OvrbrAmpsPU

016

OvrkVA Pickup PFLag Pickup PFLead Pickup 50BF Pickup

017

50BF Trip TrScMon PU TrCoilCont PU BrMech PU

018

CommEvent 1 CommEvent 2 CommEvent 3 CommEvent 4

019

CommEvent 5 not matrixed

020

OvrAmpsDmd PU

OvrkWDmdPU OvrkVAR PU

Siemens Energy & Automation, Inc. S-13

ISGS Settings Worksheet for Date: Set A

6400 Trip Contacts

001

6401

Contact 1

BI1 BI2 BI3 BI4

002 003

OC Trip Non OC Trip Relay Tripped 50HS Trip

004 005

50HSN Trip 81O Trip 81U Trip 47N Trip

006

(005)

007

50 Trip

008 009

67 Trip 67N Trip 27 Trip 59 Trip

010 011

47Trip OvrBrOps PU OvrbrAmpsPU OvrAmpsDmd PU

012 013

OvrkWDmdPU OvrkVAR PU OvrkVA Pickup PFLag Pickup

014 015

PFLead Pickup 50BF Pickup TrScMon PU TrCoilCont PU

016 017

BrMech PU

018 019

CommEvent 4 CommEvent 5 not matrixed

020

(002)

50N Trip

(001) CommEvent 1

(003)

51 Trip

CommEvent 2 CommEvent 3

(004) 51N Trip

6402

Contact 2

001

BI1 BI2 BI3 BI4

002 003

OC Trip Non OC Trip Relay Tripped 50HS Trip

004 005

50HSN Trip 81O Trip 81U Trip 47N Trip

006 007

50 Trip 50N Trip 51 Trip 51N Trip

008 009

67 Trip 67N Trip 27 Trip 59 Trip

010 011

47Trip OvrBrOps PU OvrbrAmpsPU OvrAmpsDmd PU

012 013

OvrkWDmdPU OvrkVAR PU OvrkVA Pickup PFLag Pickup

014 015

PFLead Pickup 50BF Pickup TrScMon PU TrCoilCont PU

016 017

BrMech PU CommEvent 1

018 019

CommEvent 4 CommEvent 5 not matrixed

020

(001)

CommEvent 2

CommEvent 3

S-14 Siemens Energy & Automation, Inc.

Siemens SG8158-00 User Manual

Specifications and Main Features

Frequently Asked Questions

User Manual