Kcgg142 Man

Service Manual Types KCGG 122, 142, KCEG 112, 142, 152, 242 and KCEU 142, 242 Overcurrent and Directional Overcurrent Relays

Service Manual Types KCGG 122, 142, KCEG 112, 142, 152, 242 and KCEU 142, 242 Overcurrent and Directional Overcurrent Relays HANDLING OF ELECTRONIC EQUIPMENT A person's normal movements can easily generate electrostatic potentials of several thousand volts. Discharge of these voltages into semiconductor devices when handling electronic circuits can cause serious damage, which often may not be immediately apparent but the reliability of the circuit will have been reduced. The electronic circuits of ALSTOM T&D Protection & Control Ltd products are immune to the relevant levels of electrostatic discharge when housed in their cases. Do not expose them to the risk of damage by withdrawing modules unnecessarily. Each module incorporates the highest practicable protection for its semiconductor devices. However, if it becomes necessary to withdraw a module, the following precautions should be taken to preserve the high reliability and long life for which the equipment has been designed and manufactured. 1. Before removing removing a module, module, ensure ensure that you are at at the same electrost electrostatic atic potential potential as as the equipment equipment by touching the case. 2. Handle the the module module by its front-pla front-plate, te, frame, frame, or edges edges of the printed printed circuit circuit board. board. Avoid touching the electronic components, printed circuit track or connectors. 3. Do not pass pass the module module to any any person without without first first ensuring ensuring that you you are both both at the same same electrostatic potential. Shaking hands achieves equipotential. 4. Place the the module module on an antistat antistatic ic surface, surface, or on a conducti conducting ng surface surface which is at the same potential as yourself. 5. Store Store or transp transport ort the the module module in a cond conduct uctive ive bag. bag. More information on safe working procedures for all electronic equipment can be found in BS5783 and IEC 60147-0F. If you are making measurements on the internal electronic circuitry of an equipment in service, it is preferable that you are earthed to the case with a conductive wrist strap. Wrist straps should have a resistance to ground between 500k – 10M ohms. If a wrist strap is not available, you should maintain regular contact with the case to prevent the build up of static. Instrumentation which may be used for making measurements should be earthed to the case whenever possible. ALSTOM T&D Protection & Control Ltd strongly recommends that detailed investigations on the electronic circuitry, or modification work, should be carried out in a Special Handling Area such as described in BS5783 or IEC 60147-0F.

Types KCGG 122, 142, KCEG 112, 142, 152, 242 and KCEU 142, 242 Overcurrent and Directional Overcurrent Relays

Service Manual R8551D

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242

R8551D Contents

SAFETY SECTION THIS MUST BE READ BEFORE ANY WORK IS CARRIED OUT ON THE RELAY CHAPTER 1

INTRODUCTION

CHAPTER 2

HANDLING AND INSTALLATION

CHAPTER 3

RELAY DESCRIPTION

CHAPTER 4

APPLICATION OF PROTECTION FUNCTIONS

CHAPTER 5

MEASUREMENT AND RECORDS

CHAPTER 6

SERIAL COMMUNICATIONS

CHAPTER 7

TECHNICAL DATA

CHAPTER 8

COMMISSIONING

APPENDIX 1

RELAY CHARACTERISTIC CURVES

APPENDIX 2

LOGIC DIAGRAMS

APPENDIX 3

CONNECTION DIAGRAMS

APPENDIX 4

COMMISSIONING TEST RECORD

Page 2

SAFETY SECTION This Safety Section should be read before commencing any work on the equipment. Health and safety The information in the Safety Section of the product documentation is intended to ensure that products are properly installed and handled in order to maintain them in a safe condition. It is assumed that everyone who will be associated with the equipment will be familiar with the contents of the Safety Section. Explanation of symbols and labels The meaning of symbols and labels which may be used on the equipment or in the product documentation, is given below.

Caution: refer to product documentation

Caution: risk of electric shock

Protective/safety *earth terminal

Functional *earth terminal. Note: this symbol may also be used for a protective/ safety earth terminal if that terminal is part of a terminal block or sub-assembly eg. power supply.

*Note: The term earth used throughout the product documentation is the direct equivalent of the North American term ground.

Installing, Commissioning and Servicing Equipment connections Personnel undertaking installation, commissioning or servicing work on this equipment should be aware of the correct working procedures to ensure safety. The product documentation should be consulted before installing, commissioning or servicing the equipment. Terminals exposed during installation, commissioning and maintenance may present a hazardous voltage unless the equipment is electrically isolated. If there is unlocked access to the rear of the equipment, care should be taken by all personnel to avoid electric shock or energy hazards. Voltage and current connections should be made using insulated crimp terminations to ensure that terminal block insulation requirements are maintained for safety. To ensure that wires are correctly terminated, the correct crimp terminal and tool for the wire size should be used. Page 3

Before energising the equipment it must be earthed using the protective earth terminal, or the appropriate termination of the supply plug in the case of plug connected equipment. Omitting or disconnecting the equipment earth may cause a safety hazard. The recommended minimum earth wire size is 2.5 mm 2, unless otherwise stated in the technical data section of the product documentation. Before energising the equipment, the following should be checked: Voltage rating and polarity; CT circuit rating and integrity of connections; Protective fuse rating; Integrity of earth connection ( where applicable ) Equipment operating conditions The equipment should be operated within the specified electrical and environmental limits. Current transformer circuits Do not open the secondary circuit of a live CT since the high voltage produced may be lethal to personnel and could damage insulation. External resistors Where external resistors are fitted to relays, these may present a risk of electric shock or burns, if touched. Battery replacement Where internal batteries are fitted they should be replaced with the recommended type and be installed with the correct polarity, to avoid possible damage to the equipment. Insulation and dielectric strength testing Insulation testing may leave capacitors charged up to a hazardous voltage. At the end of each part of the test, the voltage should be gradually reduced to zero, to discharge capacitors, before the test leads are disconnected. Insertion of modules and pcb cards These must not be inserted into or withdrawn from equipment whilst it is energised, since this may result in damage. Fibre optic communication Where fibre optic communication devices are fitted, these should not be viewed directly. Optical power meters should be used to determine the operation or signal level of the device.

Page 4

Older Products Electrical adjustments Equipments which require direct physical adjustments to their operating mechanism to change current or voltage settings, should have the electrical power removed before making the change, to avoid any risk of electric shock. Mechanical adjustments The electrical power to the relay contacts should be removed before checking any mechanical settings, to avoid any risk of electric shock. Draw out case relays Removal of the cover on equipment incorporating electromechanical operating elements, may expose hazardous live parts such as relay contacts. Insertion and withdrawal of extender cards When using an extender card, this should not be inserted or withdrawn from the equipment whilst it is energised. This is to avoid possible shock or damage hazards. Hazardous live voltages may be accessible on the extender card. Insertion and withdrawal of heavy current test plugs When using a heavy current test plug, CT shorting links must be in place before insertion or removal, to avoid potentially lethal voltages.

Decommissioning and Disposal Decommissioning: The auxiliary supply circuit in the relay may include capacitors across the supply or to earth. To avoid electric shock or energy hazards, after completely isolating the supplies to the relay (both poles of any dc supply), the capacitors should be safely discharged via the external terminals prior to decommissioning. Disposal:

It is recommended that incineration and disposal to water courses is avoided. The product should be disposed of in a safe manner. Any products containing batteries should have them removed before disposal, taking precautions to avoid short circuits. Particular regulations within the country of operation, may apply to the disposal of lithium batteries.

Page 5

Technical Specifications Protective fuse rating The recommended maximum rating of the external protective fuse for this equipment is 16A, Red Spot type or equivalent, unless otherwise stated in the technical data section of the product documentation. Insulation class: IEC 61010-1: 1990/A2: Class I EN 61010-1: 1993/A2: Class I

1995 This equipment requires a protective (safety) earth 1995 connection to ensure user safety.

Installation Category (Overvoltage):

IEC 61010-1: 1990/A2: Category III EN 61010-1: 1993/A2: Category III

1995 Distribution level, fixed installation. Equipment in 1995 this category is qualification tested at 5kV peak, 1.2/50µs, 500Ω, 0.5J, between all supply circuits and earth and also between independent circuits.

Environment:

IEC 61010-1: 1990/A2: Pollution degree 2 EN 61010-1: 1993/A2: Pollution degree 2

1995 Compliance is demonstrated by reference to generic 1995 safety standards.

Product safety: 73/23/EEC

EN 61010-1: EN 60950:

Compliance with the European Commission Low Voltage Directive. 1993/A2: 1995 Compliance is demonstrated 1992/A11: 1997 by reference to generic safety standards.

Page 6

Types KCGG 122, 142, KCEG 112, 142, 152, 242 and KCEU 142, 242 Overcurrent and Directional Overcurrent Relays Service Manual

Chapter 1 Introduction

SERVICE MANUAL KCGG 122, 142, KCEG 112, 142, 152, 242, KCEU 142, 242 1. 2. 3. 4. 5.

INTRODUCTION USING THE MANUAL AN INTRODUCTION TO K RELAYS MODELS AVAILABLE AVAILABILITY OF MAIN FEATURES

R8551D Chapter 1 Contents

1 1 2 3 4

SERVICE MANUAL KCGG 122, 142, KCEG 112, 142, 152, 242, KCEU 142, 242 Section 1.

R8551D Chapter 1 Page 1 of 4

INTRODUCTION

The K Range of overcurrent and directional overcurrent relays has been rationalised and additional features have been added to the individual relays to widen their application. Some menu cell locations have changed to accommodate the new features and so setting files that have been generated for the series 1 relays to suit particular applications may need some small modification before they can be used with the new K Range series 2. However, the menu locations for measured values and other data that is accessed by SCADA equipment retain their original locations. Hence the changes should be transparent to most communication interfaces that may have been developed. Manual R8501 should be used for K Range series 1 relays. This manual details the menu, functions and logic for the K Range series 2 relays. Section 2.

USING THE MANUAL

This manual provides a description of the K Range series 2 overcurrent and directional overcurrent range of protection relays. It is intended to guide the user through application, installation, setting and commissioning of the relays. The manual has the following format: Chapter 1.

Introduction An introduction on how to use this manual and a general introduction to the relays covered by the manual.

Chapter 2.

Handling and installation Precautions to be taken when handling electronic equipment

Chapter 3.

Relay description A detailed description of features that are common to all K Range series 2 relays.

Chapter 4.

Application of protection functions An introduction to the applications of the relays and special features provided.

Chapter 5.

Measurements and records How to customise the measurements and use the recording features.

Chapter 6.

Serial communications Hints on using the serial communication feature.

Chapter 7.

Technical data Comprehensive details on the ratings, setting ranges and specifications etc.

Chapter 8.

Commissioning A guide to commissioning, problem solving and maintenance.

Appendix

Appendices include relay characteristic curves, logic diagrams, connection diagrams and commissioning test records.



AN INTRODUCTION TO K RELAYS

The K Range of protection relays brings numerical technology to the successful Midos range of protection relays. Fully compatible with the existing designs and sharing the same modular housing concept, the relays offer more comprehensive protection for demanding applications. Each relay includes an extensive range of control and data gathering functions to provide a completely integrated system of protection, control, instrumentation, data logging, fault, event and disturbance recording. The relays have a user-friendly 32 character liquid crystal display (LCD) with 4 push buttons which allow menu navigation and setting changes. Also, by utilising the simple 2-wire communication link, all of the relay functions can be read, reset and changed on demand from a local or remote personal computer (PC) loaded with the relevant software. With enhanced versatility, reduced maintenance requirements and low burdens, K Range relays provide a more advanced solution to power system protection. The K Range series 2 relays have new features that are additional to those found on series 1 relays. The additional functions include: Protection

thermal, underfrequency, broken conductor detection, rectifier protection and improved undervoltage

Measurement thermal ammeters, single phase W and VAR Logic

improved logic flexibility

Recording

additional methods of resetting the disturbance recorder, triggering the disturbance recorder from the logic inputs, thresholds on circuit breaker maintenance counter and contact arcing duty plus 5 full fault records.

KCGG relays provide overcurrent and earth fault protection for power distribution systems, industrial power systems and all other applications where overcurrent protection is required. The relays are used in applications where time graded overcurrent and earth fault protection is required. The earth fault protection provides suitable sensitivity for most systems where the earth fault current is limited. KCEG relays provide directional overcurrent and earth fault protection. The overcurrent elements can be selectively directionalised, making the relays a cost effective option where both directional and non-directional protection is required. The sensitivity of earth fault protection has been increased to cover most applications. The earth fault protection provides suitable sensitivity for most systems where the earth fault current is limited. KCEU relays provide directional overcurrent and sensitive wattmetric earth fault protection for systems which are earthed through a Petersen coil. Integral features in K Range relays include circuit breaker failure protection, back tripping, blocked overcurrent protection for feeders or busbars, cold load pick-up facilities, load shedding capabilities and two alternative groups of predetermined settings. The relays also have integral serial communication facilities via K-Bus.



MODELS AVAILABLE

The following list of models is covered by this manual KCGG 122

One phase overcurrent and earth fault relay

KCGG 142 01 Three phase overcurrent and earth fault relay KCGG 142 02 Three phase overcurrent and earth fault relay with reduced I/O KCEG 112

Directional earth fault

KCEG 142

Directional three phase overcurrent and directional earth fault relay

KCEG 152

Three phase overcurrent relay and directional earth fault relay

KCEG 242

Directional three phase overcurrent and directional earth fault relay

KCEU 142

Directional three phase overcurrent and wattmetric sensitive earth fault relay

KCEU 242

Directional three phase overcurrent and wattmetric sensitive earth fault relay

Note:

The 100 series of relays are powered by a DC/AC auxiliary supply. The 200 series of relays are dual powered, ie. powered by a DC/AC auxiliary supply or from the current transformer circuit in the absence of an auxiliary supply.

K Range series 2 relay

Equivalent K Range series 1 relays

KCGG 122

KCGG 110, KCGU 110

KCGG 142

KCGG 120, KCGG 130, KCGG 140, KCGU 140

KCEG 112

KCEG 110, KCEU 110

KCEG 142

KCEG 130, KCEG 140, KCEU 140

KCEG 152

KCEG 150, KCEU 150, KCEG 160, KCEU 160

KCEG 242

KCGG/KCEG 210, KCGG/KCEG 230, KCGG/KCEG 250, KCGG/KCGU 240, KCEG/KCEU 240

KCEU 142

KCEU 141

KCEU 242

KCEU 241

Table of equivalence between K Range series 1 and series 2 relays



AVAILABILITY OF MAIN FEATURES

The following table lists the features that vary between models Feature

KCGG KCGG KCGG KCEG KCEG KCEG KCEG KCEU KCEU 122 142 01 142 02* 112 142 152 242 142 242

Protection

Overcurrent

q

q

q

Earth fault

q

q

q

q

Directional overcurrent

q

q

q

q

q

q

q

q

q

q

q

q

q

q

q

q

q

q

q

q

q

q

q

Directional earth fault

q

Underfrequency

q

q

Undervoltage Thermal overload

q

q

q

q

q

q

q

q q

q

q

q

q

Wattmetric Measurement

Frequency Current

q

q

q

q

q

q

q

q

q

q

q

q

q

q

q

q

q

q

Voltage

q

q

Single phase power

q

q

Three phase power

q

q

q

q

Thermal ammeter(s)

q

q

q

q

q

q

q

q

Thermal demand(s)

q

q

q

q

q

q

q

q

Thermal state

q

q

q

q

q

q

q

q

CB operations

q

q

q

q

q

q

q

q

CB contact duty

q

q

q

q

q

q

q

q

Logic inputs

3

8

3

3

8

8

8

8

8

Output relays

4

8

4

4

8

8

8

8

8

q

Programmable Inputs/Outputs

* The fully functionality KCGG 142 01 relay is also available as a KCGG 142 02 with reduced I/O.


Chapter 2 Handling and Installation

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242 1. 1.1 1.2 2. 3. 4. 5.

GENERAL CONSIDERATIONS Receipt of relays Electrostatic discharge (ESD) HANDLING OF ELECTRONIC EQUIPMENT RELAY MOUNTING UNPACKING STORAGE

R8551C Chapter 2 Contents

1 1 1 1 2 2 3


R8551C Chapter 2 Page 1 of 3

Section 1. GENERAL CONSIDERATIONS 1.1

Receipt of relays Protective relays, although generally of robust construction, require careful treatment prior to installation on site. Upon receipt, relays should be examined immediately to ensure no damage has been sustained in transit. If damage has been sustained during transit a claim should be made to the transport contractor and ALSTOM T&D Protection & Control Ltd should be promptly notified. Relays that are supplied unmounted and not intended for immediate installation should be returned to their protective polythene bags.

1.2

Electrostatic discharge (ESD) The relays use components that are sensitive to electrostatic discharges. The electronic circuits are well protected by the metal case and the internal module should not be withdrawn unnecessarily. When handling the module outside its case, care should be taken to avoid contact with components and electrical connections. If removed from the case for storage, the module should be placed in an electrically conducting antistatic bag. There are no setting adjustments within the module and it is advised that it is not unnecessarily disassembled. Although the printed circuit boards are plugged together, the connectors are a manufacturing aid and not intended for frequent dismantling; in fact considerable effort may be required to separate them. Touching the printed circuit board should be avoided, since complementary metal oxide semiconductors (CMOS) are used, which can be damaged by static electricity discharged from the body.

Section 2. HANDLING OF ELECTRONIC EQUIPMENT A person’s normal movements can easily generate electrostatic potentials of several thousand volts. Discharge of these voltages into semiconductor devices when handling electronic circuits can cause serious damage, which often may not be immediately apparent but the reliability of the circuit will have been reduced. The electronic circuits are completely safe from electrostatic discharge when housed in the case. Do not expose them to risk of damage by withdrawing modules unnecessarily. Each module incorporates the highest practicable protection for its semiconductor devices. However, if it becomes necessary to withdraw a module, the folowing precautions should be taken to preserve the high reliability and long life for which the equipment has been designed and manufactured. 1. Before removing a module, ensure that you are at the same electrostatic potential as the equipment by touching the case. 2. Handle the module by its frontplate, frame or edges of the printed circuit board. Avoid touching the electronic componenets, printed circuit track or connectors. 3. Do not pass the module to another person without first ensuring you are both at the same electrostatic potential. Shaking hands achieves equipotential.



4. Place the module on an antistatic surface, or on a conducting surface which is at the same potential as yourself. 5. Store or transport the module in a conductive bag. If you are making measurements on the internal electronic circuitry of an equipment in service, it is preferable that you are earthed to the case with a conductive wrist strap. Wrist straps should have a resistance to ground between 500ký – 10Mý. If a wrist strap is not available you should maintain regular contact with the case to prevent a build-up of static. Instrumentation which may be used for making measurements should be earthed to the case whenever possible. More information on safe working procedures for all electronic equipment can be found in BS5783 and IEC 60147-OF. It is strongly recommended that detailed investigations on electronic circuitry or modification work should be carried out in a special handling area such as described in the above-mentioned BS and IEC documents.

Section 3. RELAY MOUNTING Relays are dispatched either individually or as part of a panel/rack assembly. If loose relays are to be assembled into a scheme, then construction details can be found in Publication R7012. If an MMLG test block is to be included it should be positioned at the right-hand side of the assembly (viewed from the front). Modules should remain protected by their metal case during assembly into a panel or rack. The design of the relay is such that the fixing holes are accessible without removal of the cover. For individually mounted relays an outline diagram is normally supplied showing the panel cut-outs and hole centres. These dimensions will also be found in Publication R6551.

Section 4. UNPACKING Care must be taken when unpacking and installing the relays so that none of the parts is damaged or the settings altered. Relays must only be handled by skilled persons. The installation should be clean, dry and reasonably free from dust and excessive vibration. The site should be well lit to facilitate inspection. Relays that have been removed from their cases should not be left in situations where they are exposed to dust or damp. This particularly applies to installations which are being carried out at the same time as construction work.



Section 5. STORAGE If relays are not to be installed immediately upon receipt they should be stored in a place free from dust and moisture in their original cartons. Where de-humidifier bags have been included in the packing they should be retained. The action of the de-humidifier crystals will be impaired if the bag has been exposed to ambient conditions and may be restored by gently heating the bag for about an hour, prior to replacing it in the carton. Dust which collects on a carton may, on subsequent unpacking, find its way into the relay; in damp conditions the carton and packing may become impregnated with moisture and the de-humifier will lose its efficiency. Storage temperature –25°C to +70°C.


Chapter 3 Relay Description

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242 1. 2. 2.1 2.2 2.3 2.4 2.5 3. 3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 3.9 3.10 3.11 3.12 3.13 3.14 3.15 3.16 3.17 4. 4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 4.9 4.10 4.11 4.12 4.13 4.14 4.15 4.16

RELAY DESCRIPTION USER INTERFACE Frontplate layout LED indications Keypad Liquid crystal display Flag display format MENU SYSTEM Default display Accessing the menu Menu contents Menu columns System data Fault records Measurements 1 Measurements 2 Measurements 3 Earth fault 1 Phase fault 1 Earth fault 2 Phase fault 2 Logic Input masks Relay masks Recorder CHANGING TEXT AND SETTINGS Quick guide to menu controls To enter setting mode To escape from the setting mode To accept the new setting Password protection Entering passwords Changing passwords Restoration of password protection Entering text Changing function links Changing setting values Setting communication address Setting input masks Setting output masks Resetting values and records Resetting trip LED indication


1 2 2 3 3 3 3 5 5 5 6 6 7 8 8 8 9 9 10 11 12 13 14 14 15 17 17 18 18 18 19 19 19 20 20 20 20 21 21 21 21 22

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242 5. 5.1 5.2 5.3 5.4 5.5 5.6 5.7 6.

EXTERNAL CONNECTIONS Auxiliary supply Dual powered relays Logic control inputs Analogue inputs Output relays Ouput relay minimum dwell time Setting the relay with a PC or laptop ALARM FLAGS

Figure 1. Figure 2.

Frontplate layout Flag display format


22 23 23 23 24 25 25 25 25 2 4



Section 1. RELAY DESCRIPTION The KCGG, KCEG and KCEU relays use numerical techniques to derive protection and control functions. They can have up to eight multiplexed analogue inputs, sampled eight times per power frequency cycle. The Fourier derived power frequency component returns the rms value of the measured quantity. To ensure optimum performance, frequency tracking is used. The channel that is tracked is chosen on a priority basis, Va, Vb, Vc, Ia, Ib, Ic. Frequency tracking is not employed on the residual voltage, or current to ensure the maximum harmonic rejection. In the absence of a signal to frequency track, the sampling frequency defaults to the rated frequency of the power system. Up to eight output relays can be programmed to respond to any of the protection or control functions and up to eight logic inputs can be allocated to control functions. The logic inputs are filtered to ensure that induced AC current in the external wiring to these inputs does not cause an incorrect response. Software links further enable the user to customise the product for their own particular applications. They select/interconnect the various protection and control elements and replace the interconnections that were previously used between the cases of relays that provided discrete protection or control functions. The relays are powered from either a DC or an AC auxiliary supply which is transformed by a wide ranging DC/DC converter within the relay. This provides the electronic circuits with regulated and galvanically isolated supply rails. The power supply also provides a regulated and isolated field voltage to energise the logic inputs. The dual powered version of the relay draws its energising supply from the current transformers in the absence of an auxiliary voltage supply. This makes it suitable for application where the auxiliary supply is not reliable or not available. They can be used in shunt trip, capacitor discharge and AC series trip arrangements. An interface on the front of the relay allows the user to navigate through the menu to access data, change settings and reset flags, etc. As an alternative the relays can be connected to a computer via their serial communication ports and the menu accessed on-line. This provides a more friendly and intuitive method of setting the relay, as it allows a whole column of data to be displayed at one time instead of just a single menu cell. Computer programs are also available that enable setting files to be generated off-line and these files can then be downloaded to the relay via the serial port. In addition to protection and control functions the relays can display all the values that it measures and many additional ones that it calculates. They also store useful time stamped data for post fault analysis in fault records, event records and disturbance records. This data is available via a serial communication port for access locally and/or remotely with a computer. The fault records, event records and disturbance records can be extracted automatically via the serial port and values can be polled periodically to determine trends. Remote control actions can also be made and to this end many K Range relays have been integrated into SCADA systems. K Range relays provide the user with the flexibility to customise the relay for their particular applications. They provide many additional features that would be expensive to produce on an individual basis and, when the low installation costs are taken into account, it will be seen to provide an economic solution for protection and control.



Section 2. USER INTERFACE The front plate of the relay provides a man machine interface providing the user with a means of entering settings to the relay displaying measured values, fault records and alarms. The series 2 relays have additional graphics to assist the user. The area in which the fault flags are displayed is divided up to denote the area associated with each phase and there is a marked position for the appropriate phase colours to be marked and for labels to be affixed to denote the use of the three overcurrent stages and the three auxiliary timers. 2.1

Frontplate layout Model number

Relay types

KCGG14200102125 No P967701

KCGG142

Liquid crystal display

Serial number

SETTING GROUP FAULT No

A

B

F n _ 2 G2 A _ _ * B _ _ * V < BT N AU X 2 C * F E D C B A 9 8 7 6 5 4 3 2 1 0 C

AUX TIMER

Flag identifiers

STAGE 1 STAGE 2

AUX 1 AUX 2 AUX 3

Digit identifiers

* Ð* ÐÐ*

STAGE 3

ALARM

TRIP HEALTHY

Entry keys

LED indicators F

+

-

0

Ratings In 1 A V 110/125 V Vn 110 V

50/60

Hz

Figure 1: Frontplate layout

The frontplate of the relay carries a liquid crystal display LCD on which data such as settings and measured values can be viewed. The data is accessed through a menu system. The four keys [F]; [+]; [–] and [0] are used to move around the menu, select the data to be accessed and enter settings. Three light emitting diodes (LEDs) indicate alarm, healthy and trip conditions. A label at the top corner identifies the relay by both its model number and serial number. This information uniquely specifies the product and is required when making any enquiry to the factory about a particular relay. In addition there is a rating label in the bottom corner which gives details of the auxiliary voltage, reference voltage (directional relays only) and current ratings. Two handles, one at the top and one at the bottom of the frontplate, will assist in removing the module from the case.

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242 2.2


LED indications The three LEDs provide the following functions:

2.3

GREEN LED

Indicates the relay is powered up and running. In most cases it follows the watchdog relay but dual powered relays are the exception because the watchdog does not operate for loss of auxiliary supply. Such a condition would be considered a normal operational condition when the relays are energised from line current transformers alone.

YELLOW LED

Indicates alarm conditions that have been detected by the relay during its self checking routine. The alarm lamp flashes when the password is entered (password inhibition temporarily overridden).

RED LED

Indicates a trip that has been issued by the relay. This may be a protection trip or result from a remote trip command; this can be determined by viewing the trip flags.

Keypad The four keys perform the following functions: [F]

function select/digit select key/next column

[+]

put in setting mode/increment value/accept key/previous column

[–]

put in setting mode/decrement value/reject key/next column

[0]

reset/escape/change default display key

Note: Only the [F] and [0] keys are accessible when the relay cover is in place. 2.4

Liquid crystal display The liquid crystal display has two lines each of sixteen characters. A back-light is activated when any key on the frontplate is momentarily pressed and will remain lit until ten minutes after the last key press. This enables the display to be read in all conditions of ambient lighting. The numbers printed on the frontplate just below the display, identify the individual digits that are displayed for some of the settings, ie. function links, relay masks etc. Additional text around the display is used to define the areas in which the various parts of the fault information will be found.

2.5

Flag display format Now that there are five full fault records the top four left-hand digits no longer display “Fn”, “Fn-1”, . . . “Fn-4” to denote the last and previous fault flags. Instead they now display “Fn” to indicate latched fault flags and “Fnow” to indicate unlatched flags (when cell 0023 is selected from the System Data column). The next two digits indicate the setting group that was in operation during the fault when “Fn” is displayed eg. “G1” indicates setting group 1 and “G2” indicates setting group 2. When “Fnow” is displayed then the setting group is that which is currently active. The next most important areas are the four marked by a circle. These circles are over printed with a letter (A, B or C) to indicate the phase, or a symbol to represent



an earth fault. Alternatively a coloured disc may be stuck over the circles to indicate the phases by colour eg. red, yellow and blue. There are four characters on the display associated with each of these four areas to flag operation of the start and operation of the three overcurrent stages for that phase.

SETTING GROUP FAULT No

A

B

F n _ 2G2 A _ _ * B _ _ * V < BT N AU X 2 C * F E D C B A 9 8 7 6 5 4 3 2 1 0 AUX TIMER STAGE 1 STAGE 2

AUX 1 AUX 2 AUX 3

STAGE 3

C

* Ð* Ð Ð*

ALARM

TRIP HEALTHY

Figure 2: Flag display format

Consider the four digits above the circle marked |©|. If the relay trips during a fault involving phase C then the first digit will be the letter C to indicate the current exceeded the I> threshold and that the protection has started. The next three characters are flags for each of the three overcurrent stages (t>, t>>, t>>>) associated with that phase (phase C in this example) and an asterisk (*) will be displayed for the stage or stages that have operated. Thus: C

would indicate that a current above the I> setting had been detected by the phase C element during the fault (START condition).

C*

would indicate the first overcurrent stage (t>) had operated

C_*

would indicate the second stage (t>>) had timed out

C__*

would indicate t>>> had timed out – third overcurrent stage

C*_*

would indicate that both t> and t>>> had timed out

Flag information is similarly provided for the other two phases and for earth faults. The six digits at the left-hand side of the display on the bottom line identify the auxiliary functions AUX1, AUX2, AUX3 as AUX123. Two printed panels below the display may be used to indicate the function of each of the three auxiliary functions and those of the three main overcurrent functions respectively. The appropriate preprinted labels can be affixed in these two areas.



The two characters at the extreme right-hand end of the top line of the display will indicate V< when the undervoltage element has operated. Operation of the breaker failure protection is indicated by the letter ‘B’ and operation of the thermal element by the letter “T” immediately below the V<. For indication of a local/ remote trip via relay RLY7 the ‘B’ is replaced by an ‘R’. Where ‘B’ and ‘R’ are both valid, ‘B’ is given priority.

Section 3. MENU SYSTEM Data within the relays is accessed via a menu table. The table is comprised of cells arranged in rows and columns, like a spreadsheet. A cell may contain text values limits or functions. The first cell in a column, the column heading, contains text identifying the data grouped under it in that column. 3.1

Default display The selected default display will normally show on the LCD and a momentary press of the function key [F] will change the display to the heading for the first column, SYSTEM DATA. Further momentary presses of the [F] key will step down the column, row by row, so that data may be read. If at any time the [F] key is pressed and held for one second the cursor will be moved to the top of the next column and the heading for that column will be displayed. Further momentary presses of the [F] key will then move down the new column, row by row. A new feature is that pressing the [F] and [0] keys together and holding for one second can be used to step back up the menu column. A short press of the [0] key will switch on the back light for the LCD without changing the display in any way. In this way the full menu may be scanned with just the [F] and [0] keys that are accessible with the relay cover in place, and reset actions can be effected. Following a protection trip red trip LED will be lit. The display will change automatically from the default display to that of the fault flags for the last fault. Whilst the fault flags are displayed the trip LED can be reset by holding down the [0] for at least one second. The trip LED will be reset and the display will change to the default display that was last selected. The flag information will not be lost by this action, it can still be accessed under FAULT RECORDS. The display will not default to the flag information if the user interface is in use at the time. The default display will return 15 minutes after the last key press, or it can be selected more quickly by moving to any column heading and then pressing the [0] key for 1 second. The selected default display will appear unless there has been a fault when the fault flags will be displayed. It is possible to step through the available default displays by momentary presses of the reset key [0].

3.2

Accessing the menu The only settings which can be changed with the cover in place are those that can be reset either to zero or some preset value. To change any other settings the cover must be removed from the relay to gain access to the [+] and [–] keys that are used to increment or decrement a value. When a column heading is displayed the [–] key will change the display to the next column and the [+] key will change the display to the previous column, giving a faster selection. When a cell that can be changed is displayed the action of pressing either the [+] or [–] keys will put the relay in setting mode (indicated by a flashing cursor in the display). To escape from the setting mode without making any change the [0] key



should be depressed for one second. Section 4 gives instructions for changing the various types of settings. Password protection is provided for the configuration settings of the relay because an accidental change could seriously affect the ability of the relay to perform its intended functions. Configuration settings include the selection of time curves, function links, CT and VT ratios, opto-input and relay output allocation. Individual protection settings are protected from change when the relay cover is in place. 3.3

Menu contents Related data and settings are grouped in separate columns of the menu. Each column has a text heading (in capital letters) that identifies the data contained in that column. Each cell may contain text, values, limits and/or a function. The cells are referenced by the column number/row number. For example 0201 is column 02, row 01. When a cell is displayed the four characters at the top left hand corner of the LCD indicate the column number and row number in the menu table. The full menu is given in the following tables, but not all the items listed will be available in a particular relay. For example, a single pole earth fault relay would not display any phase fault settings and a non-directional relay would not display any settings associated with the directional feature. Those cells that do not provide any useful purpose are not made available in the factory configuration. Certain settings will disappear from the menu when the user de-selects them; the alternative setting group is a typical example. If group 2 settings have not been enabled then the menu columns EARTH FLT 2 and PHASE FLT 2 will be hidden and make them visible, the system data link SD4 must be set to ‘1’. This note is included at this time to explain why some of the items listed below may not appear in the menu for a relay that is being compared with the full list.

3.4

Menu columns The menu tables shown below are for KCEG directional overcurrent and earth fault protection relays, unless otherwise stated. The directional elements shown in the menu tables are not available in KCGG relays. Column Number 00

Heading

Description

SYSTEM DATA

Settings and data for the system - relay and serial communications

01

FLT RECORDS

Fault records for the last five faults

02 03

MEASURE 1 MEASURE 2

Directly measured quantities (V & I etc.) Calculated quantities (W & VAR etc.)

04

MEASURE 3

Calculated (additional)

05 06

EARTH FLT 1 PHASE FLT 1

Earth fault protection settings – group 1 Phase fault protection settings – group 1

07 08

EARTH FLT 2 PHASE FLT 2

Earth fault protection settings – group 2 Phase fault protection settings – group 2

09

LOGIC

Settings for miscellaneous functions used in the logic

0A

INPUT MASKS

User assigned allocation of logic input



0B

RELAY MASKS

User assigned allocation of output relays

0C

RECORDER

Settings for the disturbance recorder

The menu cells that are read only are marked Cells that can be set are marked Cells that can be reset are marked Cells that are password protected are marked

3.5

[READ]. [SET]. [RESET]. [PWP].

System data Display 0000 SYSTEM DATA 0002 Password

Status READ PWP

0003 SD Links

PWP

0 2 3 4

Rem ChgStg Rem CB Ctrl Rem ChgGrp En Grp2

5

Auto Flag

6

Auto Rec

7

Log Evts 8

8

Alt Rec Rst

0004 0005 0006 0008

Description Plant Model Serial No.

PWP PWP READ READ

0009 Freq

SET

000A Comms Level

READ

000B Rly Address 000C Plnt Status

SET READ

000D 000E 000F 0010 0011 0020 0021 0022 0 1 2 3

READ READ READ SET READ READ READ READ READ READ READ READ

Ctrl Status Grp now LS Stage CB Control Software Log Status Rly Status Alarms Uncfg Uncalib Setting No Service

Description Column heading Password that must be entered before certain settings may be changed Function links that enable the user to enable (activate) the options required 1 = enable remote setting changes 1 = enable remote control of circuit breaker 1 = enable remote change of setting group 1 = enable group 2 settings to be used and displayed 1 = enable flags to be reset automatically on load restoration 1 = enable disturbance recorder to reset on load restoration 1 = enable logic inputs and output relay status to be stored in event records 1 = enable alternative reset method for disturbance recorder Product description – user programmable text Plant reference – user programmable text Model number that defines the product Serial number – unique number identifying the particular product Default sampling frequency – must be set to power system frequency (not available on KCEU relays) Indicates the Courier communication level supported by the product Communication address (1 to 255) Binary word used to indicate the status of circuit breakers and isolators Binary word used to indicate the status of control data Indicates the active setting group Indicates the last received load shedding command Indicates the status of the circuit breaker control Software reference for the product Indicates the current status of all the logic inputs Indicates the current status of the output relay drives Indicates the current state of internal alarms Error in factory configuration settings Operating in uncalibrated state Error detected in stored settings Protection out-of-service and not functioning

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242 4 5 6 0023

3.6

3.7

No Samples No Fourier Test Wdog FnowG1


READ READ SET READ

No A/D samples but still in service Fourier is not being performed Test watchdog by setting this bit to “1” Indicates the current status of the fault flags (These flags are not latched)

Display 0100 FLT RECORDS 0101 Fault No 1

Status READ SET

0102 Fn G1

READ

0103

Ia

READ

0104

Ib

READ

0105

Ic

READ

0106

Io

READ

0107 0108 0109 010A

Vab Vbc Vca Vo

READ READ READ READ

010B CB Trip Time 0110 Clear = O

READ RESET

Description Column heading Number of fault record displayed – may be selected (Fn; Fn -1; Fn -2; . . . Fn -5) Flags (latched) indicating the functions that operated during the fault Highest value of current measured in phase A during the fault Highest value of current measured in phase B during the fault Highest value of current measured in phase C during the fault Highest value of residual current measured during the fault Value of Vab during the fault Value of Vbc during the fault Value of Vca during the fault Highest value of residual voltage measured during the fault Circuit breaker trip time Press [0] key to clear all fault records when this cell is displayed

Fault records

Measurements 1 Display 0200 MEASURE 1 0201 Ia 0202 Ib 0203 Ic 0204 Io 0205 Vab 0206 Vbc 0207 Vca 0208 Va

Status READ READ READ READ READ READ READ READ READ

0209 Vb

READ

020A Vc

READ

020B Vo 020C F

READ READ

Description Column heading Measured current in phase A Measured current in phase B Measured current in phase C Measured residual current Measured line voltage Vab Measured line voltage Vbc Measured line voltage Vca Measured phase voltage Va (not available on KCEU relays) Measured phase voltage Vb (not available on KCEU relays) Measured phase voltage Vc (not available on KCEU relays) Measured residual voltage Vo Measured power system frequency F


3.9

3.10


Measurements 2 Display 0300 MEASURE 2 0301 3W 0302 3VA 0303 3VAr 0304 Imax

Status READ READ READ READ READ

0309 Wa

READ

030A Wb

READ

030B Wc

READ

030C PowerFactor 030D VARa

READ READ

030E VARb

READ

030F

VARc

READ

0310 0311 0312 0313 031E

Sum (ops) CBdutyA CBdutyB CBdutyC Power mode

PWP PWP PWP PWP PWP

Description Column heading Three phase active power Three phase apparent power Three phase reactive power Highest of the three phase currents measured – not a peak demand value Active power in phase A (not available on KCEU relays) Active power in phase B (not available on KCEU relays) Active power in phase C (not available on KCEU relays) Power factor – three phase Reactive power in phase A (not available on KCEU relays) Reactive power in phase B (not available on KCEU relays) Reactive power in phase C (not available on KCEU relays) Number of circuit breaker operations Sum of I , or I2 broken by phase A of circuit breaker Sum of I , or I2 broken by phase B of circuit breaker Sum of I , or I2 broken by phase C of circuit breaker Sets the convention used for signing the direction of measured power flow

Measurements 3 Display 0400 MEASURE 3 0404 IthA 0405 IthB 0406 IthC 0407 Thermal 040A Pk IthA

Status READ READ READ READ PWP PWP

040B Pk IthB

PWP

040C Pk IthC

PWP

Description Column heading Thermal ammeter reading in phase A Thermal ammeter reading in phase B Thermal ammeter reading in phase C Thermal state (%) Peak thermal ammeter reading in phase A – demand value Peak thermal ammeter reading in phase B – demand value Peak thermal ammeter reading in phase C – demand value

Earth fault 1 Display 0500 EARTH FLT1 0501 EF Links

1 2 3 4 5

En Io>> EN Io>>> Drn to> Drn to>> Drn to>>>

READ PWP

Status Description Column heading Software links that are used to select the available optional earth fault functions 1 = enable earth fault stage 2 1 = enable earth fault stage 3 1 = directionalise earth fault stage 1 1 = directionalise earth fault stage 2 1 = directionalise earth fault stage 3

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242 6

3.11


Io>>NoPeak

E Rev Io>>> 0502 CT Ratio

PWP

0503 VT Ratio

PWP

0504 Curve

PWP

0505

SET

Io>

0506 to>/TMS

SET

0507 to>/DT

SET

0508 toRESET

SET

0509 Io>> 050A to>> 050B Io>>> 050C to>>> 050D Char Angle

SET SET SET SET SET

050E Io< 050F Vop>

SET SET

0510 Po>

SET

1 = no peak measurement for stage 2 earth faults (KCGG only) 1 = reverse direction of third earth fault stage (Io>>>) Overall ratio of the line or neutral CT feeding the earth fault protection elements Overall ratio of the voltage transformer feeding the relay Selected characteristic from the definite time or 10 inverse time options Current setting for start output and first earth fault stage Time multiplier setting that will be used with a selected inverse time curve Time delay that will be effective when the definite time characteristic is selected Hold time for which the current must remain below Io> before the timer resets to zero Current setting for second earth fault stage Time delay for second earth fault stage Current setting for third earth fault stage Time delay for third earth fault stage Characteristic angle setting for earth fault directional element Setting for earth fault undercurrent element Setting for minimum polarising voltage below which the directional element is blocked Wattmetric power threshold (only available on KCEU relays)

Phase fault 1 Display 0600 PHASE FLT 1 0601 PF Links

0 1 2 3 4 5 6

En Therm En I>> En I>>> Drn t> Drn t>> Drn t>>> I>> NoPeak

7

I>>>

8

CB blk V<

9

V< any = 1

A

V< P-N = 1

B

SynPol = 3.2

C

Brkn Cond

= 2/3

Status READ PWP

Description Column heading Software links that are used to select the available optional phase fault functions 1 = enable thermal element 1 = enable stage 2 overcurrent 1 = enable stage 3 overcurrent 1 = directionalise stage 1 overcurrent 1 = directionalise stage 2 overcurrent 1 = directionalise stage 3 overcurrent 1 = No peak measurement for stage 2 overcurrent (KCGG only) 1 = 2 out of 3 phase elements to operate for t>>> to give an output 1 = undervoltage blocked when circuit breaker is open 1 = output for any phase undervoltage; 0 = output for all phases undervoltage 1 = undervoltage responds to phase voltage; 0 = undervoltage responds to line voltage (not available on KCEU relays) 1 = synchronous polarising extended to 3.2s; 0 = 0.32s 1 = enables broken conductor logic

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242 D

3.12


En F<

E Rev I>>> F All 2/3 0602 CT Ratio

PWP

0603 VT Ratio

PWP

0604 Curve

PWP

0605

SET

I>

0606 t>/TMS

SET

0607 t>/DT

SET

0608 tRESET

SET

0609 I>> 060A t>> 060B I>>> 060C t>>> 060D Char Angle

SET SET SET SET SET

060E I< 060F V< 0610 tV< 0611 F<

SET SET SET SET

0612 th> Alarm 0613 Ith> Trip 0614 TC

SET SET SET

1 = enable under frequency element to initiate tAUX1 (not available on KCEU relays) 1 = reverse direction of third overcurrent stage 1 = 2/3 logic applied to all phase outputs Overall ratio of the line CT feeding the phase fault protection elements Overall ratio of the voltage transformer feeding the relay Selected characteristic from the definite time or 10 inverse time options Current setting for start output and first overcurrent stage Time multiplier setting that will be used with a selected inverse time curve Time delay that will be effective when the definite time characteristic is selected Hold time for which the current must remain below I> before the timer resets to zero Current setting for second overcurrent stage Time delay for second overcurrent stage Current setting for third overcurrent stage Time delay for third overcurrent stage Characteristic angle setting for overcurrent directional element Setting for phase fault undercurrent element Setting for undervoltage element Definite time delay for undervoltage feature Setting for underfrequency (not available on KCEU relays) Thermal alarm level (%) Thermal current rating (trip level = 100%) Setting for thermal time constant

Earth fault 2 Display 0700 EARTH FLT 2 0701 EF Links

1 2 3 4 5 6

Status READ PWP

En Io>> En Io>>> Drn to> Drn to>> Drn to>>> Io>> NoPeak

E Rev Io>>> 0702 CT Ratio

PWP

0703 VT Ratio

PWP

0704 Curve

PWP

0705

SET

Io>

Description Column heading Software links that are used to select the available optional earth fault functions 1 = enable earth fault stage 2 1 = enable earth fault stage 3 1 = directionalise earth fault stage 1 1 = directionalsise earth fault stage 2 1 = directionalise earth fault stage 3 1 = no peak measurement for stage 2 earth faults (KCGG only) 1 = reverse direction of third earth fault stage (Io>>>) Overall ratio of the line or neutral CT feeding the earth fault protection elements Overall ratio of the voltage transformer feeding the relay Selected characteristic from the definite time or 10 inverse time options Current setting for start output and first earth fault stage


3.13


0706 to>/TMS

SET

0707 to>/DT

SET

0708 toRESET

SET

0709 Io>> 070A to>> 070B Io>>> 070C to>>> 070D Char Angle

SET SET SET SET SET

070E Io< 070F Vop>

SET SET

0710 Po>

SET

Time multiplier setting that will be used with a selected inverse time curve Time delay that will be effective when the definite time characteristic is selected Hold time for which the current must remain below Io> before the timer resets to zero Current setting for second earth fault stage Time delay for second earth fault stage Current setting for third earth fault stage Time delay for third earth fault stage Characteristic angle setting for earth fault directional element Setting for earth fault undercurrent element Setting for minimum polarising voltage below which the directional element is blocked Wattmetric power threshold (only available on KCEU relays)

Phase fault 2 Display 0800 PHASE FLT 2 0801 PF Links

0 1 2 3 4 5 6

En Therm En I>> En I>>> Drn t> Drn t>> Drn t>>> I>> NoPeak

7

I>>>

8

CB blk V<

9

V< any = 1

A

V< P-N = 1

B

SynPol = 3.2

C D

Brkn Cond EN F<

Status READ PWP

= 2/3

E Rev I>>> F All 2/3 0802 CT Ratio

PWP

0803 VT Ratio

PWP

0804 Curve

PWP

0805

SET

I>

Description Column heading Software links that are used to select the available optional phase fault functions 1 = enable thermal element 1 = enable stage 2 overcurrent 1 = enable stage 3 overcurrent 1 = directionalise stage 1 overcurrent 1 = directionalise stage 2 overcurrent 1 = directionalise stage 3 overcurrent 1 = No peak measurement for stage 2 overcurrent (KCGG only) 1 = 2 out of 3 phase elements to operate for t>>> to give an output 1 = undervoltage blocked when circuit breaker is open 1 = output for any phase undervoltage; 0 = output for all phases undervoltage 1 = undervoltage responds to phase voltage; 0 = undervoltage responds to line voltage 1 = synchronous polarising extended to 3.2s; 0 = 0.32s 1 = enables broken conductor logic 1 = enable under frequency element to initiate tAUX1 (not available on KCEU relays) 1 = reverse direction of third overcurrent stage 1 = 2/3 logic applied to all phase outputs Overall ratio of the line CT feeding the phase fault protection elements Overall ratio of the voltage transformer feeding the relay Selected characteristic from the definite time or 10 inverse time options Current setting for start output and first overcurrent stage


3.14


0806 t>/TMS

SET

0807 t>/DT

SET

0808 tRESET

SET

0809 I>> 080A t>> 080B I>>> 080C t>>> 080D Char Angle

SET SET SET SET SET

080E I< 080F V< 0810 tV< 0811 F<

SET SET SET SET

0812 th>Alarm 0813 Ith>Trip 0814 TC

SET SET SET

Time multiplier setting that will be used with a selected inverse time curve Time delay that will be effective when the definite time characteristic is selected Hold time for which the current must remain below I> before the timer resets to zero Current setting for second overcurrent stage Time delay for second overcurrent stage Current setting for third overcurrent stage Time delay for third overcurrent stage Characteristic angle seting for overcurrent directional element Setting for phase fault undercurrent element Setting for undervoltage element Definite time delay for undervoltage feature Setting for underfrequency (not available on KCEU relays) Thermal alarm level (%) Thermal current rating (trip level = 100%) Setting for thermal time constant

Logic Display 0900 LOGIC 0901 LOG Links

0

CB Rec

1

CB1*I = 0

2

BF blk strt

3

tAUX2 = I<

4

tAUX2=/Io<

5 6

tAUX3 Grp2 tAUX2-tAUX3

7 8 9

Latch Strt Hold Grp2 Rst CBclose

A B

Log Rly7 tAUX3=DDO

0902 0903 0904 0905 0906 0907 0908

tBF tAUX1 tAUX2 tAUX3 tTRIP tCLOSE CB ops>

Status READ PWP

SET SET SET SET SET SET SET

Description Column heading Software links that are used to select the available optional logic functions 1 = enable CB operations and contact duty registers to be incremented 1 = CB contact proportional to I; 0 = CB contact duty proportional to I2 1 = enables the start outputs to be reset when breaker failure protection operates 1 = tAUX2 initiated by undercurrent in all three phases 1 = tAUX2 initiated when the earth fault current exceeds the Io< setting 1 = tAUX3 selects setting grp2 1 = enables the pick up of tAUX3 to be delayed by tAUX2 1 = start latches fault flags and generate fault record 1 = selects and holds the grp2 settings operational 1 = enables a circuit breaker trip to reset the close pulse timer 1 = enable relay 7 to initiate fault records 1 = tAUX3 is delayed on drop-off 0 = tAUX3 is delayed on pick-up Breaker failure protection time delay setting Auxiliary timer 1 setting Auxiliary timer 2 setting Auxiliary timer 3 setting Trip pulse time setting Close pulse time setting Alarm 1 setting for excessive circuit breaker operations


3.15

3.16


0909 CB duty>

SET

090F 0 1 2 3 4

Display Manufact Descript Plant Thermal IthA B C

SET

5

Ia Ib I c

6

Ia Io

7

kW kVAr

Vab Vo

Alarm 1 setting for excessive circuit breaker contact duty Default display that is selected on power-up Manufacturer’s name Description of product Plant reference Thermal State (%) Thermal ammeter readings for each of the three phases Instantaneous reading of phase currents (prospective value of thermal ammeter) Line current and voltage plus residual current and voltage Active and reactive three phase power

Input masks Display 0A00 INPUT MASKS 0A01 Blk to> 0A02 Blk to>>

Status READ PWP PWP

0A03 Blk to>>>

PWP

0A04 Blk t> 0A05 Blk t>>

PWP PWP

0A06 Blk t>>>

PWP

0A07 L Trip

PWP

0A08 L Close

PWP

0A09 Ext Trip

PWP

0A0A 0A0B 0A0C 0A0D

Aux 1 Aux 2 Aux 3 Set Grp 2

PWP PWP PWP PWP

0A0E CB Closed

PWP

0A0F CB Open 0A10 Bus2

PWP PWP

0A11 Reset Ith

PWP

Description Column heading Logic input to block first stage earth fault timer to> Logic input to block second stage earth fault timer to>> Logic input to block third stage earth fault timer to>>> Logic input to block first stage overcurrent timer t> Logic input to block second stage overcurrent timer t>> Logic input to block third stage overcurrent timer t>>> Logic input to initiate trip pulse timer from external input Logic input to initiate close pulse timer from external input Logic input to initiate breaker fail and records from an external trip signal Logic input to initiate timer tAUX1 from external input Logic input to initiate timer tAUX2 from external input Logic input to initiate timer tAUX3 from external input Logic input to select group 2 protection settings from external input Logic input to indicate circuit breaker in closed position Logic input to indicate circuit breaker in open position Logic input to indicate circuit breaker in bus 2 position Logic input to block/reset thermal protection, also resets thermal ammeters

Relay masks Display 0B00 RELAY MASKS 0B01 Io> Fwd

Status READ PWP

0B02

PWP

Io>

Rev

Description Column heading Earth fault forward start (non directional start for non directional relays) Earth fault reverse start (only available when directionalised)


3.17


0B03 to> 0B04 to>> 0B05 to>>> 0B06 I> Fwd

PWP PWP PWP PWP

0B07

PWP

I>

Rev

0B08 tA>

PWP

0B09 tB>

PWP

0B0A tC>

PWP

0B0B 0B0C 0B0D 0B0E 0B0F 0B10 0B11 0B12 0B13 0B14

PWP PWP PWP PWP PWP PWP PWP PWP PWP PWP

t>> t>>> CB Trip CB Close CB Fail Aux 1 Aux2 Aux3 tV< Level 1

0B15 Level 2

PWP

0B16 Level 3

PWP

0B17 thAlarm 0B18 thTrip 0B19 CB Alarm

PWP PWP PWP

First stage time delayed earth fault output Second stage time delayed earth fault output Third stage time delayed earth fault output Overcurrent forward start (non directional start for non directional relays) Overcurrent reverse start (only available when directionalised) First stage time delayed overcurrent output for phase A First stage time delayed overcurrent output for phase B First stage time delayed overcurrent output for phase C Second stage time delayed overcurrent output Third stage time delayed overcurrent output Trip pulse output Close pulse output Breaker fail output for initiation of back tripping Output from the auxiliary 1 time delayed function Output from the auxiliary 2 time delayed function Output from the auxiliary 3 time delayed function Undervoltage time delayed output Output in response to command to load shed to level 1 (not available on KCEU relays) Output in response to command to load shed to level 2 (not available on KCEU relays) Output in response to command to load shed to level 3 (not available on KCEU relays) Thermal overload alarm Thermal overload trip Alarm for circuit breaker maintenance

Recorder Display 0C00 RECORDER 0C01 Control

Status READ SET

0C02 Capture

SET

0C03 Post trigger

SET

0C04 Logic trig

SET

0 1 2 3 4 5 6 7 8

+Opto0 +Opto1 +Opto2 +Opto3 +Opto4 +Opto5 +Opto6 +Opto7 –Opto0

Description Column heading Manual stop/start control (running = started; triggered = stopped) Select the functions to be captured: magnitudes/ phase angles/samples Select the number of samples recorded after the trigger (1 to 511) Select the logic input to trigger the recorder (0 to 7 pick-up or drop-off) Trigger in response to energisation of logic input L0 Trigger in response to energisation of logic input L1 Trigger in response to energisation of logic input L2 Trigger in response to energisation of logic input L3 Trigger in response to energisation of logic input L4 Trigger in response to energisation of logic input L5 Trigger in response to energisation of logic input L6 Trigger in response to energisation of logic input L7 Trigger in response to de-energisation of logic input L0

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242 9

–Opto1

A

–Opto2

B

–Opto3

C

–Opto4

D

–Opto5

E

–Opto6

F

–Opto7

0C05 Relay Trig 0

+Rly 0

1

+Rly 1

2

+Rly 2

3

+Rly 3

4

+Rly 4

5

+Rly 5

6

+Rly 6

7

+Rly 7

8

–Rly 0

9

–Rly 1

A

–Rly 2

B

–Rly 3

C

–Rly 4

D

–Rly 5

E

–Rly 6

F

–Rly 7


SET

Trigger in response to de-energisation of logic input L1 Trigger in response to de-energisation of logic input L2 Trigger in response to de-energisation of logic input L3 Trigger in response to de-energisation of logic input L4 Trigger in response to de-energisation of logic input L5 Trigger in response to de-energisation of logic input L6 Trigger in response to de-energisation of logic input L7 Select the output relay tio trigger the recorder (0 to 7 pick-up or drop-off) Trigger in response to energisation of output relay RLY 0 Trigger in response to energisation of output relay RLY 1 Trigger in response to energisation of output relay RLY 2 Trigger in response to energisation of output relay RLY 3 Trigger in response to energisation of output relay RLY 4 Trigger in response to energisation of output relay RLY 5 Trigger in response to energisation of output relay RLY 6 Trigger in response to energisation of output relay RLY 7 Trigger in response to de-energisation of output relay RLY 0 Trigger in response to de-energisation of output relay RLY 1 Trigger in response to de-energisation of output relay RLY 2 Trigger in response to de-energisation of output relay RLY 3 Trigger in response to de-energisation of output relay RLY 4 Trigger in response to de-energisation of output relay RLY 5 Trigger in response to de-energisation of output relay RLY 6 Trigger in response to de-energisation of output relay RLY 7



Section 4. CHANGING TEXT AND SETTINGS Settings and text in certain cells of the menu can be changed via the user interface. To do this the cover must be removed from the front of the relay so that the [+] and [–] keys can be accessed. 4.1

Quick guide to menu controls Quick guide to menu control with the four keys Current display

Key press

Effect of action

Default display

[0] long

Back-light turns ON – no other effect

[0] short

Steps through the available default displays

[F]

steps down to column heading SYSTEM DATA

[+]


[–]


[0] short


[F]

steps down to column heading SYSTEM DATA without resetting the fault flags

[0] long

resets trip LED and returns default display

[+]


[–]


[0] short


[0] long

Re-establishes password protection immediately and returns the default display

Fault flags after a trip

Column heading

[F] long [F] short

Any menu cell

steps down the menu to the next item in the column

[–]

move to next column heading

[+]

move to previous column heading

[F] short [F] long

Any settable cell

move to next column heading

steps down the menu to the next item in the column displays the heading for the next column

[F] + [0]

steps back up the menu to the previous item

[0] short


[0] long

Resets the value if the cell is resettable

[+] or [–]

Puts the relay in setting mode. The password must first be entered for protected cells



Current display

Key press

Effect of action

Setting mode

[0]

Escapes from the setting mode without a setting change

[+]

Increments value – with increasing rapidity if held

[–]

Decrements value – with increasing rapidity if held

[F]

Changes to the confirmation display

[F]

If function links, relay or input masks are displayed the [F] key will step through them from left to right and finally changing to the confirmation display

[+]

Confirms setting and enters new setting or text

[–]

Returns prospective change to check/modify

[0]

Escapes from the setting mode without a setting change

Confirmation mode

The actions shown in the shaded area can only be performed when the cover is removed.

4.2

[F] long

means press F key and hold for longer than 1s

[F] short

means press F key and hold for less than 1s

[F]

means press the F key length of time does not change the response

To enter setting mode Give the [F] key a momentary press to change from the selected default display and switch on the back-light; the heading SYSTEM DATA will be displayed. Use the [+] and [–] keys, or a long press of the [F] key, to select the column containing the setting, or text that is to be changed. Then with the [F] key step down the column until the contents of that cell are displayed. Press the [+] key to put the relay into the setting mode. Setting mode will be indicated by a flashing cursor on the bottom line of the display. If the cell is read-only, or password protected, then the cursor will not appear and the relay will not be in the setting mode.

4.3

To escape from the setting mode IMPORTANT! If at any time you wish to escape from the setting mode without making a change to the contents of the selected cell: Hold the [0] key depressed for 1s, the original setting will be returned and the relay will exit the setting mode.

4.4

To accept the new setting Press the [F] key until the confirmation display appears: Are you sure? + = YES

– = NO

Press the [0] key if you decide not to make any change. Press the [–] key if you want to further modify the data before entry. Press the [+] key to accept the change. This will terminate the setting mode.



Password protection Password protection is provided for the configuration settings of the relay. This includes time curve selection, CT and VT ratios, function links, input masks and relay masks. Any accidental change to configuration could seriously affect the ability of the relay to perform its intended functions, whereas, a setting error may only cause a grading problem. Individual settings are protected from change when the relay cover is in place by preventing direct access to the [+] and [–] keys. The password consists of four characters that may contain any upper case letter from the alphabet. The password is initially set in the factory to AAAA, but it can be changed by the user to another combination if necessary. If the password is lost or forgotten, access to the relay will be denied. However, if the manufacturer or their agent is supplied with the serial number of the relay, a back-up password can be supplied that is unique to that particular product.

4.6

Entering passwords Using the [F] key, select the password cell [0002] in the SYSTEM DATA column of the menu. The word “Password” is displayed and four stars. Press the [+] key and the cursor will appear under the left hand star. Now use the [+] key to step through the alphabet until the required letter is displayed. The display will increment faster if the key is held down and the [–] key can be used in a similar way to move backwards through the alphabet. When the desired character has been set the [F] key can be given a momentary press to move the cursor to the position for the next character. The process is then repeated to enter the remaining characters that make up the password. When the fourth character is acknowledged by a momentary press of the [F] key the display will read: Are you sure? + = YES

– = NO

Press the [0] key if you decide not to enter the password. Press the [–] key if you want to modify the entry. Press the [+] to enter the password. The display will then show four stars and if the password was accepted the alarm LED will flash. If the alarm LED is not flashing the password was not accepted – a further attempt can be made to enter it, or the [F] key pressed to move to the next cell. Note: When the password cell is displayed, do not press the [+] or [–] key whilst the alarm LED is flashing unless you want to change the password! 4.7

Changing passwords When the password has been entered and the alarm LED is flashing the [+] key is pressed to put the relay in setting mode. A new password can now be entered as described in Section 4.6. After entering the fourth character make a note of the new password shown on the display before pressing the [F] key to obtain the confirmation display. Are you sure? + = YES

– = NO

Press the [0] key if you decide not to enter the new password. Press the [–] key if you want to modify your entry. Press the [+] to enter the new password which will then replace the old one.



Note: Make sure the new password has been written down before it is entered and that the password being entered agrees with the written copy before accepting it. If the new password is not entered correctly you may be denied access in the future. If the password is lost a back-up password unique to that relay can be provided from the factory, or certain agents, if the serial number of the product is quoted. 4.8

Restoration of password protection Password protection is reinstated when the alarm LED stops flashing. This will occur fifteen minutes after the last key press. To restore the password protection without waiting for the fifteen minute time-out, select the password cell or any column heading and hold the reset key [0] depressed for 1s. The alarm LED will cease to flash to indicate the password protection is restored.

4.9

Entering text Enter the setting mode as described in Section 4.2 and move the cursor with the [F] key to where the text is to be entered or changed. Then using the [+] and [–] keys, select the character to be displayed. The [F] key may then be used to move the cursor to the position of the next character and so on. Follow the instructions in Section 4.4 to exit from the setting change.

4.10

Changing function links Select the column heading required and step down to the function links “SD Links”, “EF Links”, “PF Links”, or “LOG Links” and press either the [+] or [–] to put the relay in a setting change mode. A cursor will flash on the bottom line at the extreme left position. This is link “F”; as indicated by the character printed on the frontplate under the display. Press the [F] key to step along the row of links, one link at a time, until some text appears on the top line that describes the function of a link. The [+] key will change the link to a “1” to select the function and the [–] key will change it to a “0” to deselect it. Follow the instructions in Section 4.4 to accept the setting change. Not all links can be set, some being factory selected and locked. The links that are locked in this way are usually those for functions that are not supported by a particular relay, when they will be set to “0”. Merely moving the cursor past a link position does not change it in any way.

4.11

Changing setting values Move through the menu until the cell that is to be edited is displayed. Press the [+] or [–] key to put the relay into the setting change mode. A cursor will flash in the extreme left hand position on the bottom line of the display to indicate that the relay is ready to have the setting changed. The value will be incremented in single steps by each momentary press of the [+] key, or if the [+] key is held down the value will be incremented with increasing rapidity until the key is released. Similarly the [–] key can be used to decrement the value. Follow the instructions in Section 4.4 to exit from the setting change. Note: When entering CT RATIO or VT RATIO the overall ratio should be entered, ie. 2000/5A CT has an overall ratio of 400:1. With rated current applied the relay will display 5A when CT RATIO has the default value of 1:1 and when the ratio is set to 400:1 the displayed value will be 400 x 5 = 2000A.



Setting communication address The communication address will be set to 255, the global address to all relays on the network, when the relay is first supplied. Reply messages are not issued from any relay for a global command, because they would all respond at the same time and result in contention on the bus. Setting the address to 255 will ensure that when first connected to the network they will not interfere with communications on existing installations. The communication address can be manually set by selecting the appropriate cell for the SYSTEM DATA column, entering the setting mode as described in Section 4.2 and then decrementing or incrementing the address. Then exit setting mode as described in Section 4.4. To automatically allocate an address to the relay, see Chapter 6.

4.13

Setting input masks An eight bit mask is allocated to each protection and control function that can be influenced by an external input applied to one or more of the logic inputs. When the menu cell for an input mask is selected the top line of the display shows text describing the function to be controlled by the inputs selected in the mask. A series of “1”s and “0”s on the bottom line of the display indicates which logic inputs are selected to exert control. The numbers printed on the frontplate under the display indicate each of the logic inputs (L7 to L0) being displayed. A “1” indicates that a particular input is assigned to the displayed control function and a “0” indicates that it is not. The same input may be used to control more than one function.

4.14

Setting output masks An eight bit mask is allocated to each protection and control function. When a mask is selected the text on the top line of the display indicates the associated function and the bottom line of the display shows a series of “1”s and “0”s for the selected mask. The numbers printed on the frontplate under the display indicate the output relay (RLY7 to RLY0) to which each bit is associated. A “1” indicates that the relay will respond to the displayed function and a “0” indicates that it will not. A logical “OR” function is performed on the relay masks so that more than one relay may be allocated to more than one function. An output mask may be set to operate the same relay as another mask so that, for example, one output relay may be arranged to operate for all the functions required to trip the circuit breaker and another for only those functions that are to initiate autoreclose.

4.15

Resetting values and records Some values and records can be reset to zero, or some predefined value. To achieve this the menu cell must be displayed and then the [0] key held depressed for at least one second to effect the reset. The fault records are slightly different because they are a group of settings and to reset these the last cell under FLT RECORDS must be selected. This will display: Clear = [0] To reset ALL FIVE fault records hold the [0] key depressed for more than 1s. If the records are not cleared the oldest record will be overwritten by the next fault.



Resetting trip LED indication The trip LED can be reset when the flags for the last fault are displayed. They are displayed automatically after a trip occurs, or can be selected in the fault record column. The reset is effected by depressing the [0] key for 1s. Resetting the fault records as described in 4.15 will also reset the trip LED indication. Set function link SD5 to “1” for the trip LED to automatically reset. This will then occur when the circuit breaker is reclosed and the load current exceeds the undercurrent setting (I<) for three seconds. The LED will not reset if the circuit breaker is not reclosed and so it is a useful function to employ with autoreclose equipment, as it will prevent unwanted trip flags being displayed after a successful reclosure of the circuit breaker.

Section 5. EXTERNAL CONNECTIONS Standard connection table Function Earth terminal Watchdog relay (break contact) 48V field voltage Capacitor trip voltage Not used Auxiliary voltage input Not used A phase voltage C phase voltage A phase current B phase current C phase current Neutral current Output relay 4

– b – [+] [+] – (+) – IN IN IN IN IN IN –

Output relay 5

–

Output relay 6

–

Output relay 7

–

Opto control input L3 Opto control input L4 Opto control input L5 Opto control input L6 Opto control input L7 Common L3/L4/L5/L6/L7

(+) (+) (+) (+) (+) (–)

Terminal 1 2 3 4 5 6 7 8 9 10 15 16 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56

– m – [–] [–] – (–) – IN OUT OUT OUT OUT OUT –

Function Not used Watchdog relay (make contact) 48V field voltage Capacitor trip voltage Not used Auxiliary voltage input Not used B phase voltage Common voltage neutral A phase current B phase current C phase current Neutral current Output relay 0

–

Output relay 1

–

Output relay 2

–

Output relay 3

(+) (+) (+) (–) – –

Opto control input L0 Opto control input L1 Opto control input L2 Common L0/L1/L2 K-BUS serial port K-BUS serial port

Key to connection tables [+] and [–]

indicate the polarity of the dc output from these terminals

(+) and (–)

indicate the polarity for the applied dc supply

IN/OUT

the signal direction for forward operation



Note: All relays have standard Midos terminal blocks to which connections can be made with either 4mm screws or 4.8mm pre-insulated snap-on connectors. Two connections can be made to each terminal. 5.1

Auxiliary supply The auxiliary voltage may be DC or AC provided it is within the limiting voltages for the particular relay. The voltage range will be found on the frontplate of the relay; it is marked Vx = (24V – 125V) or (48V – 250V). An ideal supply to use for testing the relays will be 50V DC or 110V AC because these values fall within both of the auxiliary voltage ranges. The supply should be connected to terminals 13 and 14 only. To avoid any confusion it is recommended that the polarity of any applied voltage is kept to the Midos standard: – for dc supplies the positive lead connected to terminal 13 and the negative to terminal 14 – for ac supplies the live lead is connected to terminal 13 and the neutral lead to terminal 14.

5.2

Dual powered relays Dual powered relays derive power from the current transformer circuit and may be used with this power source alone. However, the application of an auxiliary DC or AC voltage will enable lower earth fault settings to be used, also settings to be applied and data to be read when the load current is insufficient to power the relay. It will also allow communications to be maintained at such times. When powered from the CT circuit alone the 48V field voltage will be available to power the opto-isolated control inputs when the protection starts up. The phase fault current setting range is limited to the minimum current levels at which the power requirements of the relay can be maintained. See Technical Data, Chapter 7. This model of relay is rated for an auxiliary voltage Vx = (100V to 250V). Note: The capacitance discharge circuit is not isolated from the auxiliary supply and to prevent the relay from being damaged, no external ground connection should be made to this circuit.

5.3

Logic control inputs There are a number of logic control inputs to the relay that are optically coupled to provide galvanic isolation between the external and internal circuits. They are rated at 48V and the power supply within the relay provides an isolated field voltage to energise them. This arrangement keeps the power consumption of these inputs to a minimum and ensures that they always have a supply to energise them when the relay is operational. This is particularly important for the dual powered relay when there is no auxiliary supply voltage available and the relay is energised by the current from the line current transformers. Software filtering is applied to prevent induced AC signals in the external wiring causing operation of logic inputs. This is achieved by sampling the logic inputs eight times per cycle and five consecutive samples have to indicate that the input is energised in a positive sense before it is accepted. This ensures that the inputs are relatively immune to spurious operation from induced AC signals in the wiring. The capture time is: 12 ±2.5ms at 50Hz 10.4 ±2.1ms at 60Hz (not available on KCEU relays)



Note: These inputs will not capture a fleeting contact unless it dwells in the closed state for a time exceeding the above values. The opto-isolated logic control inputs are divided into two groups. Three (L0, L1, L2) have their common connection on terminal 52 and are fitted to the KCGG 142 02 relay and relays with no more than two analogue inputs. The remainder (L3, L4, L5, L6, L7) have their common connection on terminal 55 and are fitted to relays with 8 opto inputs. When they are to be energised from the field voltage then terminals 52 and 55 must be connected to terminal 8, the negative of the field voltage. The logic inputs can then be energised by connecting a volt free contact between the positive of the field voltage, terminal 7, and the terminal for the appropriate logic input. The circuit for each opto-isolated input contains a blocking diode to protect it from any damage that may result from the application of voltage with incorrect polarity. Where the opto-isolated input of more than one relay is to be controlled by the same contact it will be necessary to connect terminal 7 of each relay together to form a common line. In the example circuit below, contact X operates L1 of relay 1 and contact Y operates L0 of relay 1 as well as L0 and L1 of relay 2. There are no connections made to L2 as it is not used on either relay. The logic inputs can be separated into two isolated groups when it is necessary to energise some from the station battery. The logic inputs are rated at 48V and it will be necessary to connect an external resistor in series with the input if the battery is of higher rated voltage. The value of this resistor should be 2.4ký for every additional 10V. The field voltage is not earthed and has insulation rated for 2kV for 1 minute. Thus if necessary the positive terminal of the field voltage could be connected to the positive terminal on the external battery. Also the two separate groups of logic inputs could be energised from separate batteries. 5.4

Analogue inputs The relays can have up to eight analogue inputs, two on the microprocessor board and six on the auxiliary expansion board. Each is fed via an input transducer, a low pass filter and a three range scaling amplifier. The analogue signals are sampled eight times per cycle on each channel as the sampling rate tracks the frequency of the input signal. The wide setting range provided on the auxiliary powered version of the relays is sufficient to enable the 5A version of the relay to operate from either 1A or 5A current transformers and this version of the relay can be used where dual rated relays are specified. Alternatively, the wide setting range makes the relay suitable for use on circuit breakers that may be applied to a wide range of load circuit ratings with only one current transformer ratio. For example a circuit breaker rated at 2kA and fitted with current transformers rated at 2000/10A (or 2000/2A) and relays rated at 5A (or 1A) could be applied to circuits with load ratings from 100A to 2000A. The dual powered relays have a narrower setting range and must be used with current transformers that match their current rating. Thermal dissipation is the limitation for the upper end of the setting range and the energy required to power the relay is the limitation at the lower end. When the relay is powered from an additional auxiliary voltage source, earth fault settings can be applied below that at which the relay can derive sufficient power from the CTs. For this reason the earth fault setting range has not been restricted.



Output relays Four programmable output relays are provided on the KCGG 142 02 relay and relays with no more than two analogue inputs and eight on all other models. They can be arranged to operate in response to any or all of the available functions by suitably setting the output masks. The protection and control functions to which these relays respond are selectable via the menu system of the relay. In addition there is a watchdog relay which has one make and one break contact. Thus it can indicate both healthy and failed conditions. As these contacts are mainly used for alarm purposes they have a lower rating than the programmable outputs. The terminal numbers for the output relay contacts are given in the table at the start of Section 5.

5.6

Ouput relay minimum dwell time Outputs from t>, t>>, t>>>, to>, to>>, to>>> have a minimum dwell of 100ms. The thermal trip will have an inherent delay dependent on the selected time constant. The contact dwell ensures a positive trip signal is given to the circuit breaker. All other outputs such as I>, I>>, I>>>, Io>, Io>>, Io>>>, tV>, Aux1, Aux2 and Aux3 have no deliberate dwell time added to them. This is because they are either followed by a timer, or used for control purposes which require a faster reset time.

5.7

Setting the relay with a PC or laptop Connection to a personal computer (PC) or lap top via a K-Bus/RS232 interface type KITZ 101 will enable settings to be changed more easily. Software is available for the PC that allows on line setting changes in a more user friendly way with a whole column of data being displayed instead of just single cells. Setting files can also be saved to floppy disk and downloaded to other relays of the same type. There are also programs available to enable setting files to be generated offline, ie. away from the relays that can be later down-loaded as necessary. The communication connections and available software are covered under ‘Applications’ in Chapter 6.

Section 6. ALARM FLAGS A full list of the alarm flags will be found in Section 3.3 and is located in cell 0022 of the SYSTEM DATA column of the menu. They consist of nine characters that may be either “1” or “0” to indicate the set and reset states respectively. The control keys perform for this menu cell in the same way as they do for function links. The cell is selected with the function key [F] and the relay then put in the setting mode by pressing the [+] key to display the cursor. The cursor will then be stepped through the alarm word from left to right with each press of the [F] key and text identifying the alarm bit selected will be displayed. The only alarm flag that can be manually set is the bit 6, the watchdog test flag. When this flag is set to “1” the watchdog relay will change state and the green LED will extinguish. When any alarm flag is set the alarm LED will be continuously lit. However, there is another form of alarm condition that will cause the alarm LED to flash and this indicates that the password has been entered to allow access to change protected



settings within the relay. This is not generally available as a remote alarm and it does not generate an alarm flag. Note: No control will be possible via the key pad if the “unconfigured” alarm is raised because the relay will be locked in a non-operate state.

Types KCGG 122, 142 KCEG 112, 142, 152, 242 and KCEU 142, 242 Overcurrent and Directional Overcurrent Relays Service Manual

Chapter 4 Application of Protection Functions

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242 1. 1.1 1.2 2. 2.1 2.2 2.3 2.4 2.5 2.6 3. 4. 4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 5. 5.1 5.2 5.3 5.4 5.5 5.6 5.6.1 5.6.2 5.7 5.8 5.9 5.10 5.10.1 5.10.2 5.10.3 5.10.4 5.11 5.12 6. 6.1 6.2 6.3 6.4 6.5 6.6 6.7 6.8 6.9

CONFIGURATION Configuring the relay Default configuration CHANGING THE CONFIGURATION OF THE RELAY System data (SD) Earth fault links (EF) Phase fault links (PF) Logic links (LOG) Preferred use of logic inputs Preferred use of output relays OVERCURRENT AND EARTH FAULT PROTECTION FIRST STAGE OVERCURRENT AND EARTH FAULT LOGIC Start function Definite time Inverse time curves Reset timer Matching the reset time response of an electromechanical relay Protection against intermittent recurrent faults Time graded protection Dual rate inverse time curves SECOND/THIRD STAGE OVERCURRENT AND EARTH FAULT LOGIC Two out of three logic Broken conductor logic Transformer inrush currents Sensitivity to harmonics Autoreclose inhibition of instantaneous low set Blocked overcurrent protection Blocked IDMT overcurrent Blocked short time overcurrent Protection of busbars on radial system Points to consider with blocking schemes Back-up transfer tripping scheme Restricted earth fault protection Setting voltage for stability: Rs, stabilising resistor Is, current setting Metrosil assessment Rectifier protection Cold load pick-up DIRECTIONAL OVERCURRENT Directional overcurrent logic Directional start output Directional first stage overcurrent Directional second and third overcurrent stages Directional earth fault logic Application of directional phase fault relays Synchronous polarisation Application of directional earth fault relays Power directional earth fault element


1 1 2 2 2 3 4 5 6 6 7 8 8 9 9 10 10 10 11 12 12 13 13 13 14 14 14 14 15 16 17 18 18 18 19 19 19 20 21 23 23 23 24 24 24 24 26 26 27

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242 6.10 6.11 6.11.1 6.11.2 6.11.3 7. 7.1 7.2 7.3 7.4 7.5 7.6 7.7 8. 8.1 9. 9.1 9.2 10. 11. 11.1 11.2 11.3 12. 12.1 12.2 12.3 13. 13.1 13.2 13.3 13.4 13.5 13.6 14. 14.1 14.2 14.3 14.4 14.5 14.6

Directional stability for instantaneous elements Protection of circuits with multiple in-feeds Blocked directional overcurrent protection Blocked overcurrent protection for the feeder Blocked overcurrent protection for the bus section THERMAL OVERCURRENT Thermal state Thermal trip and alarm levels Operation time Thermal memory Thermal reset Dual time constant characteristics Application of thermal protection UNDERCURRENT Breaker failure protection UNDERVOLTAGE Undervoltage trip Voltage controlled overcurrent protection UNDER FREQUENCY AUXILIARY TIMERS Extra earth fault stage Loss of load protection Delayed under frequency trip SETTING GROUP SELECTION Remote change of setting group Manual change of setting group Controlled change of setting group DUAL POWERED RELAYS Powered from current transformers alone Powered from an auxiliary AC voltage and from current transformers Special application notes for dual powered relays Dead substation protection Capacitor discharge tripping AC series tripping AUTORECLOSE - SINGLE SHOT SCHEME Overview Connections Successful reclose description Unsuccessful reclose Blocking instantaneous low set protection when reclosing Circuit breaker operation counter


28 28 29 29 29 30 31 31 31 31 32 32 33 34 34 35 35 36 36 36 37 37 37 38 38 38 38 39 39 40 40 41 41 41 42 42 43 44 45 45 46

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242 Figure 1: Figure 2: Figure 3: Figure 4: Figure 5: Figure 6: Figure 7: Figure 8: Figure 9: Figure 10: Figure 11: Figure 12: Figure 13: Figure 14: Figure 15: Figure 16: Figure 17: Figure 18: Figure 19: Figure 20: Figure 21: Figure 22: Figure 23: Figure 24: Figure 25: Figure 26:

Available overcurrent characteristics and their settings First stage overcurrent and earth fault logic. Matching electromechanical reset time Intermittent recurrent fault Dual rate curves Second and third stage overcurrent logic Blocked IDMT overcurrent Blocked overcurrent for busbar protection Back-up transfer trip scheme Protection for silicon rectifiers Matching curve to load and thermal limit of rectifier Compensation for motor starting current Directional characteristic Directional overcurrent relay logic Circuit with multiple infeeds Thermal alarm and trip logic Circuit breaker fail logic Undervoltage logic Auxiliary timer logic Setting group selection logic Start-up time delay Capacitor discharge trip AC series trip arrangement Connection diagram for single shot autoreclose scheme Successful autoreclose sequence Unsuccessful autoreclose sequence


7 8 10 11 12 13 15 16 17 20 20 22 23 25 29 30 34 35 37 38 39 41 42 43 44 45



Section 1. CONFIGURATION The settings that customise the relay for a particular application are referred to as the configuration. They include the function links, input masks, relay masks, etc. and they are password protected to prevent them being changed accidentally. Together these settings select the functions that are to be made available and how they are to be interconnected. Before the advent of integrated numerical relays, protection and control schemes comprised individual relays that had to be interconnected and a diagram was produced to show these interconnections. The configuration of a numerical relay is the software equivalent of these interconnections. With the software approach, installations can be completed in much shorter times, especially for repeat schemes, saving valuable time and cost. A second advantage is the ability to make some changes without having to disturb the external wiring. Before the connection diagrams can be drawn for an installation, it will be necessary to decide how the logic within the relay is to function. A copy of the logic diagram will be found at the back of this manual. It should be copied and the appropriate squares in the input and relays masks should be shaded in to show which logic inputs and output relays are to be assigned in each mask. The function links should then be drawn on the diagram in position “0” or “1” as required. These software links may turn functions on, or off, and when in the “off” state some unnecessary settings may not appear in the menu. The second and third overcurrent stages are typical examples of this. As supplied the third overcurrent stage is turned off and its associated settings I>>>/t>>> will not appear in the menu. The function link settings can now be read off the logic diagram and entered as a series of ones and noughts, in the boxes provided on the logic diagram. Case connection diagrams will be found at the back of this manual for the current models of K Range directional and non directional overcurrent relays. They may be copied and notes added in the appropriate boxes to indicate the function of the logic inputs and relay outputs. This diagram will then give the appropriate terminal numbers to which the external wires must be connected. In particular, it will show the terminal numbers to which the current and voltage transformers connections are to be made. Enough information is available from the logic and case connection diagrams to enable the full external wiring diagrams to be drawn and the operation of complete protection and control scheme to be understood. 1.1

Configuring the relay Each scheme of protection and control will have its own particular configuration settings. These can be named appropriately and the name entered as the “description” in cell 0004 in the system data column of the menu. If the scheme is likely to become a standard that is to be applied to several installations it would be worthwhile storing the configuration on a floppy disc so that it can be downloaded to other relays. The configuration file can be made even more useful by adding appropriate general settings for the protection and control functions. It will then only require the minimum of settings to be changed during commissioning the installation.



Default configuration The relays are provided with a basic configurations and typical settings to suit a basic application. The basic configuration provides: One settings group only. One IDMT characteristic (t> = standard inverse) Instantaneous overcurrent (t>>=0) Breaker failure protection with backtrip relay CB maintenance alarm Remote circuit breaker control

Section 2. CHANGING THE CONFIGURATION OF THE RELAY 2.1

System data (SD) Select the system data column of the menu, enter the password and then step down to the cell containing the SD links. Press the [+] key to put the relays into setting mode and use the [F] key to step through the options. The option will be shown in abbreviated form on the top line of the display as each function link is selected. To select an option set the link to “1” with the [+] key and to deselect it set it to “0” with the [–] key. The following options are available via links SD0 to SD8: SD0

Rem ChgStg

1 = enable remote setting changes

SD1

Not used

SD2

Rem CB Ctrl

1 = enable remote control of circuit breaker

SD3

Rem ChgGrp

1 = enable remote change of setting group

SD4

En Grp2

1 = enable group 2 settings to be used

SD5

Auto Flag

1 = enable flags to reset automatically on load restoration

SD6

Auto Rec

1 = enable disturbance recorder reset on load restoration

SD7

Log Evts

1 = enable logic events to be stored

SD8

Alt Rec Reset

1 = enable alternative reset method for disturbance record.

When the selection has been completed continue to press the [F] key until the confirmation display appears and confirm the selection. Now step down the menu to cell [0004 Description] and enter a suitable name for the configuration; a maximum of sixteen characters are available. Step down one cell [0005 Plant Ref.], where a suitable reference can be entered for the plant that the relay is to protect. If the configuration is for a relay that is to be applied to one particular circuit, then the reference by which the circuit is known can be entered at this time; a maximum of sixteen characters are available. Now move down the system data column to cell [0009 Freq] and set the frequency to 50Hz or 60Hz (except for KCEU relays) as appropriate. This is an important



setting because it will be the default frequency used by the analogue/digital converter when appropriate signals are not available for frequency tracking. If the address of the relay on the serial communication bus is known then it can be entered at this time. This cell is password protected on the series 2 relays. This concludes the settings that can be entered in this menu column at this time. 2.2

Earth fault links (EF) Select the column EARTH FAULT (1) and EF Links. Press the [+] key to put the relay into setting mode and set the links to “1” that enable the required options available via links EF0 to EF6. EF 0

Not used

EF 1

En Io>>

1 = enable earth fault stage 2

EF 2

En Io>>>

1 = enable earth fault stage 3

EF 3

Drn to>

1 = earth fault stage 1 directionalised

EF 4

Drn to>>


EF 5

Drn to>>>


EF 6

Io>>

1 = no peak measurement for stage 2 earth fault element

EF E

RevIo>>>

NoPeak

1 = reverse direction of third earth fault stage (Io>>>)

The links EF3, EF4 and EF5 enable the three overcurrent stages Io>, Io>> and Io>>> to be selectively directionalised. If all three links EF3, EF4 & EF5 are set non directional then the forward start will also be non directional and the reverse start will retain its normal function provided a directionalising voltage signal is available. The directional options are not be available on non directional KCGG overcurrent relays. For KCGG relays the Io>>/Io>>> elements are responsive to peak measurement so that they respond faster, but they will be more sensitive to harmonic currents that create peaks on the waveform. The “NoPeak” option can be selected for Io>> element, with link EF6, when the relay is required to be insensitive to harmonics. However, the “NoPeak” option is only provided for the Io>> setting. The KCEG/ KCEU directional overcurrent relays do not respond to peak values and are not provided with this link option. When the selection has been completed continue to press the [F] key until the confirmation display appears and then confirm the selection. Next enter the time delay characteristic for the to> element. Enter, or copy, the same settings into the EARTH FAULT (2) column if it is active. It is not essential that the links are set the same in both setting groups. For example the Io>>> element could be made available in group one and not in group two settings. Note: It would be wise to ensure the logic is such that an element that is to be switched out in the alternative setting group is reset before the alternative setting group is selected, or alternatively make a physical test to ensure there are no latch-up problems. A different time characteristic can be selected for to> in the second setting group, but it is not advisable to select inverse in one group and definite time in the other if



it is intended to dynamically switch between setting groups. If two different inverse curves are selected then the same register will be used for both. These registers are not reset to zero when the setting group is changed unless the current falls below the set threshold. 2.3

Phase fault links (PF) Select the PF Links under the PHASE FAULT (1) menu column heading and put the relay into setting mode by pressing the [+] key. Step through the function links with the [F] key and set the links for the options required. There are more options available for phase faults, but most of the additional ones are associated with voltage functions that are only available of the directional relays. The exceptions are the thermal characteristic which can be enabled by setting PF0=1 and the broken conductor detection which is activated by setting PFC=1. The 2/3 logic is also required for the broken conductor detection, so set link PF7=1 as well when using this function. PF 0

En Therm

1 = enable thermal element

PF 1

En I>>

1 = enable stage 2 overcurrent

PF 2

Enable I>>>

1 = enable stage 3 overcurrent

PF 3

Drn t>

1 = stage 1 overcurrent directionalised

PF 4

Drn t>>


PF 5

Drn t>>>


PF 6

I>>

1 = no peak measurement for stage 2 overcurrent

PF 7

I>>>=2/3

1 = 2 out of 3 phase elements to operate for I>>>/t>>> trip

PF 8

CB blk V<

1 = V< blocked when CB open

PF 9

V< any=1

1 = any phase undervoltage for trip 0 = all phases undervolted for trip

PF A

V< P-N=1

1 = V< measure phase/neutral voltage 0 = V< measure line voltage

PF B

SynPol=3.2

1 = synchronous polarising time extended to 3.2s

PF C

Brkn Cond

1 = enable broken conductor logic

PF D

En F<

1 = enable underfrequency element to initiate tAUX1

PF E

RevI>>>

1 = reverse direction of third overcurrent stage

PF F

All 2/3

1 = 2/3 logic applied to all phase outputs

NoPeak

The links PF3, PF4 and PF5 enable the three overcurrent stages I>, I>> and I>>> to be selectively directionalised. If all three links PF3, PF4 & PF5 are set non directional then the forward start will also be non directional and the reverse start will retain its normal function provided a directionalising voltage signal is available. The directional options are not available on non directional KCGG overcurrent relays. For KCGG relays the I>>/I>>> elements are responsive to peak measurement so that they respond faster, but they will be more sensitive to harmonic currents that create peaks on the waveform. The “NoPeak” option can be selected for I>> element, with link PF6, when the relay is required to be less sensitive to harmonics.



However, the “NoPeak” option is only provided for the I>> setting. The KCEG/ KCEU directional overcurrent relays do not respond to peak values and are not provided with this link option. When the selection has been completed continue to press the [F] key until the confirmation display appears and confirm the selection. Next enter the time delay characteristic for the t> element. Enter, or copy, the same settings into the PHASE FAULT (2) column if it is active. It is not essential that the links are set the same in both setting groups. For example the I>>> element could be made available in group one and not in group two settings. Note: It would be wise to check that an element that is to be switched out in the alternative setting group is reset before the alternative setting group is selected, or alternatively make a physical test to ensure there are no latchup problems. A different time characteristic can be selected for t> in the second setting group, but it is not advisable to select inverse in one group and definite time in the other if it is intended to dynamically switch between setting groups. If two different inverse curves are selected then the same register will be used for both and these registers will not be reset to zero when the setting group is changed unless the current is below the set threshold. 2.4

Logic links (LOG) The Logic Links under the LOGIC menu column heading customise the auxiliary functions of the relay. Put the relay into setting mode by pressing the [+] key. Step through the function links with the [F] key and set the links for the options required. LOG0

CB Rec

1 = enable CB records to be generated; 0 = inhibit CB records.

LOG1

CB1*1=0

1 = sum of currents; 0 = sum of current squared.

LOG2

BF blk Start

1 = enable breaker fail to reset start relays.

LOG3

Aux2=I<

1 = enable I< to initiate timer tAUX2 (loss of load function).

LOG4

Aux2=/Io<

1 = enable tAUX2 to start when Io exceeds Io< .

LOG5

tAUX3 Grp2

1 = Group 2 settings selected whilst tAUX3 is giving an output.

LOG6

tAUX2-tAUX3

1 = enable tAUX2 to delay pick-up of tAUX3.

LOG7

Latch Strt

1 = enable start flags to be latched.

LOG8

Hold Grp2

1 = manual selection of group 2 settings.

LOG9

Rst CBclose

1 = enable a trip to terminate the CB close pulse

LOGA

Log Rly7

1 = enable relay RLY7 to initiate latch flags and log records

LOGB

tAUX3=DDO

1 = tAUX3 delayed on drop-off 0 = delayed on pick-up



When the selection has been completed continue to press the [F] key until the confirmation display appears and confirm the selection. Set the breaker failure protection time delay tBF. Set the circuit breaker close and trip pulse time delays tCLOSE and tTRIP. Select the default display that appears on start-up. 2.5

Preferred use of logic inputs The following table is not mandatory, but it is suggested that it is followed where possible so that different schemes will use the a particular logic input for the same or similar function.

2.6

L0

Stg grp2

[change setting group]

L1

Blk t>>/to>>

[Block instantaneous low set from autoreclose]

L2

Blkt>>>/to>>>

[Block overcurrent for busbar/unit feeder protection]

L3

EXT TRIP

[external trip input from other protection]

L4

AUX2

[Auxiliary input to initiate timer tAUX2/CLP]

L5

AUX3

[Auxiliary input to initiate timer tAUX3/CLP]

L6

CB closed

[indication that CB is closed]

L7

CB open

[indication that CB is open]

Preferred use of output relays The following table is not mandatory, but it is suggested that it is followed where possible so that different schemes will use a particular output relay for the same or similar function. RLY0

START

[earth fault start or combined phase and earth forward start]

RLY1

START

[phase start or combined phase and earth reverse start]

RLY2

AR INITIATE

[any function assigned to initate autoreclose]

RLY3

TRIP

[any protection function assigned to trip the circuit breaker]

RLY4

ALARM

[Any function assigned to produce an alarm]

RLY5

BACKTRIP

[Output to backtrip for breaker fail]

RLY6

CB close

[in response to a remote command]

RLY7

CB trip

[in response to a remote command]



Section 3. OVERCURRENT AND EARTH FAULT PROTECTION Three independent time delayed overcurrent stages are provided for each phase and residual current input. In addition there is an undercurrent function associated with each of these currents and in some instances a thermal overcurrent characteristic is provided. The settings are marked I>/t>; I>>/t>>; I>>>/t>>>; I< and Ith>/TC; shown appropriately in the diagram below. These settings affect all three phases equally. The earth fault elements have similar settings marked Io>/to>; Io>>/to>>; Io>>>/ to>>> and Io<; there being no thermal element associated with this input. Both the peak value and the Fourier derived rms value of the power frequency component of the fault current are used to derive the protection functions. Each value has its own associated characteristics that can be used to advantage. For example, a change in the peak value may be detected in one half cycle of fault current and so this measurement is used for the undercurrent elements to obtain the fast reset required by breaker fail applications. The Fourier derived values are particularly useful for earth fault applications due to their high rejection of harmonic currents, in particular the third harmonic. Fourier values are also used for all measurements where a phase angle reference is required.

th>

I

TC >

I

Time

t> I

>> t>>

I

<

>>>

I

t>>>

Current

Figure 1: Available overcurrent characteristics and their settings



Section 4. FIRST STAGE OVERCURRENT AND EARTH FAULT LOGIC The following diagram shows the logic associated with the first earth fault and overcurrent stages. When the residual current exceeds the Io> threshold and provided that no logic inputs selected in the input mask [0A01 Blk to>] are energised, the time delay to> will start to time out. When the delay time expires the output relays selected in the relay mask [0B03 to>] will be energised, causing them to pick-up. If a logic input selected in mask [0A01 BLK to>] is energised then the time delay will be blocked and held reset. +

0A01

BLK to>

7 6 5 4 3 2 1 0 I

&

0B03

to> &

I

0B01

I

o> START

7 6 5 4 3 2 1 0

OBO8 tA>

BLK t>

7 6 5 4 3 2 1 0

Ð

7 6 5 4 3 2 1 0

o>

¯A¯4

to>

7 6 5 4 3 2 1 0

&

0B09

t>

tB>

7 6 5 4 3 2 1 0

0B0A

>

tC>

7 6 5 4 3 2 1 0

1

≥

&

0B06

I

> START

7 6 5 4 3 2 1 0

Blocking signal from breaker fail protection

Figure 2: First stage overcurrent and earth fault logic.

Similar logic is provided for the phase fault overcurrent protection and here a separate overcurrent threshold and time delay is used for each phase, but the same settings for I> and t> will apply to the elements on all three phases. A separate relay mask is provided for each phase so that a differrent output relay can be assigned to each phase output and/or the same output relays to all three phases. 4.1

Start function As soon as the Io> threshold is exceeded an instantaneous output is available via relay mask [0B01 Io>]. This is used to indicate that the protection has detected an earth fault and that the time delay to> has started. This time delay can be blocked by energising a logic input assigned in the input mask [0A01 Blk to>]. If this blocking input is energised by the start output from a downstream relay then operation will be blocked only if the relay nearer to the fault can clear the fault. This is the principle known as “Blocked Overcurrent Protection”, described more fully in a later section. The phase element is also provided with a start output via mask [0B06 I>] and a blocking input via mask [ØAØ4 Blk t>]. The start outputs for both the phase and earth fault elements are gated with a blocking signal, the function of which is described in the Section 4.8.1 Breaker failure protection. The time delayed output is via mask [0B03 to>] for the earth faults and for phase faults masks [0B08 tA>], [0B09 tB>] and [0B0A tC>] provide separate outputs for each of the phase elements.



Definite time The first stage can be selected have a definite time characteristic. The operation time will be the set time for the time delay to> or t>, plus the operation time of the output relay and the time taken to detect the overcurrent condition. The same register is used for the time delay t> in both setting groups and the timer is not reset when switching from one setting group to the other. Thus switching from the setting group with a long time setting to that with a short time setting may result in an instantaneous trip if the shorter time setting had already elapsed.

4.3

Inverse time curves Alternatively, the first stage can be selected to have a current dependent inverse time characteristic. The operation time is given accurately by a mathematical expression, into which the constants for the selected characteristic must be inserted. Nine inverse time characteristics are available and the general mathematical expression for the curves is: k t = TMS

I Is

where

+c Ð1

seconds

TMS

= Time Multiplier (0.025 to 1.5 in step 0.025)

I

= Fault current

Is

= Overcurrent setting

k, c, a

= Constants specifying curve

Curve No. Description 0 1 2 3 4 5 6 7 8 9

a

Definite Time Standard Inverse Very Inverse Extremely Inverse Long Time Inverse Moderately Inverse Very Inverse Extremely Inverse Short Time Inverse Rectifier Protection

Name DT SI30xDT VI30xDT EI10xDT LTI30xDT MI VI EI STI30xDT RECT

IEC Curve

k

c

a

– A B C – D E F – –

0 0.14 13.5 80 120 0.103 39.22 56.4 0.05 45900

0 to 100 0 0 0 0 0.228 0.982 0.243 0 0

1 0.02 1 2 1 0.02 2 2 0.04 5.6

Although the curves tend to infinity at the setting current value ( Is), the guaranteed minimum operation current is 1.05 Is ±0.05Is for all inverse characteristic curves, except curve 9 for which the minimum operating current is 1.6 Is±0.05Is (see section on rectifier protection). Note: Definite time characteristic and the start functions operate at Is ±0.05Is. Curves numbers 1, 2, 4, and 8 become definite time for currents in excess of 30 x Is. Curve 3 becomes definite time for currents above 10 x Is to give extra time grading steps at high current levels.



Reset timer A delayed reset is provided with the t>/to> time delays and the time set for this timer determines the duration that the current must remain below the threshold I>/Io> before the time delay register is reset to zero. There is an exception to this when the protection trips, because for this condition the time registers t>/to> are reset immediately. For the majority of applications the reset delay could be set to zero. For others a more appropriate setting can be used and some examples applications are given later.

4.5

Matching the reset time response of an electromechanical relay

tReset Is

Figure 3: Matching electromechanical reset time

The reset characteristic of an electromechanical relay is inverse and the reset timer can be used to give the relay a reset characteristic which approximates to this as shown in the diagram. It should be noted that the tRESET is not affected by the time multiplier setting and must therefore be set to the required delay. 4.6

Protection against intermittent recurrent faults This type of fault is also sometimes referred to as a pecking or flashing fault. A typical example of an intermittent recurrent fault would be one in a plastic insulated cable where, in the region of the fault, the plastic melts and reseals the cable, extinguishing the fault but after a short time the insulation breaks down again. The process repeats to give a succession of fault current pulses each of increasing duration with reducing intervals between, until the fault becomes permanent.



2000A 0.2s

3.0s

0.3s

2.0s

0.5s

0A Trip level

0

Figure 4: Intermittent recurrent fault

When the reset time of the overcurrent relay is less than the interval between the fault current pulses, the relay will be continually reset and not be able to integrate up to the trip level until the fault becomes permanent. Having the reset time set to give as long a delay as possible, but less than that which would interfere with normal operation of the protection and control system, will help to eliminate some less common health and safety problems. Overcurrent relays in Midos K Range have provision for adjusting the reset delay to values between 0 and 60 seconds for timers t>/to>. Reset times of 60 seconds are most suited to cable applications where autoreclose is not generally permitted. For overhead lines with fast reclosing equipment, it can be an advantage to set the reset time to zero; this will ensure that all relays will have fully reset before a reclosure takes place and that some relays will not be held part way towards operation as a result of the last fault. When grading with electro-mechanical relays which do not reset instantaneously, the reset delay can be used to advantage to gain closer discrimination. In these instances the reset time should be set to a value less than the dead time setting of any autoreclose relays on the system. Sensitive earth/ground fault relays will also benefit from having the reset time set as high as possible so that fault current pulses are summated. Any reset delay will give an improvement in the detection of intermittent faults. 4.7

Time graded protection Inverse definite minimum time relays are time graded such that the relay nearer to the fault operates faster than the relays nearer to the source. This is referred to as relay co-ordination because if the relay nearest to the fault does not operate, the next one back towards the source will trip in a slightly longer time. The time grading steps are typically 400ms, the operation times becoming progressively longer with each stage. Where difficulty is experienced in arranging the required time grading steps the use of a blocked overcurrent scheme should be considered (described in a later section). Note: The dynamic range of measurement is typically 820 times minimum setting.



Dual rate inverse time curves

t

I>(1)

I>> I>(2)

Figure 5: Dual rate curves

The same registers are used for the time delay in both setting group 1 and setting group 2. They are not reset when switching from one group to the other, unless the current falls below the threshold, or a blocking input is asserted. One of the other two time stages I>>, or I>>>, must be set in both setting groups, to the current level at which the curve is to change. When this current setting is exceeded, an output relay that is externally connected to energise a logic input will select the second setting group. I>(2), the current setting in the second setting group, must be set to less than 95% of the I>>, the current at which the characteristic is switched, to ensure that the register does not reset. The same TMS setting is advised for both setting groups, as an instantaneous trip may occur when switching to a lower TMS setting if the shorter time setting has already elapsed.

Section 5. SECOND/THIRD STAGE OVERCURRENT and EARTH FAULT LOGIC The second and third overcurrent and earth fault stages must be selected by setting links PF1, PF2, EF1 and EF2 =1 as appropriate for their associated settings to appear in the menu table. For these elements to operate the Fourier derived value of current must exceed the set threshold, or the peak value of the current must exceed twice the set threshold. This latter function ensures faster operation for currents above twice setting whilst ensuring negligible transient overreach. The time delays for the second and third stage overcurrent elements can be blocked by the energisation a logic input. If the time delay has started it will be reset by the application of the blocking signal. Each phase fault and earth fault element has its own independent time delay to ensure correct discrimination and fault indication.


EF1 0 1

EF2 0 1

PF1 0 1 PFC 0 1

PF2 0 1

0A02 BLK to>> 7 6 5 4 3 2 1 0


&

to> >

0B04 to>> 7 6 5 4 3 2 1 0

&

to> >>

0B05 to>>> 7 6 5 4 3 2 1 0

Stage 2 Earth fault

I o>>

0A03 BLK to>>> 7 6 5 4 3 2 1 0

Stage 3 Earth fault

I o>>>

0A05 BLK t>> 7 6 5 4 3 2 1 0 I >>

I<

&

t> >

&

t>> >

1

0B0B t>> 7 6 5 4 3 2 1 0

1

OBOC t>>> 7 6 5 4 3 2 1 0

∞

Stage 2 Overcurrent

&

0A06 BLK t>>> 7 6 5 4 3 2 1 0

1

≥

I >>>

PF7 0 1

≥

Broken conductor Stage 3 Overcurrent

2/3

Figure 6: Second and third third stage overcurrent overcurrent logic

5.1

Two out of three logic The t>>> element is provided with a two out of three logic, selected by setting link PF7=1. When selected, operation only occurs for phase/phase faults and double phase to earth/ground faults. It will not operate for single phase earth/ground faults.

5.2

Broken conductor logic The Broken Conductor Detection feature is associated with t>>> element and is based on the principle that if a conductor is broken there will be load current in two phases, but not in all three. The logic associated that provides this function is shown in Figure 6 above. It is enabled when links PF2, PFC and PF7 are each set to ‘1’. Link PF2 activates the third overcurrent stage and when link PF7 is set to ‘1’ an output will be produced if current is flowing in only two phases for a time in access of the setting t>>>. Link PFC enables the undercurrent elements to block the operation of t>>> if current is flowing in all three phases. Typically settings are, I< = 0.06In: I>>>= 0.08In for this application to ensure positive discrimination. An output relay can be allocated in the output mask [0B0C t>>>] for detection of a broken conductor. To To latch the flags flag s relay RLY3 must be assigned in this same output mask and the flags will indicate the fault with a _ _ * for two of the three phases and exclude the letters identifying the phases if the current is below the I> threshold. The broken conductor will be in the phase for which no flags have operated, because the current is zero.

5.3

Transformer inrush currents Either I>>/Io>>, or I>>>/Io>>> elements, may be used as high-set instantaneous elements. The design is such that they do not respond to the DC transient component of the fault current. The principle of operation allows the current settings to be set down to 35% of the prospective peak inrush current that will be taken by a transformer when it is energised. To a first approximation the peak inrush is given by the reciprocal of the per unit series reactance of the transformer. Use of the cold load pick up feature, to increase the time setting for the instantaneous elements when energising the primary circuit, may be considered as a way of allowing lower current thresholds to be used.



Sensitivity to harmonics The sampling frequency of the digital/analogue converter is synchronised to the power frequency by a frequency tracking algorithm. This improves both accuracy of measurement and the harmonic rejection. The tracking follows the analogue phase inputs with a preference to track the voltage inputs, but in their absence the current inputs are tracked. When the signal levels are too small to track the sampling frequency defaults to the set system frequency. It is important that this has been correctly set in menu cell 0009. The fundamental component of the residual voltage and current is usually relatively small and this can result in the harmonic content being predominant. Frequency tracking does not take place on the residual signals because it can lock-in to a subharmonic of the predominant frequency resulting in a reduced harmonic rejection level. An example where this would become a problem is when a transformer is energise and an almost pure second harmonic current can appear in the neutral circuit. With frequency tracking of this signal the harmonic rejection could fall significantly. For this application a multiphase relay is best suited as it will give maximum harmonic rejection whilst tracking the phase quantities. The I>>/Io>> and the I>>>/Io>>> elements in the KCGG relays respond to the peak value and the fourier derived values. This allows them to respond more quickly to an overcurrent condition, but at the same time it reduces the harmonic rejection. The I>>/Io>> elements are each provided with a software link PF6/EF6 that inhibits the peak measurement when they are set to ‘1’. If the Io>> element is used for sensitive earth fault applications it is advised that link EF6 is set to ‘1’. The KCEG directional relays do not respond to the peak values and so for them links PF6 and EF6 cannot be set.

5.5 5.5

Auto Autore recl clos ose e inhi inhibi biti tion on of inst instan anta tane neou ouss low low set set When overcurrent relays from the Midos K Range are used with autoreclose relays the I>>/Io>> elements may be used as low set instantaneous elements. The associated time delays t>>/to>> would be set to zero seconds to effect rapid fault clearance. Although the timer is set to zero, its output still may be blocked via one of the logic inputs to the relay. Blocking this element instead of the trip path, with a contact of the autoreclose relay, will ensure correct flagging at all times. Where lightning strikes are frequent, it can be an advantage to make the I>>/ Io>> setting equal to I>/Io>, in order to detect the maximum number of transient faults. It will also be advantageous to set SD5 = 1 so that the protection flags automatically reset after a successful reclose sequence.

5.6

Blocked ov overcurrent pr protection This type of protection is applicable to radial feeder circuits where there is little or no back feed. For parallel feeders, ring circuits, or where there can be a back feed from generators, directional relays should be considered.

5.6. 5.6.1 1

Bloc Blocke ked d IDMT IDMT over overcu curr rren entt This application relies on the up-stream IDMT relay being blocked by the start output from a down-stream relay that detects the presence of fault current above its setting. Thus both the up-stream and down-stream relays can then have the same current and time settings and grading will be automatically provided by the blocking feature. If the breaker fail protection is selected, the block on the upstream relay will be released if the down-stream circuit breaker fails to trip.



Thus for a fault below relay C, the start output from relay C will block operation of relay B and the start output of relay B will block operation of relay A. Hence all three relays could have the same time and current settings and the grading would be obtained by the blocking signal received from a relay closer to the fault. This gives a constant, close time grading, but there will be no back-up protection in the event of the pilots being short circuited.

A

B

C

Figure 7: 7: Blocked IDMT IDMT overcurrent overcurrent

5.6. 5.6.2 2

Blo Blocked cked sho short rt tim timee over overcu curr rren entt Reduced fault clearance times and increased security can be obtained by using blocked short time overcurrent protection. For this the I>>/t>> and the Io>>/to>> elements are used with their current threshold set above the transient load level and setting t>>/to>> to 80ms for non-directional relays. This time delay is for worst case conditions and may be reduced, depending on the system X/R and maximum fault level.



The time delays t>>/to>> are arranged to be blocked by the start output of the downstream relay when the downstream relay detects a fault current flowing. The short time delay is essential to ensure that the blocking signal will be received by the upstream relay before operation can occur. The inverse time overload elements should be graded in the normal way for cascade operation and to provide overload and backup protection. The short time elements, operating in the blocking mode, then provide an instantaneous zone of protection and again the breaker fail feature can be used to advantage. On detection of a breaker failure condition the start output would be reset to remove the block from the upstream relay, allowing the upstream relay to trip its breaker to clear the fault. Overcurrent relays are adequate for non-cascade operation on radial circuits, but for ring circuits, or where there are parallel feeds, it will be necessary to use directionalised overcurrent relays. 5.7

Protection of bu busbars on on ra radial sy system This is simply achieved on radial circuits by setting for the short time lags (t>>/to>>) of the relay on the incoming feeder 80ms for non-directional relays, and blocking these time delays when the start output of any relay on the load circuits detects fault current flowing from the busbar to a feeder. The 80ms time delay is for worst case conditions and may be reduced, depending on the system X/R and maximum fault level. Feedback from regenerative loads must be less than the relay setting. The protection can be enhanced by arranging for the internal breaker fail circuits of the feeder relays to backtrip the incoming circuit breaker and/or adding the back-up transfer tripping arrangement. The use of a dual powered relay on the incoming feeder can also be considered to provide dead substation protection. These topics are described more fully in other sections. Incomer

Block short time overcurrent

KCEG 242

Back trip

F1

KCGG 142

F2

Feeder 1

KCGG 142

F3

Feeder 2

KCGG 142

KCGG 142

F4

Feeder 3

Figure 8: Blocked overcurrent overcurrent for busbar protection

F5

Feeder 4



Poin Points ts to cons consid ider er with with bloc block king ing sche schem mes It is possible to separate the phase and earth fault start outputs and use them to block the respective elements elem ents of the upstream upstrea m relay. relay. However, if this is done then the effect of current transformer saturation during phase faults has to be considered. If the current transformers transiently saturate on one of the circuits then a spill current is produced in the neutral circuit of the current transformers. This can result in one of two effects: – The current current exceeds exceeds the threshol threshold d of the earth/grou earth/ground nd fault element then then it will will attempt to trip if it does not receive a blocking signal from a down stream relay. This will be an incorrect operation that may trip more circuits than necessary. – As a result of spill current current,, an earth/ground earth/ground fault fault element element gives gives a blocking blocking signal to the relay on the in-feed for a short duration. The first of these problems can be lessened by increasing the time setting of to>>, but this will reduce the benefits of blocked overcurrent schemes. The solution to consider is to block the phase and earth fault trip elements with the phase and earth fault start elements of the downstream relays, but prevent blocking of the phase fault trip elements under transient current transformer saturation conditions. This will be most easily achieved by setting the earth fault element polarising voltage threshold (Vop) above the maximum expected zero sequence voltage occurring under healthy conditions, thus preventing the earth fault elements on the incoming feeder relay producing a blocking signal under transient CT saturation conditions. The second effect may not be a problem at all if the transient spill current only lasts a short time, as the added delay caused by a spurious blocking signal will stabilise the protection for only a short time. If this is seen as a problem then the use of a stabilising resistor could be considered. +

Trip Ð relays

Watchdog repeat relay t>>

Incomer

t>>>

t>> set to 60ms t>>> set to 260ms Incomer

Feeder 1 Feeder 2 Feeder 3 Watchdog Contacts

Watchdog Contacts

Figure 9: Back-up transfer transfer trip scheme

Feeder Feeder Feeder Feeder Feeder 4 4 1 2 3



Back-up transfer tripping ing sche cheme In this application a trip from the relay on the incoming feeder can be diverted via the watchdog contacts of a failed relay to the circuit breaker on that feeder. Thus a fault on an outgoing feeder can be cleared by tripping the feeder circuit breaker even though the relay on that circuit has failed. Without this feature the fault would only have been cleared by tripping the circuit breaker on the incoming feeder and thus losing the total busbar load. Consider the radial feed arrangement shown in the diagram. The protection relay on the incomer provides two additional time delayed outputs: t>> with an 80ms delay if the downstream feeder relays are non-directional, or 200ms if they are directional, and t>>> with a delay of t>> plus grading margin. The t>> delay is for worst case conditions and may be reduced, depending on the system X/R and maximum fault level. The t>> output contact is wired through a normally open contact on the watchdog repeat relay, to the trip relay for the circuit breaker on the in-feed. The t>>> output is wired directly to the trip relay for the circuit breaker on the in-feed. With all the relays in a healthy state, the watchdog repeat relay will be energised and for a busbar fault the circuit breaker on the incoming circuit will be tripped by t>>. For a fault on any of the outgoing feeders t>> and t>>> of the relay on the incoming circuit will be blocked by the start contact of the overcurrent relay on the outgoing feeder which is carrying the fault current. The circuit carrying the fault current will be tripped by the overcurrent relay on that circuit. In the event of any relay on the outgoing circuits becoming defective, the watchdog repeat relay drops off to give an alarm and to transfer the t>> trip from the incoming circuit breaker to the buswire connected, via the watchdog break contact of each relay on the outgoing feeders, to the appropriate circuit breaker. Thus the trip will be transferred to the circuit breaker with the failed relay and so a fault on that circuit will be cleared without tripping the busbar. For a busbar fault the incoming circuit breaker will be tripped by t>>> after a short delay. For faults on any healthy outgoing feeder both t>> and t>>> of the incoming feeder will be blocked and correct discrimination will be obtained with only the faulted feeder being tripped.

5.10 .10

High igh impe impeda danc nce e pr prot otec ecti tion on The application of the KCGG numerical overcurrent relay as differential protection for machines, power transformers and busbar installations is based on the high impedance differential principle, offering stability for any type of fault occurring outside the protected zone and satisfactory operation for faults within the zone. A high impedance relay is defined as a relay or relay circuit whose voltage setting is not less than the calculated maximum voltage which can appear across its terminals under the assigned maximum through fault current condition. It can be seen from Figure 1 that during an external fault the through fault current should circulate between the current transformer secondaries. The only current that can flow through the relay circuit is that due to any difference in the current transformer outputs for the same primary current. Magnetic saturation will reduce the output of a current transformer and the most extreme case for stability will be if one current transformer is completely saturated and the other unaffected. This condition can be approached in busbar installations due to the multiplicity of infeeds and extremely high fault level. It is less likely with machines or power transformers due to the limitation of through fault level by the protected unit’s



CTA

CTB

Protected unit

ZMA

ZMB RCTA

RCTB

RL

RL RRELAY CIRCUIT

RL

RL

Figure 10: Principle of high impedance protection

impedance, and the fact that the comparison is made between a limited number of current transformers. Differences in current transformer remanent flux can, however, result in asymmetric current transformer saturation with all applications. Calculations based on the above extreme case for stability have become accepted in lieu of conjunctive scheme testing as being a satisfactory basis for application. At one end the current transformer can be considered fully saturated, with its magnetising impedance ZMB short circuited while the current transformer at the other end, being unaffected, delivers its full current output. This current will then divide between the relay and the saturated current transformer. This division will be in the inverse ratio of RRELAY CIRCUIT to (RCTB + 2RL) and, if RRELAY CIRCUIT is high compared with R CTB + 2RL, the relay will be prevented from undesirable operation, as most of the current will pass through the saturated current transformer. To achieve stability for external faults, the stability voltage for the protection (V s) must be determined in accordance with formula 1. The setting will be dependent upon the maximum current transformer secondary current for an external fault ( If ) and also on the highest loop resistance value from the relaying point (R CT + 2RL). The stability of the scheme is also affected by the characteristics characteristics of the differential relay and the value of K in the expression takes account of this. One particular characteristic that affects the stability of the scheme is the operating time of the differential relay. The slower the relay operates the longer the spill current can exceed its setting before operation occurs and the higher the spill current that can be tolerated. For the KCGG relay I> element the value of K is 0.5 as shown in formula 2. Vs > KIf (R (RCT + 2RL)

(1)

Vs > 0.5If (R (RCT + 2RL)

(2)

where RCT =

curr curren entt tran transf sform ormer er sec secon onda dary ry wind windin ing g resis resista tanc ncee

RL

=

maximu maximum m lead lead resistan resistance ce from from the the curren currentt tran transfo sformer rmer to the relaying point

If

=

maxim maximum um secon secondary dary exte externa rnall faul faultt curr curren entt

K

=

a cons consta tant nt affe affect cted ed by the the dyna dynami micc resp respon onse se of the the rela relayy



Note: When high impedance differential protection is applied to motors or reactors, there is no external fault current. Therefore, the locked rotor current or starting current of the motor, or reactor inrush current, should be used in place of the external fault current. To obtain high speed operation for internal faults, the knee point voltage, V K , of the CTs must be significantly higher than the stability voltage, V s. This is essential so that the operating current through the relay is a sufficient multiple of the applied current setting. Ideally a ratio of V K ≥5Vs would be appropriate, but where this is not possible refer to the Advanced Application Requirements for Through Fault Stability. This describes an alternative method whereby lower values of Vs may be obtained. Typical operating times for different V K/Vs ratios are shown in the following table: VK/Vs

12

6

3

2

Typical operating time (ms)

30

40

50

60

These times are representative of a system X/R ratio of 40 and a fault level of 5 Is to 10Is. Lower values of X/R and higher fault currents will tend to reduce the operating time. The kneepoint voltage of a current transformer marks the upper limit of the roughly linear portion of the secondary winding excitation characteristic. This is defined exactly in British practice as that point on the excitation curve where a 10% increase in exciting voltage produces a 50% increase in exciting current. The current transformers should be of equal ratio, of similar magnetising characteristics and of low reactance construction. In cases where low reactance current transformers are not available and high reactance ones must be used, it is essential to use the reactance of the current transformer in the calculations for the voltage setting. Thus, the current transformer impedance is expressed as a complex number in the form RCT + jXCT. It is also necessary to ensure that the exciting impedance of the current transformer is large in comparison with its secondary ohmic impedance at the relay setting voltage. In the case of the high impedance relay, the operating current is adjustable in discrete steps. The primary operating current (Iop) will be a function of the current transformer ratio, the relay operating current ( Ir), the number of current transformers in parallel with a relay element (n) and the magnetising current of each current transformer (Ie) at the stability voltage (Vs). This relationship can be expressed as follows: Iop

= (CT ratio) x (Ir + nIe)(3)

In order to achieve the required primary operating current with the current transformers that are used, a current setting ( Ir) must be selected for the high impedance relay, as detailed above. The setting of the stabilising resistor (R ST) must be calculated in the following manner, where the setting is a function of the relay ohmic impedance at setting (R r), the required stability voltage setting (Vs) and the relay current setting ( Ir). RST =

Vs Ir

 Rr (4)



Note: The auxiliary powered KCGG ohmic impedance over the whole setting range is small, 0.06Ω (1A) and 0.006Ω (5A) and so can be ignored. Therefore: RST =

Vs

(5)

Ir

5.10.1 Use of metrosil non-linear resistors When the maximum through fault current is limited by the protected circuit impedance, such as in the case of generator differential and power transformer restricted earth fault protection, it is generally found unnecessary to use non-linear voltage limiting resistors (Metrosils). However, when the maximum through fault current is high, such as in busbar protection, it is more common to use a non-linear resistor (Metrosil) across the relay circuit (relay and stabilising resistor). Metrosils are used to limit the peak voltage developed by the current transformers, under internal fault conditions, to a value below the insulation level of the current transformers, relay and interconnecting leads, which are able to withstand 3000V peak. The following formulae should be used to estimate the peak transient voltage that could be produced for an internal fault. This voltage is a function of the current transformer kneepoint voltage and the prospective voltage that would be produced for an internal fault if current transformer saturation did not occur. Note, the internal fault level, I'f , can be significantly higher than the external fault level, If , on generators where current can be fed from the supply system and the generator. Vp = 2 2VK (Vf  VK)

(6)

Vf = I'f (RCT + 2RL + RST + Rr)

(7)

where

Vp

=

peak voltage developed by the CT under internal fault conditions.

Vk

=

current transformer knee-point voltage.

Vf

=

maximum voltage that would be produced if CT saturation did not occur.

I

'f

=

maximum internal secondary fault current.

RCT

=

current transformer secondary winding resistance.

RL

=

maximum lead burden from current transformer to relay.

RST

=

relay stabilising resistor.

Rr

=

Relay ohmic impedance at setting.

When the value of V p is greater than 3000V peak, non-linear resistors (Metrosils) should be applied. These Metrosils are effectively connected across the relay circuit, or phase to neutral of the ac buswires, and serve the purpose of shunting the secondary current output of the current transformer from the relay circuit in order to prevent very high secondary voltages. These Metrosils are externally mounted and take the form of annular discs, of 152mm diameter and approximately 10mm thickness. Their operating characteristics follow the expression: V = CI0.25

(8)

where

=

V

Instantaneous voltage applied to the non-linear resistor (Metrosil)



C

=

constant of the non-linear resistor (Metrosil)

I

=

instantaneous current through the non-linear resistor (Metrosil)

With a sinusoidal voltage applied across the Metrosil, the RMS current would be approximately 0.52x the peak current. This current value can be calculated as follows: Vs(rms) x 2 I(rms) = 0.52 C

4

(9)

where Vs(rms) = rms value of the sinusoidal voltage applied across the Metrosil. This is due to the fact that the current waveform through the Metrosil is not sinusoidal but appreciably distorted. For satisfactory application of a non-linear resistor (Metrosil), it’s characteristic should be such that it complies with the following requirements: At the relay voltage setting, the non-linear resistor (Metrosil) current should be as low as possible, but no greater than approximately 30mA rms for 1A current transformers and approximately 100mA rms for 5A current transformers. The metrosil units normally recommended for use with 1A CTs are as follows: Stability voltage

Recommended metrosil type

Vs (V) rms

Single pole

Triple pole

Up to 125V

600A/S1/S256 C = 450

600A/S3/I/S802 C = 450

125-300V

600A/S1/S1088 C = 900

600A/S3/I/S1195 C = 900

The metrosil units normally recommended for use with 5A CTs and single pole relays are as follows: Secondary

Recommended metrosil type

internal fault

Relay stability voltage, Vs (V) rms

Current (A) rms

50A

Up to 200V

250V

275V

300V

600A/S1/S1213 C = 540/640

600A/S1/S1214 C = 670/800

600A/S1/S1214 C = 670/800

600A/S1/S1223 C = 740/870

100A

600A/S2/P/S1217 600A/S2/P/S1215 600A/S2/P/S1215 600A/S2/P/S1196 C = 470/540 C = 570/670 C = 570/670 C = 620/740

150A

600A/S3/P/S1219 600A/S3/P/S1220 600A/S3/P/S1221 600A/S3/P/S1222 C = 430/500 C = 520/620 C = 570/670 C = 620/740

The single pole Metrosil units recommended for use with 5A CTs can also be used with triple pole relays and consist of three single pole units mounted on the same central stud but electrically insulated from each other. A ‘triple pole’ Metrosil type and the reference should be specified when ordering. Metrosil units for higher stability voltage settings and fault currents can be supplied if required.



5.10.2 The KCGG The KCGG142 is a numerical 3 phase overcurrent and earth fault relay with 3 stages of phase and earth fault protection, I>/Io>, I>>/Io>> and I>>>/Io>>> which can be used for 3 phase differential protection or restricted earth fault (REF) protection. The KCGG122 is a numerical single phase overcurrent and earth fault relay with the same 3 stages of phase and earth fault protection, which can be used for REF protection only. It is recommended that the I> element is used as the main protection element for 3 phase differential protection and the Io> element for restricted earth fault applications. This is because the I>/Io> elements have increased through fault stability compared to the I>>/Io>> and I>>>/Io>>> elements. The I>/Io> elements operate when the Fourier value exceeds the threshold setting and the positive and negative peak values exceed 90% of the threshold setting. The I>>/Io>> and I>>>/Io>>> elements operate when the Fourier derived values exceeds the threshold setting or where the peak of any half cycle exceeds twice the set threshold. Since the differential spill current is likely to contain a dc offset level, the positive and negative peaks will have different amplitudes and so the I>/Io> element is more stable. The time delay characteristic should be selected to be definite time and with a setting of zero seconds. The output relay that is to trip the circuit breakers must be allocated in the relay masks for t>A, t>B and t>C. Any relay allocated in these relay masks will dwell in the closed state for a minimum of 100 milliseconds, even if fleeting operation of the protection should occur, ensuring positive operation of the circuit breaker, or trip relay. It is not advised that the start outputs from I> are used because they do not have this in-built minimum contact dwell. Separate output relays may be allocated to each phase trip if it is required to have phase segregated outputs. However, the three relay masks, t>A, t>B and t>C must also be assigned to relay RLY3, for fault records to be generated. Phase information will be included in the fault flags. The Io>>/Io>>>/I>>/I>>> elements not being used should be disabled by setting the phase and earth fault function links PF1, PF2, EF1 and EF2 to 0. Setting ranges of I>/Io> elements are: > 0.08 – 3.2In

I

o> 0.005 – 0.8In

I

The ohmic impedance (Rr) of the auxiliary powered KCGG over the whole setting range is 0.06Ω for 1A relays and 0.006 Ω for 5A relays ie. independent of current. To comply with the definition for a high impedance relay, it is necessary, in most applications, to utilise an externally mounted stabilising resistor in series with the relay. The standard values of the stabilising resistors normally supplied with the relay, on request, are 220Ω and 47Ω for 1A and 5A relay ratings respectively. In applications such as busbar protection, where higher values of stabilising resistor are often required to obtain the desired relay voltage setting, non-standard resistor values can be supplied. The standard resistors are wire wound, continuously adjustable and have a continuous rating of 145W.



5.10.3 Applying the KCGG The recommended relay current setting for restricted earth fault protection is usually determined by the minimum fault current available for operation of the relay and whenever possible it should not be greater than 30% of the minimum fault level. For busbar protection, it is considered good practice by some utilities to set the minimum primary operating current in excess of the rated load. Thus, if one of the current transformers becomes open circuit the high impedance relay does not maloperate. The Io> earth fault element in the KCGG142 with it’s low current settings can be used for busbar supervision. When a CT or the buswires become open circuited the 3 phase currents will become unbalanced and residual current will flow. Hence, the Io> earth fault element should give an alarm for open circuit conditions but will not stop a maloperation of the differential element if the relay is set below rated load. Whenever possible the supervision primary operating current should not be more than 25 amps or 10% of the smallest circuit rating, whichever is the greater. The earth fault element ( Io>) should be connected at the star point of the stabilising resistors, as shown in Figure 9. The time delay setting for the supervision elements (to>) should be at least 3 seconds to ensure that spurious operation does not occur during any through fault. This earth fault element will operate for an open circuit CT on any one phase, or two phases, but not necessarily for a fault on all three when the currents may sumate to zero. The supervision may be supplemented with a spare phase protection stage (I>>>) set to the same setting as the Io> element or its lowest setting, 0.08In, if the Io> supervision setting is less than 0.08In. Note that the Io current should be checked when the busbar is under load. This can be viewed in the Measurements 1 menu in the relay. It is important that the Io> threshold is set above any standing Io unbalance current. The supervision element should be used to energise an auxiliary relay with hand reset contacts connected to short circuit the buswires. This renders the busbar zone protection inoperative and prevents thermal damage to the Metrosil. Contacts may also be required for busbar supervision alarm purposes. It is recommended that the dual powered KCEG242 relay is not used for differential protection because of the start-up time delay when powered from the CTs alone, approximately 200ms. Also, the minimum setting of the phase overcurrent elements, 0.4In, would limit its application for differential protection. Figures 3 to 9 show how high impedance relays can be applied in a number of different situations. 5.10.3.1 Advanced application requirements for through fault stability When Vs from formula 2 becomes too restrictive for the application, the following notes should be considered. The information is based on the transient and steady state stability limits derived from conjunctive testing of the relay. Using this information will allow a lower stability voltage to be applied to the relay, but the calculations become a little more involved. There are two factors to be considered that affect the stability of the scheme. The first is saturation of the current transformers caused by the dc transient component of the fault current and the second is steady state saturation caused by the symmetrical ac component of fault current only.



5.10.3.2 Transient stability limit To ensure through fault stability with a transient offset in the fault current the required voltage setting is given by: Vs = 40 + 0.05RST + 0.04If (RCT + 2RL) (10) If this value is lower than that given by formula 2 then it should be used instead. Vs and RST are unknowns in equation (10). However, for a relay current setting Ir, the value of RST can be calculated by substituting for V s using equation (5), V s = Ir RST. RST Ir = 40 + 0.05RST + 0.04If (RCT+ 2RL)

(11)

5.10.3.3 Steady state stability limit To ensure through fault stability with non offset currents: (RCT+ 2RL) must not exceed (VK + Vs)/If .

(12)

5.10.4 Typical setting examples 5.10.4.1 Restricted earth fault protection The correct application of the KCGG as a high impedance relay can best be illustrated by taking the case of the 11000/415V, 1000kVA, X = 5%, power transformer shown in Figure 10, for which restricted earth fault protection is required on the LV winding. CT ratio is 100/5A. 5.10.4.2 Stability voltage The power transformer full load current 3 = 1000 x 10

3 x 415

= 1391A Maximum through fault level (ignoring source impedance) = 100 x 1391 5

= 27820A Required relay stability voltage (assuming one CT saturated) =

0.5If (RCT + 2RL)

=

0.5 x 27820 5

x 1500 (0.3 + 0.08) =

17.6V



5.10.4.3 Stabilising resistor Assuming that the relay effective setting for a solidly earthed power transformer is approximately 30% of full load current, we can choose a relay current setting, Io> = 20% of 5A ie. 1A. On this basis the required value of stabilising resistor is: V RST = s Ir

= 17.6 1 = 17.6 ohms

5A rated KCGG relays can be supplied, on request, with stabilising resistors that are continuously adjustable between 0 and 47 Ω. Thus, a stabilising resistance of 17.6 Ω can be set using the standard supplied resistor. 5.10.4.4 Current transformer requirements To ensure that internal faults are cleared in the shortest possible time the knee point voltage of the current transformers should be at least 5 times the stability voltage, Vs . VK = 5Vs =

5 x 17.6

=

88V

The exciting current to be drawn by the current transformers at the relay stability voltage, Vs, will be: Ie

<

Is

 Ir n

where Is = relay effective setting = 30 x 1391 x 100

5 1500

= 1.4A ( o>) = relay setting

Ir I

= 1A n = number of current transformers in parallel with the relay =4 ∴ Ie

@ 17.6V <

1.4  1 4

< 0.1A The time delay setting of the to> element should be set to 0s. The Io>>/Io>>>/I>>/I>>> elements not used should be disabled by setting the phase and earth fault function links PF1, PF2, EF1 and EF2 to 0. Note, the phase overcurrent elements not used for restricted earth fault protection could be used to provide normal overcurrent protection.



5.10.4.5 Metrosil non-linear resistor requirements If the peak voltage appearing across the relay circuit under maximum internal fault conditions exceeds 3000V peak then a suitable non-linear resistor (Metrosil), externally mounted, should be connected across the relay and stabilising resistor, in order to protect the insulation of the current transformers, relay and interconnecting leads. In the present case the peak voltage can be estimated by the formula: Vp = 2 2VK (Vf  VK)

where VK = 88V (In practice this should be the actual current transformer kneepoint voltage, obtained from the current transformer magnetisation curve). Vf

=

If

(RCT + 2RL RST + Rr)

=

27820 x

5 x 1500

(0.3 + 0.08 + 17.6) =

92.7 x 17.98

=

1667V

Therefore substituting these values for V K and Vf into the main formula, it can be seen that the peak voltage developed by the current transformer is: Vp

=

2 2VK (Vf  VK)

=

2 2 x 88 x (1667  88)

=

1054V

This value is well below the maximum of 3000V peak and therefore no Metrosils are required with the relay. If, on the other hand, the peak voltage V P given by the formula had been greater than 3000V peak, a non-linear resistor (Metrosil) would have to be connected across the relay and the stabilising resistor. The recommended non-linear resistor type would have to be chosen in accordance with the maximum secondary internal fault current and the voltage setting. 5.10.5 Busbar protection A typical 132kV double bus generating station is made up of two 100MVA generators and associated step-up transformers, providing power to the high voltage system, by means of four overhead transmission lines, shown in Figure 2. The main and reserve busbars are sectionalised with bus section circuit breakers. The application for a high impedance circulating current scheme having 4 zones and an overall check feature, is as follows: The switchgear rating is 3500MVA, the system voltage is 132kV solidly earthed and the maximum loop lead resistance is 4 ohms. The current transformers are of ratio 500/1 amp and have a secondary resistance of 0.7 ohms. 5.10.5.1 Stability voltage The stability level of the busbar protection is governed by the maximum through fault level which is assumed to be the switchgear rating. Using the switchgear rating allows for any future system expansion. =

3500 x 106 = 15300A 3 x 132 x 103



Required relay stability voltage (assuming one CT is saturated) =

0.5 If (RCT + 2RL)

=

0.5 x 15300 (0.7 + 4) 500

=

72V

5.10.5.2 Current setting The primary operating current of busbar protection is normally set to less than 30% of the minimum fault level. It is also considered good practice by some utilities to set the minimum primary operating current in excess of the rated load. Thus, if one of the CTs becomes open circuit the high impedance relay does not maloperate. The primary operating current should be made less than 30% of the minimum fault current and more than the full load current of one of the incomers. Thus, if one of the incomer CTs becomes open circuit the differential protection will not maloperate. It is assumed that 30% of the minimum fault current is more than the full load current of the largest circuit. Full load current 3 = 100 x 10 = 438A

3 x 132

5.10.5.3 Discriminating zone Magnetising current taken by each CT at 72V = 0.072A Maximum number of CTs per zone = 5 Relay current setting, Ir(I>) = 400A = 0.8In Relay primary operating current, = CT ratio x (Ir + nIe) Iop =

500 x (0.8 + (5 x 0.072))

=

500 x 1.16

=

580A (132% full load current)

5.10.5.4 Check zone Magnetising current taken by each CT at 72V = 0.072A Maximum number of circuits = 6 Relay current setting, Ir (I>) = 0.8A Relay primary operating current, Iop

=

500 x (0.8 + (6 x 0.072))

=

500 x 1.232

=

616A (141% full load current)



Therefore, by setting Ir (I>) = 0.8A, the primary operating current of the busbar protection meets the requirements stated earlier. 5.10.5.5 Stabilising resistor The required value of the stabilising resistor is: RST

= Vs Ir

= 72

0.8

= 90Ω Therefore the standard 220Ω variable resistor can be used. 5.10.5.6 Current transformer requirements To ensure that internal faults are cleared in the shortest possible time the knee point voltage of the current transformers should be at least 5 times the stability voltage, Vs. Vk/Vs = 5 Vk

= 360V

5.10.5.7 Metrosil non-linear resistor requirements If the peak voltage appearing across the relay circuit under maximum internal fault conditions exceeds 3000V peak then a suitable non-linear resistor (Metrosil), externally mounted, should be connected across the relay and stabilising resistor, in order to protect the insulation of the current transformers, relay and interconnecting leads. In the present case the peak voltage can be estimated by the formula: Vp = 2 2VK (Vf  VK)

where VK = 360V (In practice this should be the actual current transformer kneepoint voltage, obtained from the current transformer magnetisation curve). Vr

= I'f (RCT + 2RL + RST + Rr) 1

= 15300 x 500 x (0.7 + 4 + 90) = 30.6 x 94.7 = 2898V Therefore substituting these values for V K and Vf into the main formula, it can be seen that the peak voltage developed by the current transformer is: Vp

= 2 2VK (Vf  VK) = 2 2 x 360 x (2898  360) = 2704V

This value is below the maximum of 3000V peak and therefore no Metrosils are required with the relay. If, on the other hand, the peak voltage V P given by the formula had been greater than 3000V peak, a non-linear resistor (Metrosil) would have to be connected across the relay and the stabilising resistor. The recommended non-linear resistor type would have to be chosen in accordance with the maximum internal fault current and the voltage setting.



5.10.5.8 Busbar supervision Whenever possible the supervision primary operating current should not be more than 25 amps or 10% of the smallest circuit, whichever is the greater. The Io> earth fault element in the KCGG142 with its low current settings can be used for busbar supervision. Assuming that 25A is greater than 10% of the smallest circuit current. o> = 25/500 = 0.05In

I

Using the I>>> element for 3 phase busbar supervision >>> = 0.08In (minimum setting)

I

The time delay setting of the to> and t>>> elements, used for busbar supervision, is 3s. The Io>>/Io>>>/I>> elements not used should be disabled by setting the phase and earth fault function links PF1, EF1 and EF2 to 0. 5.10.5.9 Advanced application requirements for through fault stability The previous busbar protection example is used here to demonstrate the use of the advanced application requirements for through stability. To ensure through fault stability with a transient offset in the fault current the required voltage setting is given by: Vs = 40 + 0.05RST + 0.04IF(RCT+ 2RL) If this value is lower than that given by formula 2 then it should be used instead. To ensure through fault stability with non offset currents: (RCT+ 2RL) must not exceed (VK + Vs)/If . 5.10.5.10 Transient stability limit Vs = 40 + 0.05 RST + 0.04 x 15300/500 (0.7 + 4) Vs = 45.753 + 0.05 RST Vs =

Ir

RST

The relay current setting,

Ir

= 0.8In

0.8 RST = 45.753 + 0.05 RST RST = 61Ω Vs = 0.8 x 61 = 48.8V Steady state stability limit (RCT + 2RL) < (VK + Vs)/IF. Assuming VK = 5 Vs (6 x 48.8)

(0.7 + 4) < (15300/500) 4.7 < 9.57 Thus, the steady state stability requirement is met.



VK = 5 Vs = 244V Using the advanced application method the knee point voltage requirement has been reduced to 244V compared to the conventional method where the knee point voltage was calculated to be 360V. 100MVA 15kV

100MVA 132/15kV

132kV Main reserve

Figure 11: Double busbar generating station.

A B

P1

P2

S1

S2

Protected plant

C

P1

P2

S1

S2

A B C

21 RA Protective relays 22 v RST

23 RB 24

v RST

25 RC 26

v R ST

Figure 12: Phase and earth fault differential protection for generators, motors or reactors. P1

P2

S1

S2

A B C

27 P2

S2

28 R

RST

v P1

S1

Figure 13: Restricted earth fault protection for 3 phase, 3 wire system-applicable to star connected generators or power transformer windings.



P1

P2

S1

S2

A B C

27

28 R RST

v

Figure 14: Balanced or restricted earth fault protection for delta winding of a power transformer with supply system earthed. P2

P1

S2

S1

A B C

P2

P1

S2

S1

27

N

28 R RST v

Figure 15: Restricted earth fault protection for 3 phase, 4 wire system-applicable to star connected generators or power transformer windings with neutral earthed at switchgear. P2

P1

S2

S1

A B C

P2

P1

S2

S1

27 P2

S2

P1

S1

N

28 R RST v

Figure 16: Restricted earth fault protection for 3 phase, 4 wire system-applicable to star connected generators or power transformer windings earthed directly at the star point.


A B


P1

P2

S1

S2

P1

P2

S1

S2

P2

P1

S2

S1

A B

C

C

21 RA Protective relays 22 v RST

23 RB 24

25 RC

v RST

26

RST

v

Figure 17: Phase and earth fault differential protection for an auto-transformer with CTs at the neutral star point. P1

S1

P2

S2

A B C P2

S2

P2

S2

P1

S1

P1

S1

A B C 21 RA v

Contacts from buswire supervision auxiliary relay

Protective relays 22

23 RB 25 RC v v 24 26 RST RST RST 27 Buswire RN supervision 28

Figure 18: Busbar protection – simple single zone phase and earth fault s cheme. 11kV

1500/5A

415V

A RCT

B C

RL

RL

RL Data Protection: RL = 0.04ý RLC = 0.3ý Transformer: X

= 5%

RCT

Restricted earth fault protection

RL

Figure 19: Restricted earth fault protection on a power transformer LV winding.



Rectifier protection

A

+

B

Ð

C A

B

C

N

Rectifier

Transformer

Rs

Protection

Figure 20: Protection for silicon rectifiers 10000 Typical thermal limit for silicon rectifier

1000 ) s d n o c e s ( e m i T

Protection curve 100

Instantaneous overcurrent

10 Typical load area

1

0.1 1

2

3

4

5

6

7

8

Multiple of rated current

Figure 21: Matching curve to load and thermal limit of rectifier

The rectifier protection feature has been based upon the inverse time/current characteristic as used in the MCTD 01 and the above diagram shows a typical application. The protection of a rectifier differs from the more traditional overcurrent applications in that many rectifiers can withstand relatively long overload periods without damage, typically 150% for 2 hours and 300% for 1 min. The relay I> setting of the relay should be set to the rated rms value of the current that flows into the transformer when the rectifier is delivering its rated load. The relay will give a start indication when the current exceeds this setting but this is of no consequence because this function is not used in this application. Curve 9 should be selected for the inverse time curve and this cuts-off for currents below 1.6 times allowing the rectifier to carry 150% overload for long periods. If this is not acceptable the I> setting can be adjusted to move the cut-off point relative to the current scale. The operation time can be modified by adjustment of the time multiplier setting (TMS) so that it lies between limiting characteristic of the rectifier and the allowable load area.



Typical settings for the TMS are: Light industrial service

TMS = 0.025

Medium duty service

TMS = 0.1

Heavy duty traction

TMS = 0.8

The high set is typically set at 8 times rated current as this ensures HV AC protection will discriminate with faults covered by the LV protection. However, it has been known for the high set to be set to 4, or 5, times where there is more confidence in the AC protection. Use of the thermal element to provide protection between 70% and 160% of rated current could enhance the protection. It is also common practice to provide restricted earth fault protection for the transformer feeding the rectifier. See the appropriate section dealing with restricted earth fault protection. 5.12

Cold load pick-up The Cold Load Pick-up (CLP) feature enables the settings of the relay to be changed to cater for temporary overload conditions that may occur during cold starts, such as switching on large heating loads after a sufficient cooling period, or any load that takes a high initial starting current. Initiation of CLP is usually by an auxiliary contact of the circuit breaker that is closed when the circuit breaker is in the open state. This would be used to energise a logic input that would be allocated in mask [0A0C Aux3]. If a logic input is already available to indicate the circuit breaker open status, it can be allocated in more than one mask; it would not be necessary to use an additional logic input. For short duration starting loads it may only be necessary to delay the short time protection functions. Allocating a relay in output mask [0B12 Aux3] and energising a logic input via its contacts. The logic input can then be allocated in the appropriate input masks to block the short time overcurrent elements. Alternatively setting link LOGB = 1 gives timer tAUX3 a delay on drop-off, when it can be used to select group 2 settings. Then, with the appropriate preset settings applied, the protection levels can be raised above starting currents and held there for the time set on tAUX3, after which they return to their normal values. To select this mode of operation set link [LOG5] = 1 and [SD4]=1. Group 2 settings will be in operation when tAUX3 is energised, that is before the load comes on and for the set time for tAUX3 after the circuit breaker closes. See also the section entitled “SETTING GROUPS” which explains the alternative methods by which group 2 settings can be selected. This latter arrangement is useful when there are no spare output relays and can be used as an alternative means of blocking the short time elements without using external connections. To achieve it, the elements that are set to a short time must be deselected in the group 2 settings, or preferably given a higher setting. This is possible for elements t>>; t>>>; to>> and to>>>. If delayed initiation is required, allocate the logic input in mask [0A0B Aux2] instead of [0A0C Aux3]; set link [LOG6] =1 and set the required delay on tAUX2. For retrofit installations where an auxiliary circuit breaker contact is not available, undercurrent initiation via tAUX2 may be used. It is possible to set tAUX2 to zero if no initial delay is necessary.



The above change of setting group can also be enabled if a 52B contact is not available, or during instances when the operation of upstream circuit breakers will cut the supply without opening the down-stream circuit breakers. This is achieved by using the loss of load feature associated with tAUX2 and by setting [LOG6] =1. The time delay of the tAUX2 when used in this configuration must be set longer than the total fault clearance time of the system. Note: It will be essential to check for correct resetting of any function that is deselected when switching to group 2 settings. e m i T

Stall (CLP) O v er l o a d ( CL P ) t>

Stall

t>>

O v e r l oa d

Short circuit t>>>

I >

I >>

I >>>

Current

Figure 22: Compensation for motor starting current

Section 6. DIRECTIONAL OVERCURRENT I

Zone of forward start forward operation

Is

¯cÐ90

¯c ÐI s

Reverse start

ÐI

Figure 23: Directional characteristic

¯c+90



Phase fault directional elements are polarised by the quadrature phase/phase voltage, and the earth/ground fault elements are polarised by the zero sequence voltage. The directional part of the measurement includes a threshold value on the polarising quantity, and for phase fault measurement this threshold is fixed. However for earth/ground faults an adjustable threshold is provided to allow a setting above any imbalance in the zero sequence polarising signal to be applied. Control is provided for adjustment of the characteristic angle of the relay. The directional decision is applied after the current threshold and before the following associated time delay. The directionalisation of any element can be selectively overridden by adjusting software links in the relay menu to a suitable setting. The undercurrent element I< is the exception since this element is not provided with directional control. 6.1

Directional overcurrent logic The logic, shown in Figure 24, provides directional control for stage 1, 2 and 3 overcurrent elements in the forward direction and start indication in both the forward and reverse direction. The forward direction will usually be for current flowing from the busbar to the feeder. KCEG 142 and KCEU 142 relays only, are supplied with additional links PFE and EFE. They enable the direction of the third overcurrent and earth fault stages to be reversed. There is also the option to select 2/3 logic for all phase trip and start outputs, by setting link PFF = 1. The 2/3 logic requires more than one phase to operate before an output is given. These features may not be found in the very first models manufactured.

6.2

Directional start output When the current threshold I> is exceeded and the polarising signal is above the threshold Vp>, an output is directed to the [0B06 I> Fwd] mask for forward current flow and to the [0B07 I> Rev] for reverse current flow. A non-directional start can be obtained by allocating the same output relay in both start masks so that it operates for forward or reverse current flow. If all three elements are selected to be non directional (links PF3, PF4 and PF5 set to ‘0’) then the forward start will become a non-directional start, but the reverse start will retain its directionality (on the series 1 relays, KCEG110/130/140/150, the reverse start was inhibited when all three elements were selected to be non directional).

6.3

Directional first stage overcurrent If link PF3=0 the time delay t> will start timing when the current exceeds the I> setting to give a non-directional trip via the appropriate relay mask [0B08 tA>], [0B09 tB>], or [0B0A tc>]. With link PF3 set to “1” the time delay will only run if the current exceeds the I> threshold and is in the forward direction. External control is asserted via input mask [0A04 Blk t>] and when this input is energised the time delay is reset to zero after the reset delay (tRESET).



Directional second and third overcurrent stages Elements I>>/t>> and I>>>/t>>> can also be selectively directional, or nondirectional. To directionalise them links PF4 and PF5 respectively, should be set to ‘1’. If these links are set to ‘0’ then the elements will be non-directional. The delay has a definite time characteristic for these elements, which can be blocked via the appropriate input mask [0A05 Blk I>>] and [0A06 Blk I>>>]. There are no start functions associated with these two elements.

6.5

Directional earth fault logic The logic for the earth fault element is similar to that described for phase faults. An independent set of software links, input masks and relay masks are provided to give optimum flexibility to the user.

6.6

Application of directional phase fault relays It is normal practice to set the characteristic angle of the relay ( φc) to the angle between the prospective fault current and the polarising voltage. A fault will then lie at the centre of the directional characteristic. For a three phase fault the fault current will normally lag the phase voltage by an angle of 45° to 60°. However the polarising voltage is the quadrature line voltage, which lags the phase voltage by 90°. Thus if the fault current lags the phase voltage by an angle (– φ), the angle difference with respect to the polarising voltage will be (90° – φ). Thus characteristic angle setting for the relay will be the phase angle of the fault current with respect to the polarising voltage. Thus φc = (90° – φ) and so for a fault angle of –60° the setting for φc will be +30°. K Range series 2 relays have the range for the characteristic angle setting increased to ±180°, so that it is possible to reverse the direction of operation. For the above example the characteristic angle setting is +30° for operation when current flows from the busbar to the feeder, so for operation when current flows from the feeder to the busbar the characteristic angle must be shifted by 180°. Thus for operation in the reverse direction φc = –(90 + φ) = –150°. The minimum operating value of the voltage input to the directional overcurrent relay should be as low as practicable from the aspect of correct directional response of the relay itself. This follows because of the important requirement for the relay to achieve correct directional response during a short circuit fault close to the relay when the voltage input can be below 1% of rated value. Furthermore, there is no restriction on the minimum operating value from the aspect of the power system or voltage transformer performance. Hence the threshold for the phase fault elements of the KCEG relays has been set at 0.006Vn.

6.7

Synchronous polarisation The phase directional elements are polarised by the quadrature line voltage, referred to a cross polarisation, they will always have a polarising signal for closeup phase to phase faults. However, for close-up three phase faults the polarising voltage may be lost completely and synchronous polarising is then used. The phase angle of the line voltages with respect to the sampling frequency is measured for each cycle and the last value measured is stored in memory. When the polarising signal is lost the last stored phase reference for the voltage is used for the directional decision. The phase angle of the current relative to the sampling frequency is measured and from this is subtracted the stored phase angle of the polarising voltage to give the phase angle of the current with respect to the


t l u a f h t r a e 1 e g a t S




0 0 T R 1 1 A T 2 2 S V 3 3 E R 4 > 4 > > o o 5 t I 5 2 6 4 6 0 0 B 7 B 7 0 0

0 1 2 3 > > 4 > o t 5 5 6 0 B 7 0

t l u a f h t r a e t r a t S

t n e r r u c r e v o 1 e g a t S

t n e r r u c r e v o 2 e g a t S

t n e r r u c r e v o t r a t S

t r n e o r t r c u u c r d n e v o c o 3 n e k e g o r a B t s

Ð 0 T R 1 A T 2 S D 3 W F 4 > o 5 I 1 6 0 B 7 0

0 1 2 3 > 4 o t 5 3 6 0 B 7 0

&

0 1 2 3 > 4 A t 5 8 6 0 B 7 0

0 1 2 3 > 4 C t 5 A 6 0 B 7 0

0 1 2 3 > 4 B t 5 9 6 0 B 7 0

0 T R 1 A T S 2 D 3 W F 4 > 5 6 6 0 B 7 0 I

I

& & & &

&

0 1 2 3 > 4 > t 5 B 6 0 B 7 0

0 T R 1 A T 2 S V 3 E R > 4 5 7 6 0 B 7 0

0 1 2 3 > > 4 > t 5 C 6 0 B 7 0

&

F F P 0 1 F F F F F P 0 1 F P 0 1 F P 0 1 F P 0 1

1 2 ≥ ≥

5 F 0 1 E

> o t

> > > o t

> > o t

1 2 ≥ ≥

1 2 ≥ ≥

1 2 ≥ ≥

1 2 ≥ ≥

> > t

> > > t

&

&

4 F P 0

5 F P 0

5 F P 0 1

> t 4 0 1 F E

&

7 F P 0 1

4 F P 0 1

&

3 0 1 F E

&

&

5 F E 0 1

4 0 1 F E

3 F P 0 1

1

E F 0 1 E 0 1 2 > o 3 t K L 4 B 5 1 6 0 A 7 0

> o I

D V 0 E W R F 1 > 2 > o 3 t K L B 4 5 2 6 0 A 7 0

0 D 1 W F > > 2 > o 3 t K L B 4 5 > 3 6 > 0 o A 7 0 I

1 F 1 E 0

+

D V E W R F > > > o I

2 F 1 E 0

1

1 ≥ E F P 0

0 1 2 > 3 t K L 4 B 5 4 6 0 A 7 0

D V E W F R

> I

0 1 2 > > 3 t K L 4 B 5 5 6 0 A 7 0

D W F

> > I

1 0 1 F P

&

0 1 > 2 > > 3 t K L 4 B 5 < 6 6 0 A 7 0 I

C 0 1 F P

D V W F E R

> > > I

2 0 1 F P

1

c i g o l y a l e r t n e r r u c r e v o l a n o i t c e r i D : 4 2 e r u g i F



polarising voltage and this is compared with the set operational angle limits for operation. Because the relay tracks the frequency the stored phase reference for the voltage holds good even though the frequency may drift during the fault and hence the term synchronous polarisation. The duration of the synchronous polarisation is 320ms, but an option is now provided to extend this to 3.2s to allow operation of the IDMT element. The duration is selected with link [PFB]. For PFB=0 duration is 320ms and for PFB=1 duration it is increased to 3.2s. The longer duration will be useful when fault current is limited and the operation time of the relay is expected to be relatively slow for close-up faults. 6.8

Application of directional earth fault relays The earth fault elements use the residual voltage as the polarising quantity. With the KCEG 142/242 relays this voltage is internally derived from the three phase/neutral voltages applied to the relay. With the KCEG 112/152 this voltage has to be externally derived from an open delta winding on the line voltage transformers, or via star/open delta interposing voltage transformers. Note that the KCEU 142/242 relays measure residual voltage by means of an internal resistor network and VT. However, the external VT connections to the relay are the same as those for the KCEG 142/242 relays, namely three phase and one neutral connection. This is therefore applicable where a suitable star connected VT winding is available. However, for applications where there is only a broken delta winding available to polarise the relay, this is accommodated by connecting the relay as shown in Figures 21 and 22, Appendix 3. From this figure it can be seen that the residual voltage must be applied between one phase voltage input and neutral, ensuring that the remaining two phase voltage inputs are tied down to neutral. It is important that these two connections are not left floating, as an incorrect residual voltage measurement would result. The characteristic angle will be directly as marked for earth faults and lagging angles of between 0° to –60° may be used as appropriate, dependent on the system earthing arrangements. When providing sensitive earth fault protection for an insulated system a core balance transformer is recommended. Where this is oriented as for an earthed system ie. with the relay looking down the feeder, the relay characteristic angle should be set to +90°. If the current transformer is reversed, anticipating capacitive current flow from the feeder onto the busbar, –90° should be used. In such applications, relatively sensitive current settings will be required for the directional earth fault relay. The standard setting range of the earth fault elements in the KCEG relay models goes down to 0.5% of rated current. If settings more sensitive than this are required, the KCEG 112 and KCEG 152 models can be supplied with a setting range matching that of the KCEU models, namely, down to 0.1% of In. For complete details on available setting ranges, refer to Technical Data section Chapter 7. More detailed information regarding application of the KCEG 112/152 relays to insulated systems, is available in a separate application guide, reference R6554. Where a directional relay is used to prevent sympathetic tripping of the earth fault overcurrent element, which would otherwise result from the currents flowing via the cable capacitance to earth, an angle setting of +45°(lead) is recommended.



For earth faults the minimum operating value of the residual voltage input to the directional earth fault relay is determined by power system imbalance and voltage transformer errors. The zero sequence voltage on a healthy distribution system can be as high as 1.0%, also the voltage transformer error can be 1.0% per phase which results in a possible spurious residual voltage as high as 2.0% under healthy conditions. In order to take account of both of the foregoing quantities and thus eliminate unwanted relay operation it is necessary to introduce a minimum operating value of up to 3.5%. In practice, a choice of settings of say 2.0% to 4.0% should be considered, with perhaps 10% and 20% for high resistance and insulated neutral systems respectively. The setting for Vop> will be found in the EARTH FAULT setting column of the menu and should be set appropriately, taking the above notes into account. Note: The KCEG 140 required a residual voltage in excess of 6%Vn before the voltage threshold circuit would function, regardless of the Vop> setting. With the KCEG 142/242 the sensitivity of this circuit has been improved to less than 0.6%Vn. For protection of arc suppression (Petersen) coil earthed systems, a sensitive current setting is required to enable accurate detection of the relatively small currents flowing under fault conditions. Angles in the region of +5°(lead), 0°, –5°(lag) are common, with the relays having suitably fine setting adjustment of 1°. 6.9

Power directional earth fault element An alternative option for arc suppression (Petersen) coil earthed systems is provided by the KCEU 142/242 relays. These relays operate when the power measured in the residual circuit exceeds the power setting (Po>). Power is measured in watts and is equal to V Icosφ. Po> Thus for operation the residual current must exceed before it can operate. Vo cosφ The residual current required to operate the relay is high when there is little residual voltage. By virtue of this feature the relay effectively ignores any residual spill current, resulting from mismatch of the line CTs, due to the fact that there is negligible zero sequence voltage present under load conditions. The power characteristic is relative to the set characteristic angle (fc), which will typically be set to 0°. To reverse the direction of operation the characteristic angle is changed by ±180°. Note: If the power setting Po> = 0, then the normal directional characteristic will be operative instead of the power characteristic. More detailed information regarding the application of the KCEU 142,242 relays to Petersen Coil Earthed systems, is available in a separate application guide, reference R6554.

6.10

Directional stability for instantaneous elements Directional relays are required to withstand a fault in the reverse direction without operating. In addition they are required to remain stable (ie. not operate) when the reverse fault current is removed and the current falls to zero, or to a level that is below the current setting of the relay and in a forward direction. With time delayed protection, directional stability is not usually a problem, but with directionalised instantaneous overcurrent relays it is much more difficult to achieve and momentary operation may occur when the fault is removed.



The software of the K Range relays has been arranged to reduce transient operation to a minimum, but even so it is advisable to set the associated time delay for any directional overcurrent element to between 40ms and 200ms, depending on the system X/R ratio and the maximum fault level, to ensure stability under this condition. For a two phase to earth fault, close to the operating boundary, one definite time phase element may give a directional decision that is different to the other two and could be considered to be incorrect. To eliminate the protection performing in a way that is not expected a better decision can be made by setting link PFF = 1 to activate the 2/3 logic on both the trip and start outputs. Earth fault protection will then be essential to clear single phase faults. This was not a problem with directionalised IDMT protection because of its inherent current/time characteristic. 6.11

Protection of circuits with multiple in-feeds For the blocked overcurrent protection to be applied to a feeder that can be fed from either end, or a busbar with multiple in-feeds, a directional feature must incorporated. The START elements of any relay that detects current flowing from the protected zone must block the operation of any relays that detect current flowing into the protected zone. The directional feature is used to establish if the current is flowing into, or out of, the protected zone. The principle can be applied to the protection of busbars, parallel feeders, as shown in the following example, and it is also suited to ring circuits to simplify grading problems. The following diagram shows a busbar with several feeders connected to it and divided by a bus section circuit breaker. The dotted lines indicate the zones of protection that can be formed using short time overcurrent protection arranged in a blocked overcurrent scheme. The basic IDMT protection is still applied in the traditional fashion, but is now augmented by the additional overcurrent elements within the feeder protection arranged to provide unit protection for both their associated feeder the bus section to which the feeder is connected. Incomer

Incomer

KCEG 142

KCEG 142

KCEG 142

Feeder 1

KCEG 142

KCEG 142

Feeder 2

Figure 25: Circuit with multiple infeeds

KCEG 142

KCEG 142

Feeder 3

Feeder 4



6.11.1 Blocked directional overcurrent protection Because the busbar is divided by a circuit breaker an extra directional overcurrent relay is required to divide the protection into a separate zone for the bus sections. The standard connections used for the relays connected to each feeder is such that the forward start relays operate for fault current flowing from the busbar to the feeder and the reverse start for fault current flowing towards the busbar. For the bus section relay the forward start operates for current flowing from the left hand to the right hand bus section. 6.11.2 Blocked overcurrent protection for the feeder The KCEG 142 relays will usually be arranged to protect the feeder and the forward direction will then be for current flow from the busbar to the feeder. The current threshold for the I>>/Io>> element would be set above any transient loads. They can be prevented from overreaching the ends of the feeder and operating for faults beyond the busbars, by applying the blocked directional overcurrent principle. This forms a unit protection scheme for the feeder and can be useful when the normal time grading steps are not possible. Set links PF4 = 1 and EF4 = 1 for these elements to be directionalised, so that they will not operate for faults on the busbar behind them. Then to prevent them overreaching the remote busbar the reverse start contact of the relay at the other end of the line is arranged to block the t>>/to>> time delays via a logic input. For a fault on the feeder, current will only be seen to flow in the forward direction, into the feeder, and so the protection will operate. This arrangement is also tolerant to high transient loads, so allowing the short time elements to be set closer to the load current. 6.11.3 Blocked overcurrent protection for the bus section The circuits connected to the left hand bus section in Figure 25 are the incomer, feeders 1 & 2 and the bus section. The I>>>/Io>>> elements of each relay may be used to form the blocked directional overcurrent protection for this application. The I>>>/Io>>> elements shall be directionalised by setting function links PF5 = 1 and EF5 = 1. The forward direction for these relays will be for current flowing from the bus zone to a feeder, so it will be necessary to reverse the direction of operation for the third stage by setting links PFE = 1 and EFE = 1. The forward start contacts from each relay are used to define the boundary of the bus zone. To do this, the forward start contacts of each relay connected to a zone are connected in parallel across a pair of buswires and arranged to block the operation of both the t>>>/to>>> time delays of each relay when current flows from the busbar by any legitimate path. Thus if fault current flows away from the busbar the overcurrent protection is blocked and if current flows towards the busbar and does not flow away down any other legitimate circuit the busbar overcurrent protection operates to clear the fault. Previous notes on this application referred to the use of a non directional element to cover the bus zone. However, based on experience we now recommend the use of directional elements for improved stability. Stability can be further improved by applying 2/3 logic to all phase fault start and trip outputs. However, operation of the earth fault element will then be essential to cover single phase faults and for solidly earthed systems the zero sequence voltage should be calculated to ensure that there is sufficient to operate the relay at the minimum fault current.



Application of Midos K Range relays for single and double busbar protection is further described in publications R4112 and R4114. Note: The response of directional overcurrent relays to power system disturbances will vary with the earthing arrangements. It is not practical to consider all configurations of the power system and so the application notes in this document can only be a general guide. Each application will need to be engineered to suit the system.

Section 7. THERMAL OVERCURRENT The thermal overload protection shares the time constant setting with the thermal ammeters and thus a compromise will be necessary if they are to be used at the same time. It is recommended that the time constant is chosen to suit the protection in such instances. The settings for the time constant (TC), the continuous thermal current rating (Ith>) and the thermal alarm (th>) will be found in the menu columns containing the phase fault settings. The time constant can be set between 1 minute and 120 minutes in 1 minute steps and the thermal current setting ( Ith>) can be adjusted between 0.08In and 3.2In. The thermal protection responds to I2 and will operate faster as the current increases, but for currents in access of 5.3 times rated current the operation time will remain the same as that for 5.3 times rated current. This will not be a problem in practice because the normal IDMT, or definite time, protection will normally have taken over at a lower level of current. 0 1 PF0

1

≥

Alarm

1

≥

Trip Thermal reset

0A11 RESET I th 7 6 5 4 3 2 1 0

0B17 th ALARM 7 6 5 4 3 2 1 0 0B18 th TRIP 7 6 5 4 3 2 1 0

Figure 26: Thermal alarm and trip logic

7.1

Thermal state In simplified terms the thermal state is a percentage thermal current limit that has been attained by the thermal replica. The thermal state will be found under MEASURE 3 in cell 0407 and can be displayed on the front of the relay by viewing this cell or selecting it from the default display. The thermal state =

I2[1-e-t/T]/[Ith>]2

Final value of thermal state =

x 100 = %Ith>

[highest thermal ammeter reading]2 [continuous thermal current

limit] 2

x100%

The thermal state will tend to 100% when the highest of the three thermal ammeters is displaying a current equal to the set thermal current limit ( Ith>). The time to reach 100% will depend upon: Applied current Prefault load current Thermal time constant Continuous thermal rating



Thermal trip and alarm levels A thermal trip will be given via the output mask [0B18 th Trip] when the thermal state reaches 110%. This is equivalent to the current being in excess of 1.05 Ith>. It should be noted that the thermal trip will remain asserted until the replica cools and the thermal state falls below the trip level. In addition an alarm setting can be set for a thermal state between 0% and 110%. When this threshold is exceeded an output can be obtained via the alarm output mask [0B17 th Alarm].

7.3

Operation time The operation time characteristic is given by he following expression: t = T.LOGe

Ix

2

ÐP 2 Ix Ð 1.10

where t T Ix P P

= time in minutes = selected time contstant = current in multiples ( Ith>) = (per unit of prefault load)2 = (IL/Ith>)2

The characteristic curves will be found in the appendix to this document where the times are shown as a multiple of the selected time constant for various levels of prefault load. 7.4

Thermal memory When the auxiliary energising supply is lost the thermal state is stored in non volatile memory. On restoration of the supply the thermal state is restored. However, if the stored value of the thermal state is in excess of 90%, the restored thermal state will be set to 90%.

7.5

Thermal reset The thermal state can be reset to zero after the password has been entered by performing a reset function on cell [0407 Thermal] under MEASURE 3. This can be achieved via the user interface of the relayby pressing the reset key [0] for one second whilst this cell is displayed, or by a 'reset cell' command via the serial port. However, this cell is protected and the password must be entered before it can be reset. Alternatively, the thermal state can be reset by energising a logic input that has been allocated in the input mask [0A11 RESET th]. All input masks are password protected against change, but once a logic input has been assigned to this function it is not necessary to enter the password again before the reset function can respond to this input being energised. Note: The thermal state cannot be reset whilst viewing cell 0407 from the default display. If the thermal state is greater than 90% it will be reset to 90% after a break in the auxiliary supply. If link PF0 = 0 in either setting group, then the thermal state will not reset to zero when that group is selected. If the thermal protection is not to be used



the thermal state should be manually reset to zero to clear the memorised state. 7.6

Dual time constant characteristics It is possible to set different time constants in setting group 1 and 2 and so produce dual characteristics with dual time constants in a similar way to the composite curves described in Section 4.8. For such an application the setting group will be arranged to change in response to the current exceeding one of the current thresholds I>> or I>>>.

7.7

Application of thermal protection The thermal protection characteristic can be used to protect electrical equipment in such a way that the full thermal capacity is utilised with due regard to the thermal inertia, but in a manner that prevents unacceptable temperatures from being attained. It can be applied to standard high voltage cables with natural cooling and to dry type power transformers. The setting (Ith>) should be set to the maximum continuously rated current for the protected item of plant. If the current transformer (CT) ratio has been entered then this will be in primary quantities, but if the CT ratio has been set to 1:1 then the continuous rated current entered should be that referred to the secondary winding of the CT. The appropriate thermal time constant (T) must be entered and the following table gives some suggested values for typical cables. The curves for the thermal characteristic are to be found in the appendix to this document and it will be seen that they take due account of the pre-load current. The typical values of time constants in the following table are paper insulated lead sheathed cables, or polyethylene insulated cables laid above ground or in conduits. Rated voltage of cable

Conductor cross section (mm)2

6 to 11kV T minutes

22kV T minutes

33kV T minutes

66kV T minutes

25 35 50 70 95 120 150 185 240 300

10 10 10 15 15 20 25 25 40 40

15 15 15-25 25 25 25 40 40 40 60

– – 40 40 40 40 50 60 60 60

– – – – 60 60 60 60 75 90

Typical time constant values for cables


Other protectable items Dry-type transformers Air-cored reactors Capacitor banks Overhead lines from 100mm2 Cu or 150mm2 Al Busbars Typical time constants for other protected plant items


T minutes 40 40 10 10 60



Section 8. UNDERCURRENT These elements provide a quick response to an undercurrent condition when they are used to terminate the breaker fail timer sequence and close the fault records etc. To achieve this the peak value of each both half cycles of current are compared with the current setting threshold I<. An undercurrent indication is indicated given when the peak value of either the positive, or negative, half cycle is below the I< threshold giving a theoretical detection time of half a cycle. A logical OR function is performed on the outputs of the three phase fault undercurrent elements to produce an output when an undercurrent condition is detected in all three phases. Similarly the peak value of the residual current is compared with the earth fault undercurrent threshold Io< to produce a separate output. The undercurrent elements are also be used to provide some additional functions in conjunction with the auxiliary timers, but it should be remembered that they are responsive to peak measurement and will be more responsive to the harmonic content of the waveform. 8.1

Breaker failure protection Reset start relays

0A09 EXT. TRIP 7 6 5 4 3 2 1 0

< I o< I

≥

1

tBF

LOG2 1 0

0B0F CB FAIL 7 6 5 4 3 2 1 0

RLY3

Figure 27: Circuit breaker fail logic

The breaker fail timer (tBF) will start to time if relay RLY3 operates and at least one of the undercurrent elements is detecting current flowing in the circuit. The breaker fail timer can also be initiated in response to a logic input being energised if that logic input is allocated in the input mask [0A09 EXT TRIP]. If tBF times out before the undercurrent element, relay RLY3, and the external trip reset, then the output mask [0B0F BF] will be energised and any output relay assigned in this mask will pick-up. If this relay picks-up the circuit breaker is assumed to have failed to clear the fault and this output relay can be then used to back trip the next circuit breaker, nearer the source, to clear the fault. If a blocked overcurrent scheme is in use, logic link LOG2 can be set to ‘1’. This will cause the start relays to reset releasing the block on the upsteram relay to allow it to trip directly and clear the fault. The time delay (tBF) will typically have a setting in the range of 200 to 400ms. The exact time will depend on the sum of the delays in the tripping path including the operation time of the circuit breaker.



Section 9. UNDERVOLTAGE The undervoltage elements can be selected to respond to changes in line voltage by setting link PFA=0, or to the phase voltage by setting link PFA=1. The following time delay tV< can be selected to time when ALL three phase elements indicate an undervoltage condition by setting link PF9=0. Alternatively the delay can be selected to start in response to any one, or more, elements indicating an undervoltage condition by setting link PF9=1. One, or more, output relays can be assigned in mask [0B13 tV<] to pick-up when the undervoltage condition has been present for longer than the set time tV<.

PF8 0 1

V<

0A0E CB CLOSED IND 7 6 5 4 3 2 1 0

& 1

PF9 0 1

tV<

0B13 tV< 7 6 5 4 3 2 1 0

≥

Figure 28: Undervoltage logic

The undervoltage function can be selectively blocked when the circuit breaker is open if link PF8=1. A logic input should be energised via an auxiliary contact of the circuit breaker that will be closed when the circuit breaker is closed. This logic input will indicate when the circuit breaker is closed and must then be assigned in the input mask [0A0E CB CLOSED]. If the undervoltage element is to be operational when the circuit breaker is open then set link PF8=0, then assigning a logic input in mask [0A0E CB CLOSED] is not essential to the operation of the undervoltage function. 9.1

Undervoltage trip An undervoltage trip is often used to isolate the supplies to machinary when the source of electrical supply is lost. This is a safety feature that prevents equipment starting-up unexpectedly when the supplies are eventually restored. The undervoltage elements can arranged to trip the circuit breaker when all three phase voltages have been lost and for this application it does not matter if the phase, or the line, voltages are used. It is advisable to block the undervoltage trip function when the circuit breaker is open, otherwise the trip command will be maintained and reclosing of the circuit breaker may be prevented. Set links as follows: PF8 = 1; PF9 = 0, or 1; PFA = 0. An appropriate delay may be applied to tV< to prevent tripping on voltage dips. Assign relay RLY3 in output mask [0B17 tV<]. Assign a logic input, to indicate CB closed, in input mask [0A0E CB CLOSED]. These settings will be applicable to trigger the disturbance recorder for an undervoltage condition, but it would be advisable to assign an alternative relay to RLY3, because this relay is assigned functions that cause the fault flags to be latched.



Voltage controlled overcurrent protection Applications where the fault current may be less than the nominal full load, eg. generation current decrement, or remote back-up protection of long feeders, will benefit from the application of voltage controlled overcurrent protection. Discrimination between low load current and a low fault current is achieved by detecting the reduction in the line voltage, at the relaying point, that is present during a fault and not during normal load conditions. For this application the following settings should be applied to the relay: Set links as follows: PF8 = 1; PF9 = 1, or 1; PFA = 0 (the line voltage is used to prevent operation during earth fault). Assign a logic input, to indicate CB closed, in input mask [0A0E CB CLOSED]. Assign any relay, but not RLY3, in output mask [0B17 tV<] and externally wire this contact to energise an unused logic input and then assign this input in mask [0A0D SEL GRP2]. This will select the group 2 settings when an undervoltage condition occurs. Apply normal settings for phase faults in group 1and the appropriate lower phase fault settings in group 2.

Section 10. UNDER FREQUENCY The under frequency threshold (F<) is used in conjunction with an auxiliary timer to provide a load shedding function. Setting link PFD = 1 will enable the under frequency element to initiate tAUX1 when the frequency falls below the setting F< provided a logic input is assigned in the input mask [0A0A AUX1] is energised, to give a time delayed output via any relay assigned in the output mask [0B10 AUX1]. This will usually be relay RLY3, the main trip relay. This feature enables the load shedding to be graded by both frequency and time. The frequency measurement will default to the set rated frequency when the signals are too small to measure and provided the under frequency setting is lower than this no output should occur. However, it is known that when a circuit breaker is opened there may be small signals present due to mutual coupling, or ringing effects, that generate signals to which the underfrequency element can respond. In such cases the underfrequency can be gated with some other function such as a lowset overcurrent element, or the circuit breaker closed indication via the input mask [0A0A AUX1].

Section 11. AUXILIARY TIMERS When the auxiliary timers tAUX1, tAUX2, and tAUX3 are not being used by the internal logic of the relay they may be used as discrete time delay elements. Timers tAUX1 and tAUX2 will start to time when a logic input assigned in their input masks is energised. They will then energise an output relay assigned in their associated output masks after the set time has elapsed. Time delays can be set from 0.01s up to 24 days. Timer tAUX2 may be used as a discrete time delay function, or to give delayed initiation of tAUX3. It can also be used to give longer reset delays for the disturbance recorder (see the section on Disturbance Recorder).



Timer tAUX3 is slightly different to tAUX1 and tAUX2 in it can be selected to give a delay on pick-up as in series 1 relays, or alternatively a delay on drop-off. Software link LOGB is used to make the selection. Set LOGB = 0 for delay on pickup and LOGB = 1 for delay on drop-off. 0A0A AUX1 7 6 5 4 3 2 1 0

PFD=1 0 1

0B10 AUX1 7 6 5 4 3 2 1 0

tAUX1 F<

I<

SD8 0 1 LOG3 0 1 LOG4 0 1

3SEC

0A0B AUX2 7 6 5 4 3 2 1 0

I<

Recorder stopped

I o<

1

≥

&

tAUX2

1

≥

0A0C AUX3 7 6 5 4 3 2 1 0

1

≥

tAUX3

0 1 LOGB

SD8 0 1

SD5 0 1 SD6 0 1

Reset trip flags

Recorder stopped

0 1 LOG6

Reset disturbance recorder

0B11 AUX2 7 6 5 4 3 2 1 0 0B12 AUX3 7 6 5 4 3 2 1 0

Figure 19: Auxiliary timer logic

The cold load start timer has been deleted in the K Range series 2 relays and when this function is required tAUX3 should be utilised with link LOGB = 1. For delayed initiation of the cold load start, set link LOG6 = 1 when the delayed initiation will be given by tAUX2. 11.1

Extra earth fault stage Setting link LOG4=1 will enable the earth fault undercurrent element Io< to start tAUX2 when the current exceeds the Io< setting. This gives a fourth earth fault stage, but note that this element is responsive to peak measurement and will not provide a high degree of rejection to harmonic currents.

11.2

Loss of load protection Setting link LOG3=1 will enable the phase fault undercurrent elements to start tAUX2 when the current is less than the I< setting. This can be used to start the cold load start sequence in retrofit installations. It can also be used to indicate loss of critical loads.

11.3

Delayed under frequency trip Setting link PFD=1 will enable the under frequency element to initiate tAUX1 when the frequency falls below the setting F<, to give a time delayed output via any relay assigned in the output mask for tAUX1. This can be used to provide a time delayed under frequency trip for load shedding. This feature enables the load shedding to be graded by frequency and time setting. The under frequency will not maloperate when the signal that is being frequency tracked is too small to track. This is because the frequency tracking will default to the set rated frequency and provided the under frequency setting is lower than this no output will occur.



Section 12. SETTING GROUP SELECTION The relay has two setting groups, but as supplied only setting group 1 will be visible. To make the second group of settings visible in the menu, set function link SD4=1 in the SYSTEM DATA column. The value of the group 2 settings is unimportant when link SD4 = 0, because group 1 settings will be in use by default. The menu cell 000E, in the SYSTEM DATA column, is a read only cell that displays the setting group that is in operation. Note: The logic associated with the change of setting group has changed from that in the original K Range relay and the following notes only apply to K Range series 2 relays.

LOG8 0 1 SD3 0 1

0A0C AUX3 7 6 5 4 3 2 1 0

1

≥

0 1 LOGB

tAUX3

STG GRP 2 0A0D 7 6 5 4 3 2 1 0

1

≥

Remote set Grp2 Remote reset Grp1

SET RESET

1 LOG6

0B12 AUX3 7 6 5 4 3 2 1 0 LOG5 0 1

SD4 0 1

Change to setting group 2

1 0

Figure 30: Setting group selection logic

12.1

Remote change of setting group Link [SD3] must be set to “1” before the relay will respond to a remote command to change the selected setting group. Because the command cannot be sustained over the serial link a set/reset register is used to remember the remotely selected setting group. When link SD3=1, the set/reset register shall change to 0/1 in response to the respective commands / via the serial port. When the value of set/reset register is “0” then the group 1 settings shall be in operation and when its value is “1” the group 2 settings will be in operation. The state of this register stored when the relay is powered down and restored on power up. When link SD3=0 the value of the set/reset register will no longer change in response to remote command and will retain its last set state prior to setting SD3=0. When link SD3=0 the value of the cell cannot be changed via the serial port and the value of this register will have no effect on the setting group in use. Note: If [SD4] = 0 then the group 2 settings will be hidden and group 1 will be active by default.

12.2

Manual change of setting group Link [SD4] must be set to “1” to make the second setting group active. Then manual selection of Setting Group 2 shall be effected by setting link LOG8=1 in the LOGIC column of the menu.

12.3

Controlled change of setting group Link SD4 must be set to “1” to make the second setting group active. Now an internally generated control signal from timer tAUX3 via link LOG5 will select setting group 2. Alternatively, energising a logic input allocated in mask [0A0D STG GRP2] will select setting group 2. Note that tAUX3 will have a delay on pick-



up if link LOGB = 0 and delay on drop-off if LOGB = 1. The logic input could be energised via the contacts of one of the output relays so that change of setting group will be in response to some protection function such as an overcurrent element operating, or the directional contacts changing state. Three example uses are given below: Dual rate inverse time curves

[see Section 4.8]

Cold load pick-up

[see Section 5.12]

Dual thermal time constant

[see Section 7.6]

Voltage controlled overcurrent [see Section 9.2]

Section 13. DUAL POWERED RELAYS Dual powered relays are powered from an AC, or DC, auxiliary supply. This supply need not be secure because the relay will draw current from the current transformer circuit in the absence of the auxiliary supply. 13.1

Powered from current transformers alone When powered from the current transformer circuit alone, the minimum current to operate the relay is that required to establish the power supply rails within the relay. Lowering the design value of this parameter increases the burden on the current transformers and the power dissipated within the relay case. The limits are therefore a compromise based on these factors: Minimum current to power the relay for phase faults = 0.4 In Minimum current to power the relay for earth faults = 0.2 In However, a combined three phase and earth/ground fault relay will operate with lower earth/ground fault current settings when the load current in the protected circuit is sufficient to power the relay ie. greater than 0.4 In. Settings less than 0.2In are provided for earth faults, but they must be used with discretion. 0.8

0.6 ) s d n o c e s (

0.4

e m i T

0.2

0 7

1

10

70

Multiple of minimum current to power the relay

Figure 31: Start-up time delay

100



When switching onto a fault, the relay will be delayed in operation by the start up time and this delay will need to be taken into account in any grading exercise. The delay is the time taken by the processor to initialise its registers, read in settings from non-volatile memory and perform self checks. There will be an additional delay whilst the power supply builds up, but this will be less significant when using an inverse time/current characteristic as the power supply delay similarly varies with current. The start-up time is not reduced by lowering the time multiplier setting. With prefault load current there will be no start-up time and the relays will operate within their normal time settings. Note: Where the start-up delay cannot be tolerated it is recommended that the relay is also powered from an auxiliary AC voltage supply so that it can be up and running before a fault occurs. It will also make stored disturbance and event records more secure, because they are discarded when the relay powers down. 13.2

Powered from an auxiliary AC voltage and from current transformers The addition of an auxiliary AC, or DC, voltage supply to power the relay will: – enable the settings to be changed when the protected circuit is de-energised. – enable records to be retrieved and control functions to be carried out over the communication link. – reduce the burden on the line CTs. When using an auxiliary AC voltage, it may be lost during a fault, when power will be drawn from the current transformer circuit to maintain the relay in a fully operational state. However, if the source of the auxiliary voltage is carefully chosen it is unlikely to be lost completely during earth faults but it may collapse to 50% of its rated value. Provided the voltage is still above the minimum required to power the relay, very low earth fault settings can be successfully applied. In the absence of the auxiliary voltage the relay is not guaranteed to operate for earth fault currents less than 0.2 In. No alarm is given for loss of the ac auxiliary voltage, unless it is externally monitored by a separate supervision relay.

13.3

Special application notes for dual powered relays Dual powered relays may be fitted with eight opto-isolated inputs and eight relay outputs, but at the claimed minimum operating current they cannot all be energised at the same time. If they are, then the minimum operation current will be increased. However, in applications requiring a dual powered relay it is unlikely that more than two output relays will be energised at any one time. The following table shows how the minimum operating current varies with the number of relays (not including the watchdog) and inputs that are to be energised at the same time. No.of output relays energised 8 opto-inputs energised 6 opto-inputs energised 4 opto-inputs energised 2 opto-inputs energised Imin

2 1.3xImin 1.3xImin 1.2xImin 1.1xImin



= 0.4 In for phase faults and 0.2In for earth/ground faults.




Dead substation protection The dual powered relays derive power for the electronics and the trip coil of the circuit breaker from the line current transformers and optionally from an auxiliary voltage supply. Applying one of these relays on the incoming feeder to the substation will ensure that the substation is still protected in the event of complete failure of the auxiliary supplies. The application limitations are that the setting range of these relays is a little more restricted when power is being derived from the current transformers alone and that the circuit breaker must have a suitable trip coil fitted. The tripping energy is provided by a 680µF capacitor charged to 50V and the circuit breaker should reliably trip when this capacitor is discharged into its trip coil.

13.5

Capacitor discharge tripping Dual powered relays may use either of the above methods. In addition, these particular relays charge an internal capacitor from the current circuit and also from the auxiliary voltage circuit (Figure 32). This capacitor is 680µF and it is charged to 50V dc. It may be discharged directly into a suitably sensitive trip coil via one of the programmable output relays. The minimum energy fed to the trip coil is that from the capacitor, but in most cases it will be supplemented by a current from the auxiliary voltage circuit and/or the current circuit. When energized from current alone the lowest current for which the relay will operate will be that necessary to start up the power supply. To be able to use lower fault settings an auxiliary supply will be required. The capacitance discharge circuit is not isolated from the auxiliary supply and to prevent the relay from being damaged, no external ground connection should be made to this circuit. Relay

42

RLY3

44 9

Trip

+ 10

Figure 32: Capacitor discharge trip

13.6

AC series tripping As an alternative the trip capacitor in the dual powered relays may be discharged into an auxiliary relay. This relay will be de-energized in the quiescent state, with its break contacts short circuiting the trip coils of the circuit breaker (Figure 33). The trip coils are connected in series with the current transformer secondary circuit so that, when the auxiliary relay is operated, the full secondary current is diverted through the trip coils. To cover all fault conditions, three trip coils are required and may be necessary to limit the maximum energy that can be fed to each coil, by means of saturating shunt reactors.



RELAY

42

RLY3

44 9 + 10

21

TC

TC

23

25

28

TC

MVAZ Ia

To line CTs

Ib

Ic In

Figure 33: AC series trip arrangement

Section 14. AUTORECLOSE - single shot scheme In many feeder protection schemes, autoreclose is used as an effective tool to restore supply following transient faults such as flash overs caused by lightning strikes. Areas prone to sever lightning activity usually require multi-shot autoreclose schemes to deal with multiple strikes. These schemes are quite complex, often involving enabling and disabling of certain protection functions at each stage and hence requires complex scheme logic and timing routines as provided in the KAVR and KVTR relays. However, there are many instances where transient faults are rare and not justifying dedicated autoreclose schemes, but even so a simple single shot autoreclose scheme can reduce the number of instances of lost supply due to these occasional transient faults. 14.1

Overview The scheme provides a single shot autoreclose function using the scheme logic capablilities of the KCGG or KCEG overcurrent relays together with a single external auxiliary relay. The auxiliary relay is an MVAA 15 relay or similar electrically reset relay, which is utilised to latch the autoreclose initiate signal. This has the added advantage of preventing hunting of the scheme. The autoreclose dead time and reclaim time are controlled by the two auxiliary timers tAUX2 and tAUX3 that form an integral part of the KCGG/KCEG. Timer tAUX1 may be included in the scheme to detect unsuccessful reclosures. Of course these auxiliary timers may already be in use with other K scheme options in which case they may be replaced by external delay on energisation timers such as the MVTT 14 or MVUA 11. In K Range series 2 relays only, auxililary timers tAUX3 may be configured for delay on pick-up, or delay on drop-off and for this



application it should be set for a delay on pick-up by setting link LOGB = 0 (in K Range series 1 tAUX3 is always delayed on pick-up). Timers tAUX2 and tAUX3 are always delayed on pick-up. 14.2

Connections The connection diagram for the scheme using the K Range relay auxiliary timers is shown in Figure 34. Equipment list Device 99-1,2 SW-1 SW-2 PB-1 94 52-a 52-b FS-1 FS-2

Function Multifunction protection Manual trip/close switch A/R in/out selector switch Manual A/R reset push button Electrically reset relay - MVAA 15 CB aux-open when CB open CB aux-closed when CB open Trip circuit fuse Protective relay circuit fuse

Device FS-3 52T 52C AUX1 AUX2 AUX3 AUX1-1 AUX2-1 AUX3-1

Function Close circuit fuse CB trip coil CB close coil Unsuccessful reclose timer Dead time Reclaim time Unsuccessful reclose contact CB close initiate contact Successful reclose pulse contact

SW-1/1 TOC +

FS-1

99-1 (t>, t>>, t>>>)

FS-2

99-2 (t>, t>>, t>>>)

In Out 52T SW-2/1 Out In

PB-1

R MVAA15

AUX3-1 13

94 S

14 48V + -

94-1

52-b

AUX1 AUX2

52-a

AUX3

AUX2-1

BLOCK (99-t>>) CB Close

AUX1-1 FS-3

CB Close -1

SW-1/2 TOC

99 KCGG/KCEG 94-2

Figure 34: Connection diagram for single shot autoreclose scheme

52C



Successful reclose description When the protective relay operates (KCGG or KCEG) to trip the circuit breaker, the MVAA 15 (device 94) electrically reset relay is latched in, initiating the autoreclose sequence if the autoreclose service switch SW-2/1 is set to In Service.

99 52-a 52-b 94-1 Aux2 CB Close Aux3 Aux1 1

2

3

1. Protection relay trips 2. AUX2 operates at end of dead time and closes breaker 3. AUX3 operates at end of reclaim time and resets scheme

Figure 35: Successful autoreclose sequence

The 94-1contact starts the AUX2 timer as the dead time of the scheme. At the end of the dead time, contact AUX2-1 operates to energise the local CB close input to the KCGG relay, which in turn closes its contact CBClose-1 to energise the CB close coil 52C. The CB Close function of the K Range relay includes a timer setting for the duration of the close pulse to prevent burn out of the 52C coil. The 94-1 contact may also be used, if desired, to block any one or all of the K range relay overcurrent stages by setting the appropriate input masks. The one input from 94-1 can then be programmed to initiate CB Close as well as initiate blocking. As the 94-1 contact is latched in, as soon as the CB closes, the 52-a contact will close to initiate the Aux3 timer as the reclaim time. If the breaker remains closed for the duration of AUX3 reclaim time, the AUX3-1 contact operates to reset the 94 relay which resets the complete scheme. A second contact may be programmed for the AUX3 timer as a successful reclose pulse contact which will remain closed for the reset time of 94 plus the reset time of AUX3.



Unsuccessful reclose In the case of an unsuccessful reclose, a separate alarm is given by the AUX1 timer.

99 52-a 52-b 94-1 Aux2 CB Close Aux3 Aux1 1

2

3

4

5

1. Protection relay trips 2. AUX2 operates at end of dead time and closes breaker 3. Protection relay trips again within reclaim time 4. AUX1 raises unsuccessful reclose alarm 5. Scheme reset by manual push-button - CB can now be closed manually Figure 36: Unsuccessful autoreclose sequence

As the 94-1 contact is latched in when the autoreclose is initated, if the breaker fails to close or fails to stay closed following the reclose pulse from CB Close-1, the 52-b contact will initate the AUX1 timer. This timer is set slightly longer (eg. 2s) than the AUX2 Dead Time timer and raises the Unsuccessful Reclose alarm via AUX1-1. As a security against manual closing of the breaker either during a reclose sequence or if there has been an unsuccessful reclose, the 94-2 contact prevents the manual close switch energising the 52C coil. 14.5

Blocking instantaneous low set protection when reclosing When using autoreclose equipment it is often the practice to utilise I>>/Io>> as instantaneous low set elements. This will ensure that any transient fault is quickly extinguished so that the autoreclose can then re-establish the supplies. It may be considered an advantage to block the operation of the instantaneous elements during the reclose cycle to allow time graded tripping to determine and isolate the faulted circuits, with the minimum disruption of supplies. As described in Chapter 4, Section 5.5, it is advantageous to block the associated timers for the low set elements t>>/to>> to ensure accurate flagging of the fault. The output from timer AUX2 is shown in the diagram to perform this function as well as initiating the close pulse timer. Setting link SD5 = 1 will result in the fault flags being reset automatically following a successful reclosure.



Where lightning strikes are frequent, it can be an advantage to make the I>>/Io>> setting equal to I>/Io>, in order to detect the maximum number of transient faults. 14.6

Circuit breaker operation counter Each K Range series 2 relay is equipped with a circuit breaker operation counter, the value of which can be displayed on the LCD or remotely via the serial communication port. In addition an output relay can be arranged to pick-up when the counter value reaches a settable limit (see Chapter 5, Section 7.2). This counter can be used to augment the autoreclose scheme.


Chapter 5 Measurement and Records

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242 1. 1.1 1.2 1.3 2. 2.1 2.2 2.3 2.4 3. 3.1 3.2 3.3 4. 4.1 4.2 4.3 4.4 5. 5.1 5.2 5.3 6. 6.1 6.2 6.3 6.4 6.5 6.6 6.7 7. 7.1 7.2 7.3 7.4 8. 8.1 8.1.1 8.1.2 8.2 8.3

MEASURE 1 Current Voltage Frequency MEASURE 2 Imax Power Power mode selection Three phase power factor MEASURE 3 Thermal ammeter Thermal state Peak demand FAULT RECORDS Generating fault records Accessing fault records Resetting fault records Fault passage information EVENT RECORDS Triggering event records Time tagging of event records Accessing and resetting event records DISTURBANCE RECORDS Recorder control Recorder capture Recorder post trigger Recorder logic trigger Recorder relay trigger Notes on recorded times Disturbance recorder reset options CIRCUIT BREAKER MAINTENANCE RECORDS Circuit breaker clearance time Circuit breaker operations counter Circuit breaker contact duty Circuit breaker maintenance alarm ALARM RECORDS Watchdog Auxiliary powered relays Dual powered relays Trip indication Alarm indication

Figure 1: Figure 2: Figure 3: Figure 4:

Mode of signing power flow Record initiation logic Recorder reset Circuit breaker alarm


1 1 1 1 1 1 1 2 2 3 3 4 4 4 5 5 5 6 6 6 6 7 7 7 8 8 8 8 8 9 9 9 10 10 10 11 11 11 11 11 11 2 5 9 9



Section 1. MEASURE 1 The same menu cells have been retained for measurement values and new cells have been used for any additional measurements that are now included. 1.1

Current Current is measured once per power frequency cycle and Fourier is used to extract the fundamental component. Measurements are made for each of the three phase currents (Ia, Ib, Ic) and the residual circuit current ( Io). These values are stored in menu cells 0201, 0202, 0203 and 0204 respectively.

1.2

Voltage The phase/neutral voltages are measured directly when the internal VTs are star connected. The phase voltages (Va, Vb, Vc) are then stored in menu locations 0208, 0209 and 020A. From the sum of these voltages the residual voltage (Vo) is calculated. This voltage is equivalent to the output that would be obtained from an open delta connection of a three phase VT and is three times the zero sequence voltage. The residual voltage Vo is stored in menu location 020B. The phase voltages are calculated from the measured phase voltages and stored in menu locations 0205, 0206 and 0207. In KCEU 142/242 the internal VTs are delta connected. The line voltages (Vab, Vbc, Vca) and the residual voltage (Vo) are then directly measured and stored in their respective menu locations.

1.3

Frequency The sampling frequency of the analogue/digital converter is synchronised to the power system frequency when there is a signal of sufficient strength to reliably make a frequency measurement. In the absence of a signal to frequency track the sampling frequency defaults to the power frequency setting in menu cell 0009. For protection functions the measured frequency defaults to the power frequency setting when the current and voltage is zero. The displayed frequency measurement will also be the sampling frequency, but in this case it will read 0 when the frequency tracking stops.

Section 2. MEASURE 2 2.1

max Imax

is not a demand value, but the highest of the three phase currents and is stored in menu cell 0304. It is a useful value to display when all three phase currents cannot be displayed. 2.2

Power Active and reactive power is calculated for each of the three phases and from these the three phase power is calculated. On series 1 relays only the three phase power could be accessed, but on series 2 relays the single phase values are also available. All the power measurements are to be found under MEASURE 2.



Power mode selection The standard current and voltage connections, shown on connection diagrams, follow the convention that forward current flows from the busbar to the feeder. This will correspond to positive values of active power flowing from the busbar to the feeder. However, alternative methods of signing the direction of power flow are provided to suit other application, or user’s standard. The signing for the active and reactive power can be changed in menu cell 031E to any of the following four alternatives:

Lagging kVArs to busbar Mode 0 = ÐVAr Mode 1 = ÐVAr Mode 2 = +VAr Mode 3 = +VAr

Power to feeder Mode 0 = +W Mode 1 = ÐW Mode 2 = +W Mode 3 = ÐW

Power to busbar Mode 0 = ÐW Mode 1 = +W Mode 2 = ÐW Mode 3 = +W

Lagging kVArs to feeder Mode 0 = +VAr Mode 1 = +VAr Mode 2 = ÐVAr Mode 3 = ÐVAr

Figure 1: Mode of signing power flow

When connected for forward power flow to the feeder then: Mode 0 – Net export signing : + = net export of power and negative VArs Mode 1 – Import to busbar

: + = net power flow to busbar in (a+jB) form.

Mode 2 – Export from busbar : + = net power flow to feeder in (a+jB) form. Mode 3 – Net import signing : + = net import of power and negative VArs As a safeguard against accidental change this cell is password protected. 2.4

Three phase power factor The three phase power factor is calculated after taking the selected signing mode into account as follows: pf = [active power]/[apparent power] Range: –1<0<+1 [the sign (–/+) indicates reverse/forward and not lag/lead]



Section 3. MEASURE 3 3.1

Thermal ammeter The thermal ammeters have a representative characteristic similar to that produced by a bi-metal type of instrument, where the movement would be proportional to the bending of the bi-metal strip as a result of the heat applied. Its time/position characteristic is essentially exponential during the heating and cooling cycle and its response is measured in time constants. This type of instrument does not respond to minor rises or dips in the measured current. It displays a steady measurement of the average current over the demand period, equal to six times the selected time constant. In the event of the auxiliary supply to the relay being lost the thermal values are remembered and restored when the supply is re-established. The setting for the time constant is in menu cells 0614 and 0814 and is adjustable from 1 to 120 minutes in 1 minute steps. However, the time constant is shared with the thermal protection and if the thermal protection is in use its time constant settings will probably be given priority over the instrument requirements. For some applications it may be found to be advantageous to allocate a different time constant in the group 1 and group 2 settings and to arrange for the setting group 2 to be selected in response to operation of one of the overcurrent stages. For example a different cooling time constant could be effective when a motor was stationary and taking no current, to that when the cooling is increased by windage. UK applications Electricity Supply Industry Specification ESI 50-2 states that the preferred time lag is 30 minutes and this shall be equal to 6 time constants. Thus for this application the time constant should be set to 5 minutes. US applications In the USA the response of such devices is expressed as the time to reach 90% of the prospective current and the generally accepted time would seem to be in the order of 15 minutes. The time to reach 90% of final value is 2.3 time constants and so for such applications the recommended time constant would be 15/2.3 = 6 minutes. Note:

Link PF0 =1 for the thermal ammeters to operate. If PF0 = 0 then they will neither increment nor decrement. It is recommended that the thermal demand registers are manually reset to zero after setting PF0 = 0 as this will clear the thermal memory of the ammeters. If link PF0 is set differently in the two setting groups, the thermal memory may maintain a constant reading on the thermal ammeters after switching to the setting group in which PF0 = 0.

The thermal ammeters cannot be directly reset by performing a reset cell operation on menu cell 0404, 0405 or 0406. They are password protected and only reset when the peak demand registers are reset (see Section 3.3).



Thermal state The thermal state is a measure of the percentage of the limiting thermal capacity that the protected item of plant is estimated to have reached. The maximum current that the device can withstand continuously should be entered as the setting for (Ith>) in the phase fault settings of the relay (cells 0613 and 0813). The time constant will compensate for the cooling effects resulting from heat being radiated to the surroundings. When a current equal to Ith> is applied the thermal state will reach 100% after approximately 6 times the set time constant. Normal load current will be less than Ith> and the thermal state, being proportional to I2 will be considerably lower than 100%. On loss of the auxiliary supply the thermal state is memorised and when the supply is restored the thermal state is restored to the memorised value unless the stored value is greater than 90% when it will be restored to 90%. The thermal state is protected and the password must be entered before it can be reset via the menu. Cell 0407 under MEASURE 3 should then be displayed and the [0] key pressed for 1 second. This does not reset the thermal ammeters or the peak demand values. The thermal state can also be reset by energising a logic input assigned in input mask [0A11 RESET Ith]. Energising this input will reset the thermal state without resetting the peak demand ammeters. The password does not need to be entered to reset by this method.

3.3

Peak demand The peak demand is the highest value the thermal ammeters have attained since they were last reset and the demand for each phase is recorded separately. The peak demand can be reset by entering the password, selecting one of the peak demand values in the menu, cells 040A, 040B, or 040C, and pressing the reset key [0]. This will also cause the thermal ammeters to reset at the same time but the thermal state will not be reset.

Section 4. FAULT RECORDS A full fault record is now stored for each of the last five faults, with the new record overwriting the oldest record one. These records are stored in non volatile memory and are retained when the relay is powered down. Fault records contain the following information: – fault flags – three line voltages – measured phase currents – residual current and voltage – time from trip command to cessation of current flow Fault records are also recorded with a time tag in the event recorded


SD2 0 1


Generating fault records Block start

0A07 L TRIP 7 6 5 4 3 2 1 0

≥

Trip circuit breaker 0A08 L CLOSE 7 6 5 4 3 2 1 0

Close circuit breaker

1

0B0D CB TRIP 7 6 5 4 3 2 1 0

tTRIP

1

≥

1

≥

0A09 EXT. TRIP 7 6 5 4 3 2 1 0

1

≥

RLY3 LOGA 0 1 LOG7 0 1

I

 I o> I

1

≥

1

≥

Latch flags Generate fault records and Copy to events records

Figure 2: Record initiation logic

Fault records are generated when output relay RLY3, or a logic input assigned in the input mask [0A09 EXT TRIP], is energised. The fault flags will be latched and the trip LED lit in response to these two inputs. The circuit maintenance records will be updated and the breaker fail protection initiated by either of these two inputs. Relay RLY7 is used for remote, or manual trip, and can be arranged to trigger the generation of fault and circuit breaker maintenance records by setting link LOGA = 1, but in this case the breaker fail protection will not be initiated. Setting link LOG7 = 1 will enable the start relays to generate a fault record and so record the passage of fault current, but since if the fault is not cleared by this relay operating output relay RLY3 or RLY7, the circuit breaker fail protection will not be initiated, the trip LED will not be lit and the maintenance records will not be updated. 4.2

Accessing fault records Fault records can be accessed by selecting [0101 Fault No Fn] in the [FLT RECORD] column menu. The fault number (Fn) denotes the record for the last fault and the record for previous faults can be selected by successive long presses of the [0] key. Fn-1 is the previous fault and Fn-2 is the one before that, etc. The [0] key enables fault record selection with the cover in place on the relay, but for remote selection, the usual change setting commands will give a quicker response. With the cover removed and menu cell [0101 Fault NoFn] displayed, the [+] and [–] keys can be used to change to the required record number.

4.3

Resetting fault records All five fault records can be cleared by selecting cell 0110, the last cell under fault records and pressing the [0] key for 1 second. Note: If fault records are being viewed with ACCESS or PAS&T software; hit return key and then select the reset cell option to reset all five fault records.



Fault passage information Any start function can be used to initiate a fault record when it detects the passage of fault current through the protected zone. This fault record will contain the current magnitude, the phases involved and voltage measurements, if appropriate. To achieve this it is necessary to set function link LOG 7 = 1 so that recording is initiated by the start relays picking up. Several such records may be stored in the event recorder and the number will be increased if the logging of logic events is turned off by setting link SD7 = 0. If the fault records are also generated by relay RLY3 they will still be generated for faults that are cleared by the relay tripping as well as for those passing through the protected section. The disturbance recorder, if set to trigger when relay RLY3 picksup, will only capture a record for faults cleared by RLY3 operating.

Section 5. EVENT RECORDS Fifty time tagged event records can be stored, after which the oldest record is overwritten. They are stored in volatile memory and will be lost if the relay is powered down. The event records can only be accessed via the serial communication port and PC software is available to support the automatic extraction and storing of these records. The following items are recorded by the event recorder: – Fault records including: fault flags, fault currents and voltages. – Setting changes made via the user interface on the front of the relay – Logic events: status change of logic inputs and/or output relays – Alarms: internal equipment alarms detected by self monitoring functions. The number of full fault records that can be stored in events records can be increased by setting link SD7 = 0 to inhibit storage of logic events. 5.1

Triggering event records Event records are triggered automatically in response to the functions listed in the previous section.

5.2

Time tagging of event records The K Range relays do not have a real time clock. Instead, they each have a freerunning 32-bit counter that increments every 1ms. When an event occurs, the value of this millisecond counter is recorded (Ta) and stored in the event buffer. When the event is extracted, the present value of the millisecond counter is also sent in the message (Tb). The master station must record the actual time at which it received the event message (Tc). This is equivalent to Tb if we consider the transmission time of the event over the communication network to be negligible. It then calculates how long ago the event occurred by: How long ago = (Tb – Ta) ms Real time = (time message was received) – (how long ago it occurred) = (Tc) – (Tb – Ta) ms Time tagging is to a resolution of 1ms, the incrementation rate of the counter and remains valid for approximately 49 days. However, the crystal to control the timing has a nominal accuracy of ±50 ppm, is not externally synchronised and has no temperature compensation. It can therefore introduce an error of ±1s in every 5.5 hours.



The event recording was originally designed for use with automatic extraction programs running on a personal computer (PC) when these timing errors would be insignificant. Refer to Chapter 5, Section 6.6 for notes on recorded times, as these apply equally to event records. 5.3

Accessing and resetting event records Event records cannot be viewed on the relay and can only be accessed via the serial communication port of the relay. A PC with suitable software, such as PAS&T, can automatically extract the records, display them on a screen, print them, or store them to either a floppy disk or to the hard disk of the computer. When a new record is generated the oldest event record is automatically overridden and the event flag set. The PAS&T software responds to this flag and extracts the record. When all records have been read, the event flag resets.

Section 6. DISTURBANCE RECORDS

6.1

The internal disturbance recorder has one channel allocated to each of the measured analogue quantities; one to record the eight control inputs and one to record the eight relay outputs. As with the event recorder, when the buffer is full the oldest record is overwritten and records are deleted if the auxiliary supply to the relay is removed. This ensures that when the buffer is read the contents will all be valid. The disturbance recorder is stopped and the record frozen, a set time after a selected trigger has been activated. For example, a protection trip command could be the selected trigger and the delay would then set the duration of the trace after the fault. Each sample has a time tag attached to it so that when the waveform is reconstituted it can be plotted at the correct point against the time scale, thus ensuring that the time base is correct and independent of the frequency. The K Range overcurrent relays measure eight samples per cycle, but the method of recording allows the analysis program to perform with records that may have a different sample rate. The disturbance recorder may be triggered by several different methods dependent on the settings in the RECORDER column of the menu. However, the records have to be read via the serial communication port and suitable additional software is required to reconstruct and display the waveforms. Only one complete record is stored and the recorder must be reset before another record can be captured. Recorder control This cell displays the state of the recorder : a) RUNNING – recorder storing data (overwriting oldest data) b) TRIGGERED – recorder stop delay triggered c) STOPPED – recorder stopped and record ready for retrieval When this cell is selected, manual control is possible and to achieve this the relay must be put into the setting mode by pressing the [+] key. A flashing cursor will then appear on the bottom line of the display at the left-hand side. The [+] key will then select 'running' and the [–] key will select 'triggered'. When the appropriate function has been selected the [F] key is pressed to accept the selection and the selected function will take effect when the [+] key is pressed to confirm the selection. To abort the selection at any stage, press the reset key [0].



Recorder capture The recorder can capture: a) SAMPLES – the individual samples b) MAGNITUDES – the Fourier derived amplitudes c) PHASES – the Fourier derived phase angles The relay has no electro-mechanical adjustments, all calibration is effected in software and all three of the above options are used in the calibration process. For normal use as a fault recorder, SAMPLES will be the most useful. However, for 60Hz systems there is less processing time available per cycle and if all the protection functions have been activated the menu system, being the lowest priority task, may appear very slow. To improve this the disturbance recorder should be stopped (triggered) via the menu. If records are still required at this time then it is suggested that the recorder is set to record magnitudes rather than samples because this will use less of the available processing time.

6.3

Recorder post trigger The post trigger setting determines the length of the trace that occurs after the stop trigger is received. This may be set to any value between 1 and 512 samples. When recording samples the total trace duration is 512/8 = 64 cycles because the interval between the samples is equivalent to one eighth of a cycle. However, the Fourier derived values are calculated once per cycle and so the total trace length when recording these calculated phase or amplitude values is 512 cycles.

6.4

Recorder logic trigger Any, or all, of the opto-isolated inputs may be used as the stop trigger and the trigger may be taken from either the energisation or the de-energisation of these inputs. The bottom line of the display for this cell will show a series of 16 characters, each of which may be set to '1' or '0'. A '1' will select the input as a trigger and a '0' will deselect it. The selection is made using the instructions for the setting links in Chapter 3, Section 3.4. The opto-isolated input (L0 to L7) associated with each digit is shown on the top line of the display for the digit underlined by the cursor. A '+' preceding it will indicate that the trigger will occur for energisation and a '–' will indicate the trigger will occur for de-energisation.

6.5

Recorder relay trigger Any, or all, of the output relays may be used as a stop trigger and the trigger may be taken from either the energisation or the de-energisation of these outputs. The bottom line of the display for this cell will show a series of 16 characters, each of which may be set to '1' or '0'. A '1' will select the input and a '0' will deselect it. The selection is made using the instructions for setting links in Chapter 3, Section 3.4. The output relay (RLY0 to RLY7) associated with each digit underlined by the cursor is shown on the top line of the display. A '+' preceding it will indicate that the trigger will occur for energisation and a '–' will indicate the trigger will occur for de-energisation.

6.6

Notes on recorded times The times recorded for the opto-isolated inputs is the time at which the relay accepted them as valid and responded to their selected control function. This will be 12.5 ±2.5ms at 50Hz (10.4 ±2.1ms at 60Hz) after the opto-input was energised.



The time recorded for the output relays is the time at which the coil of the relay was energised and the contacts will close approximately 5ms later. Otherwise the time tags are generally to a resolution of 1ms for events and to a resolution of 1µs for the samples values. 6.7

Disturbance recorder reset options I<

0A0B SD8 0 1 LOG3 0 1 LOG4 0 1

3SEC

AUX2

7 6 5 4 3 2 1 0

I

<

I

o<

1

≥

Recorder stopped

& 1

≥

tAUX2

SD8 0 1

SD5 0 1 SD6 0 1

Reset trip flags

Recorder stopped


0B11

AUX2

7 6 5 4 3 2 1 0

Figure 3: Recorder reset

The disturbance recorder is reset via cell [0C01 Control]. Alternatively it can be arranged to reset automatically, 3 seconds after the current is detected by the undercurrent elements to be above its set threshold. To select this option set link SD6 = 1 and SD8 = 0. This automatic 3s reset may be useful when auto reclose equipment is employed since a record will only be stored when the autoreclose equipment fails to reclose the circuit breaker, or it locks out. If a shorter or longer reset delay is required, set the links as follows. SD6 = 1 and SD8 = 1 (LOG3 = 0, LOG4 = 0) and then tAUX2 can be set to the necessary reset delay. The setting range for tAUX2 is 0 to 24 days in graduated steps with the smallest step of 10ms. With this option the recorder can be reset instantaneously by energising a logic input that is assigned in the input mask [0A0A AUX2].

Section 7. CIRCUIT BREAKER MAINTENANCE RECORDS 0A09 EXT. TRIP 7 6 5 4 3 2 1 0

1

≥

RLY3 Generate circuit breaker maintenance records

1

≥

RLY7

LOG0 0 1

Latch red trip LED

CB(ops)> 1

≥

0B19 CB ALARM 7 6 5 4 3 2 1 0

CB duty>

Figure 4: Circuit breaker alarm

7.1

Circuit breaker clearance time The time taken for the circuit breaker to break the fault current is estimated and stored in the fault records in menu cell [0109 CB Trp Time]. A sudden increase in this time measurement may indicate the need for maintenance of the circuit breaker.



Circuit breaker operations counter A register sums the number of circuit breaker operations and the value can be accessed via menu cell 0310 under the column heading MEASURE 2. This record is updated every time output relay RLY3 operates, or an opto input assigned in input mask [0A09 EXT TRIP] is energised by an external trip. If link LOGA = 1 then operation of relay RLY7 will also be able to increment this register. RLY7 is normally used for manual or remote trips via the trip pulse timer (tTRIP). This function is inhibited if link LOG 0 = 0 and operative if LOG 0 =1. Incrementation of this counter can be blocked during testing by setting link LOG 0 = 0. The value of the counter can be reset to zero when it is displayed, by pressing the reset key [0]. Alternatively a reset cell command can be sent via the serial communication port. These cells are password protected and cannot be reset if the password has not been entered. Note: Resetting the (CBops) counter will also result in the 'CBduty' registers being reset at the same time.

7.3

Circuit breaker contact duty Three registers are used to sum the contact breaking duty separately for each phase. These are labelled [0311 CBdutyA], [0312 CBdutyB] and [0313 CBdutyC]. If link LOG 1=1 then the relay sums the current and it LOG 1=0 then the relay sums the squared current. The value of these registers can be accessed under the column heading MEASURE 2. These records are updated every time output relay RLY3 operates, if link LOGA = 1 and RLY7 operates, or an opto input assigned in input mask [0A09 EXT TRIP] is energised by an external trip. When a remote trip is issued via the serial communications, or a local trip initiated via the input mask [0A07 LTrip] relay RLY7 should be assigned in output mask [0B0D CB Trip]. Then the contact duty record will also be updated when relay RLY7 operates if links LOG0 = 1, LOG1 = 0, LOGA = 1. This function is inhibited if link LOG0 = 0 and operative if LOG1 = 1. Hence by setting this link LOG0 = 0 during testing its incrementation can be blocked. The value of these three registers can be reset to zero when any one of them is displayed, by pressing the reset key [0]. Alternatively a reset cell command can be sent via the serial communication port. These cells are password protected and cannot be reset if the password has not been entered. Note:

7.4

Resetting the circuit breaker contact duty registers will also reset the circuit breaker operations counter.

Circuit breaker maintenance alarm A threshold can be set on the circuit breaker operations counter and the summated contact duty. The settings will be found in menu cells [0908 CBops>] and [0909 CBduty>1] under the LOGIC column heading. When the thresholds are exceeded the output mask [0B19 CB ALARM] will be energised and any relay assigned in this mask will pick-up to initiate an alarm. This is the only form of alarm that is generated, except for the change in state of the output relay, which may be recorded in the event records if link SD7 = 1. The alarm will be inhibited if link LOG 0=0, or if the output relay is de-selected in the relay mask.



Section 8. ALARM RECORDS 8.1

Watchdog

8.1.1

Auxiliary powered relays The watchdog relay will pick up when the relay is operational to indicate a healthy state, with its make contact closed. When an alarm condition is detected that requires some action to be taken, the watchdog relay will reset and its break contact will close to give an alarm.

8.1.2

Dual powered relays The watchdog relay operates in a slightly modified way on this version of the relay, because it does not initiate an alarm for loss of auxiliary power, as this may have been taken from an insecure source, or it may be powered solely from the current circuit. Operation of the watchdog is therefore inverted so that it will pick up for a failed condition, closing its make contact to give an alarm and in the normal condition it will remain dropped off with its break contact closed to indicate a healthy state. The green LED will usually follow the operation of the watchdog in either of these two cases. It will be lit when the relay is powered-up, operational and has not detected any abnormal conditions. The watchdog can be tested by setting alarm flag 6 to '1' in menu cell 0003 in the SYSTEM DATA column of the menu.

8.2

Trip indication The trip LED will be lit following a trip condition where output relay RLY3 has operated, or a logic input that has been assigned in input mask [0A08 EXT TRIP] has been energised. Relay RLY7 is generally reserved for remote trip initiation via the serial communication port. When link LOGA = 1 and relay RLY7 is assigned in output mask [0B0D CB Trip] the trip LED will be lit if relay RLY7 has operated. Relay RLY7 can also be initiated for manual trips via the trip pulse timer (tTRIP) by assigning a logic input in mask [0A07 LTrip] to give a trip indication. Unlike relay RLY3, RLY7 does not initate the breaker fail protection, but they can both initiate the generation of fault records and hence fault flags. When relay RLY7 operates and link LOGA = 1, the default display changes to the fault flag display and a letter 'R' is displayed in the extreme right-hand position on the bottom line of the display to indicate a 'remote trip'. If link LOGA = 0 relay RLY7 can be freely assigned to any output function, without creating a trip indication.

8.3

Alarm indication The alarm LED will flash when the password has been entered. It will be lit and remain steady when an internal fault has been detected by its self test routine. The alarm flags can then be accessed to determine the fault, provided the relay is still able to perform this function. See Chapter 3, Sections 3.5 and 3.6 for more information on alarm flags.


Chapter 6 Serial Communications



1. 2. 2.1 2.2 2.3 3. 3.1 3.2 3.3 3.4 3.5 3.6 4. 4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 4.9 4.10 4.11 4.12 4.13 4.14 5. 5.1 5.2 6. 7. 7.1 7.2 7.3 7.3.1 7.3.2 7.3.3 8.

COURIER LANGUAGE AND PROTOCOL K-BUS K-Bus transmission layer K-Bus connections Ancillary equipment SOFTWARE SUPPORT Courier Access PAS&T K-Graph CourierCom PC requirements Modem requirements DATA FOR SYSTEM INTEGRATION Differences between K Range series 1 and series 2 relays Relay address Measured values Status word Plant status word Control status word Logic input status word Output relay status word Alarm indications Event records Notes on recorded times Protection flags Fault records Disturbance records SETTING CONTROL Remote setting change Remote control of setting group REMOTE OPERATION OF OUTPUT RELAYS CIRCUIT BREAKER CONTROL Remote control of circuit breaker Local control of the circuit breaker Safe manual closing of the circuit breaker Closing the circuit breaker via the serial communication port Closing the circuit breaker via a lead mounted push-button Delayed manual closure of the circuit breaker AIDS TO CIRCUIT BREAKER MAINTENANCE

1 1 2 2 3 3 3 3 4 4 4 4 5 5 6 6 6 7 7 7 7 8 8 8 9 10 10 10 11 11 12 13 13 13 14 14 14 14 15

Figure 1. Figure 2.

Typical K-Bus connection diagram Circuit breaker control logic

2 13



Section 1. COURIER LANGUAGE AND PROTOCOL Serial communications are supported over K-Bus, a multi-drop network that readily interfaces to IEC 60870-5 FT1.2 standards. The language and protocol used for communication is Courier. It has been especially developed to enable generic master station programs to access many different types of relay without the continual need to modify the master station program for each relay type. The relays form a distributed data base and the master station polls the slave relays for any information required. This includes: Measured values Menu text Settings and setting limits Fault records Event records Disturbance records Plant status Software is available to support both on-line and off-line setting changes to be made and the automatic extraction and storage of event and disturbance records as described in Section 3. Courier is designed to operate using a polled system, which prevents a slave device from communicating directly to a master control unit when it needs to inform it that something has happened; it must wait until the master control unit requests the information. A feature of Courier is that each piece of information is packeted by preceding it with a ‘data type and length’ code. By knowing the format of the data the receiving device can interpret it. The Courier Communication Manual describes various aspects of this language and other communication information necessary to interface these devices to other equipment. It gives details on the hardware and software interfaces as well as guidelines on how additional devices should implement the Courier language so as to be consistent with all other devices.

Section 2. K-BUS K-Bus is a communication system developed to connect remote slave devices to a central master control unit, thus allowing remote control and monitoring functions to be performed using an appropriate communication language. It is not designed to allow direct communication between slave devices, but merely between a master control unit and several slave devices. The main features of K-Bus are: cost effectiveness, high security, ease of installation and ease of use. Each relay in the K Range has a serial communication port configured to K-Bus standards. K-Bus is a communication interface and protocol designed to meet the requirements of communication with protective relays and transducers within the power system substation environment. It has the same reliability as the protective relays themselves and does not result in their performance being degraded in any way. Error checking and noise rejection have been of major importance in its design.



K-Bus transmission layer The communication port is based on RS485 voltage transmission and reception levels with galvanic isolation provided by a transformer. A polled protocol is used and no relay unit is allowed to transmit unless it receives a valid message, addressed to it without any detected error. Transmission is synchronous over a pair of screened wires and the data is FM0 coded with the clock signal to remove any dc component so that the signal will pass through transformers. With the exception of the master units, each node in the network is passive and any failed unit on the system will not interfere with communication to the other units. The frame format is HDLC and the data rate is 64kbits/s.

2.2

K-Bus connections Connection to the K-Bus port is by standard Midos 4mm screw terminals or snap-on connectors. A twisted pair of wires is all that is required; the polarity of connection is not important. It is recommended that an outer screen is used with an earth connected to the screen at the master station end only. Termination of the screen is effected with the “U” shaped terminal supplied and which has to be secured with a self tapping screw in the hole in the terminal block just below terminal 56, as shown in the diagram. Operation has been tested up to 32 units connected along 1,000 metres of cable. The specification for suitable cable will be found in the technical data section. The method of encoding the data results in the polarity of the connection to the bus wiring being unimportant. Note:

K-Bus must be terminated with a 150Ω resistor at each end of the bus. The master station can be located at any position, but the bus should only be driven from one unit at a time.

1

4 5

6 5

K-Bus Screened 2 core cable

Figure 1: Typical K-Bus connection diagram



Ancillary equipment The minimum requirement to communicate with the relay is a K-Bus/IEC 60870-5 converter box type KITZ and suitable software to run on an IBM or compatible personal computer. RS232 interconnection lead for connecting the KITZ to a personal computer (PC) and software as described in Section 3.

Section 3. SOFTWARE SUPPORT 3.1

Courier Access The Courier Access program is supplied with each KITZ and it allows on-line access to any relay or other slave device on the system. It polls all available addresses on the bus to build a list of the active relays. Each relay can be programmed with a product description (16 characters) and a plant reference (16 characters). A particular relay may then be chosen and accessed to display a table listing the menu column headings. Selecting a heading from the list and pressing the return key of the computer returns the full page of data that has been selected. Selecting a setting from the displayed page and pressing the return key again will bring up the setting change box displaying the current setting value and the maximum and minimum limits of setting that have been extracted from the relay. A new setting may be typed in and entered. The new value will be sent to the relay and the relay will send back a copy of the data it received. If the returned value matches what was sent, it is judged to have been received correctly and the display asks for confirmation that the new setting is to be entered. When the execution command is issued the relay checks the setting is within limits, stores it, then replies to state if the new value has been accepted, or rejected. If the setting selected is password protected, the relay will reply that access is denied. Any data received in error is automatically resent. Any data not understood, but received without error is ignored. A complete setting file can be extracted from the relay and stored on disc and printed out for record purposes. The stored settings can also be copied to other relays. Control commands, such as close/trip of a circuit breaker, are actioned in the same way as setting changes and can be achieved with this program by using the setting change mechanism. This program supports modem connection but it cannot extract event or disturbance records.

3.2

PAS&T The Protection Access Software and Toolkit (PAS&T) program performs all the functions described for the Courier Access program, but additionally it can perform the following functions: – Generate a table of all circuit breakers that can be controlled via the relays connected to K-Bus. These are listed by their plant reference and their open/ closed status is displayed. Selecting a circuit breaker from this table enables it to be controlled with all the background security described for setting changes. – Automatically extracts event records, displays them on screen, prints, or stores them to disc.



– Automatically extracts disturbance records and stores them to disc in COMTRADE format. – Poll the relay for selected data at set intervals and displays the values on screen, or stores a selected number of values that it can plot on screen to show trend information. – Display coded or decoded messages on screen to help de-bug the communication system. – The auto-addressing feature allocates the next available address on the bus to a new relay. 3.3

K-Graph This program, supplied with PAS&T, can display disturbance records and print them. The COMTRADE format in which the files are stored can also be loaded into an Excel, or similar spreadsheet program.

3.4

Courier-Com Courier-Com is a Windows based setting program that can be used off-line, ie. without the relays being connected. Setting files can be generated in the office and taken to site on floppy disc for loading to the relays. This program can be used to down-load the settings to the relay, alternatively ACCESS or PAS&T may be used.

3.5

PC requirements To operate fully, the above programs require: IBM PC/XT/AT/PS2 or true compatible. 640kB of main memory RAM Graphics adapter CGA, EGA, VGA or MDA Serial adapter port configured as COM1 or COM2 (RS232) Floppy disk drive 3.5 inch MS-DOS 3.2 or later/IBM PC-DOS 3.2 or later Parallel printer port for optional printer. Additional equipment Printer RS-232 link. KITZ 101 K-Bus/ RS232 communication interface. Modem

3.6

Modem requirements ALSTOM T&D Protection & Control Ltd have adopted the IEC 60870-5 ft1.2 frame format for transmitting the courier communication language over RS-232 based systems, which includes transmission over modems. The IEC 60870-5 ft1.2 specification calls for an 11-bit frame format consisting of 1 start bit, 8 data bits, 1 even parity bit and 1 stop bit. However, most modems cannot support this 11-bit frame format, so a relaxed 10-bit frame format is supported by the Protection Access Software & Toolkit and by the KITZ, consisting of 1 start bit 8 data bits, no parity and 1 stop bit.



Although Courier and IEC 60870 both have inherent error detection, the parity checking on each individual character in the 11-bit frame provides additional security and is a requirement of IEC 60870 in order to meet the error rate levels it guarantees. It is therefore recommended that modems should be used which support these 11-bit frames. The following modem has been evaluated for use with the full IEC 60870 ft1.2 protocol and is recommended for use: Motorola Codex 3265 or 3265 Fast Other modems may be used provided that the following features are available; refer to the modem documentation for details on setting these features: – Support for an 11 bit frame (1 start bit, 8 data bits, 1 even parity bit and 1 stop bit). This feature is not required if the 10-bit frame format is chosen. – Facility to disable all error correction, data compression, speed buffering or automatic speed changes. – It must be possible to save all the settings required to achieve a connection in non-volatile memory. This feature is only required for modems at the outstation end of the link. Notes: 1. The V23 asymmetric data rate (1200/75bits/s) is not supported 2. Modems made by Hayes do not support 11 bit characters.

Section 4. DATA FOR SYSTEM INTEGRATION 4.1

Differences between K Range series 1 and series 2 relays As far as system integration is concerned there should be little difference between relays from series 1 and series 2. However, the following should be noted: Changing the communication address is now password protected for added security and to change the address the password must first be entered. This does not apply to the auto-addressing facility available within the Courier language that will apply the next available address on the bus to a relay set to address 0, nor the new address feature that allows a relay to be directly addressed by serial number sent to the global address 255. Both auto-addressing and direct addressing by serial number are supported by PAS&T, but direct addressing by serial number is also supported by Courier Access. Measurement functions retain their original cell references and some additional measurements will be available on the K Range series 2 relays. The data under fault records has been rearranged to enable five full fault records to be stored. The menu cell references for these have changed and reference should be made to Chapter 3, Section 6 for the new cell locations. A notable change is that the circuit breaker operation time which was stored in menu cell 0109 is now to be found in menu cell 010B. Additional input masks and output masks have also been generated for the new functions and this has resulted in them being renumbered. Software function links have been added for the new functions and they must be set to “1” in order to select the new features. Previously these links were unused



and hence set to “0” by default. The functions of some existing links have been changed. Reference should be made to the logic diagrams to determine how they should be set for series 2 relays. Application setting files for series 1 relays will require some modification before they can be used with series 2 relays. 4.2

Relay address The relay can have any address from 1 to 254 inclusive. Address 255 is the global address that all relays, or other slave devices, respond to. The Courier protocol specifies that no reply shall be issued by a slave device in response to a global message. This is to prevent all devices responding and causing contention on the bus. Each relay is supplied with its address set to 255 to ensure that when connected to an operational network it will not have a conflicting address with another device that is already operational. To make the new device fully operational it must have its address set. The address can be changed manually by entering the password and changing the address by the setting change method via the user interface on the front of the relay. Alternatively, if the software running on the PC supports auto-addressing, the relay address can be set to 0 and the auto-addressing feature of the PC software turned on. The relay will then be automatically set to the next available address on the bus. PAS&T software supports both these features. If the address is 255, or unknown, the device address can be changed by sending a new address, in a global message, to a device with a particular serial number. This method (supported by PAS&T, Courier Access and Courier-Com) is useful for devices that are not provided with a user interface with which to read or change the current address.

4.3

Measured values Any measured value can be extracted periodically by polling the relay. Measured values are stored in the same menu locations in the KCGG/KCEG/KCEU relays and the KMPC measurement centre.

4.4

Status word A status byte is contained in every reply from a slave device. This is returned by the relay at the start of every message to signal important data on which the master station may be designed to respond automatically. The flags contained are: Bit 0 Bit 1 Bit 2 Bit 3 Bit 4 Bit 5 Bit 6 Bit 7

– – – – – – – –

1 1 1 1 1 1 1 1

= = = = = = = =

Disturbance record available for collection Plant status word changed Control status word changed Relay busy, cannot complete reply in time Relay out of service Event record available for retrieval Alarm LED lit Trip LED lit

Bits 6 and 7 are used to mimic the trip and alarm indication on the frontplate of the slave devices. They cannot be used to extract fault and alarm information from a slave device because they cannot be guaranteed to be set for a long enough period to be identified.



Bits 5 and 0 enable the master station to respond automatically and extract event records and disturbance records, if they are so programmed. 4.5

Plant status word The plant status word can be found at menu location 000C and each pair of bits in the plant status word is used to indicate the status (position) of items of plant controlled via the relay. Only the circuit breaker can be controlled via the relays described in this service manual and the associated bits in the plant status word are defined as follows: Bit 1 Bit 0 0 0 1 1

0 1 0 1

Bit 8 Bit 9 0 0 1 1

0 1 0 1

–

Circuit breaker 1

– – – –

No CB connected (auxiliary CB1 contacts faulty) CB1 open CB1 closed Auxiliary CB1 contacts or wiring faulty

–

Circuit breaker 2

– – – –

No CB connected (auxiliary CB2 contacts faulty) CB2 open CB2 closed Auxiliary CB2 contacts or wiring faulty

The master PAS&T control unit software makes use of this information to generate a table of all the circuit breakers and isolators that can be controlled and to show their current status. To make this information available to the master control unit it is necessary to allocate a logic input that will be energised when the circuit breaker is closed in input mask [0A0E CB CLOSED IND] and one that is energised when the circuit breaker is open in input mask [0A0F CB OPEN IND]. Bits 0 and 1 will then indicate the position of the circuit breaker. If the circuit breaker can be racked into one of two positions, such that it can be connected to busbar 1 or busbar 2, then a third logic input that will be energised when the circuit breaker is connected to busbar 2 must be assigned in the input mask [0A10 CB BUS 2]. The circuit breaker open/closed states will then be transferred to bits 8 and 9 when the circuit breaker is in position for connecting the feeder to busbar 2. The circuit breaker can then be controlled with the appropriate open and close commands. 4.6

Control status word The control status word will be found in menu cell 000D. It is used to transfer control information from the slave device to the master control unit. However, the relays described in this manual are protection relays and this feature is not used.

4.7

Logic input status word The status of the logic control inputs can be observed by polling menu cell 0020, where the lowest 8 bits of the returned value indicates the status of each of the 8 logic inputs. This cell is read only.

4.8

Output relay status word The status of the output relays can be observed by polling menu cell 0021, where the lowest 8 bits of the returned value indicates the status of each of the 8 output relays. This cell is read only.



Alarm indications The status of the internal alarms produced by the relays self test routine can be observed by polling menu cell 0022, where the lowest 7 bits of the returned value indicate the status of each of the alarms. Bit 6 can be set/reset, in order to test the watchdog relay. No other control actions are possible on this cell. Bit 0 Bit 1 Bit 2 Bit 3 Bit 4 Bit 5 Bit 6

4.10

Error in factory configuration detected (relay inoperative) Error in calibration detected (relay running in uncalibrated state) Error detected in storage settings (relay operationsal, check settings) No service (protection out of service) No samples (A/D converter not sampling) No Fourier (Fourier routine not being performed) Test watchdog (set to 1 to test and rest to 0 afterwards)

Event records An event may be a change of state of a control input or an output relay. It may be a setting that has been changed locally or a protection or control function that has performed its intended function. A total of 50 events may be stored in a buffer, each with an associated time tag. This time tag is the value of a timer counter that is incremented every 1ms. The event records can only be accessed via the serial communication port when the relay is connected to a suitable master station. When the relay is not connected to a master station the event records can still be extracted within certain limitations: – The event records can only be read via the serial communication port and a K-Bus/IEC 60870-5 interface unit will be required to enable the serial port to be connected to an IBM or compatible PC. Suitable software will be required to run on the PC so that the records can be extracted. – When the event buffer becomes full the oldest record is overwritten by the next event. – Records are deleted when the auxiliary supply to the relay is removed, to ensure that the buffer does not contain invalid data. Dual powered relays are most likely to be affected. – The time tag will be valid for 49 days assuming that the auxiliary supply has not been lost within that time. However, there may be an error of ±4.3s in every 24 hour period due to the accuracy limits of the crystal. This is not a problem when a master station is on line as the relays will usually be polled once every second or so. The contents of the event record are documented in Chapter 5, Section 5.

4.11

Notes on recorded times As described in Chapter 5, Section 5.2, the event records are appended with the value of a 1 millisecond counter and the current value of the counter is appended to the start of each reply form a relay. Thus it is possible to calculate how long ago the event took place and subtract this from the current value of the real time clock in the PC. If transmission is to be over a modem there will be additional delays in the communication path. In which case the KITZ can be selected to append the real time at which the message was sent and this value can then be used in the



conversion of the time tags. With this method of time tagging, the time tags for all relays on K-Bus will be accurate, relative to each other, regardless of the accuracy of the relay time clock. See also Chapter 5, Section 6.6 for additional information on time tagging accuracy. 4.12

Protection flags The protection flags hold the status of the various protection elements in the relay and it is from these that the fault flags are generated. They are transmitted in the event records as part of a fault record and this is the only way they can be accessed. The following table lists the protection flags: Bit position 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31

Hexadecimal mask 0x00000001L 0x00000002L 0x00000004L 0x00000008L 0x00000010L 0x00000020L 0x00000040L 0x00000080L 0x00000100L 0x00000200L 0x00000400L 0x00000800L 0x00001000L 0x00002000L 0x00004000L 0x00008000L 0x00010000L 0x00020000L 0x00040000L 0x00080000L 0x00100000L 0x00200000L 0x00400000L 0x00800000L 0x01000000L 0x02000000L 0x04000000L 0x08000000L 0x10000000L 0x20000000L 0x40000000L 0x80000000L

Protection function PhA lowset trip PhB lowset trip PhC lowset trip E/F lowset trip PhA 1st highset trip PhB 1st highset trip PhC 1st highset trip E/F 1st highset trip PhA 2nd highset trip PhB 2nd highset trip PhC 2nd highset trip E/F 2nd highset trip PhA lowset forward/normal start PhB lowset forward/normal start PhC lowset forward/normal start E/F lowset forward/normal start PhA lowset reverse start PhB lowset reverse start PhC lowset reverse start E/F lowset reverse start Thermal overload Phase undercurrent trip Undervoltage trip Manual remote CB trip AUX1 trip AUX2 trip AUX3 trip Manual remote CB close Breaker fail trip Trip occurred in GROUP 2 settings E/F Undercurrent trip Thermal overload alarm

This 32 bit word can be found in packet #4 of the event record as the menu cell value. A decoded text form can be found in packet #3 as the ASCII Text Description of the event (refer to Courier User Manual). The value can be decoded to establish which elements were operated at the time of the event. The bit position is identical for K Range series 1 and series 2 relays with the exception of following bits: – Bit 20 for series 1 relays indicated cold load start; for series 2 relays this function is transferred to AUX3 and bit 20 now indicates operation of the thermal overload element. – Bit 31 for series 1 relays was not used. For series 2 relays bit 31 indicates the operation of the thermal overload alarm element.



Fault records Although fault records are stored in the event records and they may be extracted in this way, it may be necessary in some instances to extract the fault records directly. To do this, the record number must be first entered in menu cell 0101 so that the correct fault record can be extracted. Fn is the record for the last fault; Fn-1 is the previous fault record and Fn-4 is the oldest record. Then the values for menu column 01 should be requested. The Courier User Guide gives the detailed commands associated with these functions.

4.14

Disturbance records The procedure for setting up the disturbance recorder in the relays, is fully described in Chapter 5, Section 6 of this manual. If the extraction of these records is to be incorporated in some bespoke software program reference should be made to the Courier User Guide for the relevant commands that are necessary to extract the records. It is recommended that all such records are stored in a Comtrade format to enable commercially available programs to use the files. Comtrade includes minimum and maximum values for each analogue chanel. In all K Range relays these are 0 and 32767.

Section 5. SETTING CONTROL Control functions via a K Range relay can be performed over the serial communication link. They include change of individual relay settings, change of setting groups, remote control of the circuit breaker, and operation and latching selected output relays. Remote control is restricted to those functions that have been selected in the relays menu table and the selection cannot be changed without entering the password. CRC and message length checks are used on each message received. No response is given for received messages with a detected error. The master station can be set to resend a command a set number of times if it does not receive a reply or receives a reply with a detected error. Note: Control commands are generally performed by changing the value of a cell and are actioned by the setting change procedure, as described in Chapter 6, 3.1, and have the same inherent security. No replies are permitted for global commands as these would cause contention on the bus; instead a double send is used for verification of the message by the relay for this type of command. Confirmation that a control command, or setting change, has been accepted is issued by the relay and an error message is returned when it is rejected. The command to change setting group does not give an error message when the group 2 settings are disabled unless link SD3=0 to inhibit response to a remote setting group change commands.



Remote setting change The relay will only respond to setting change commands via the serial port if link SD0=1. Setting SD0=0 inhibits all remote setting changes with the exception of the SD software links and the password entry. Thus, with link SD0=0, remote setting changes are password protected. To change them, the password must be remotely entered and the function link SD function link SD0 set to “1” to enable remote setting changes. When all setting changes have been made, set link SD0=0 to restore password protection to remote setting changes.

5.2

Remote control of setting group The setting group selection is fully described in Chapter 4, Section 12.1 including the remote control of this function. Group 2 must be activated before it can be selected by setting software link SD4=1. Set link SD3=1 to enable the relay to respond to change setting group commands, via the serial port to select group 2 and set SD4=1 to inhibit this function. If the remote setting changes have been selected to have password protection, as described in Section 5.1, then it can also be applied to the remote setting group selection as follows. Set link SD3=0 to inhibit remote setting changes, then set link SD0=1 to enable remote setting changes and set link LOG8=1. The group 2 settings will then be in operation and setting link SD0=0 will restore the password protection. If conventional SCADA has an output relay assigned to select the alternative setting group then it may be used to energise a logic input assigned in the input mask [0A0D STG GRP 2]. In this case set link SD3=0.



Section 6. REMOTE OPERATION OF OUTPUT RELAYS K Range series 2 relays (except for KCEU) respond to the load shed by level Courier commands. These were intended to be used to control the load shedding control of conventional voltage regulating relays and can of course still be used for that purpose. However, it also provides a way of remotely operating and latching selected output relays. In the following example it is assumed that relays are allocated in the load shedding output masks as follows: RLY0 assigned in [0B14 LEVEL 1] RLY1 assigned in [0B15 LEVEL 2] RLY2 assigned in [0B16 LEVEL 3] The following truth table then applies: Command

RLY 0

RLY 1

RLY 3

Load shed to level 0

0

0

0


1

0

0


0

1

0


0

0

1

If the relays are assigned as follows : RLY0 assigned in [0B14 LEVEL 1] RLY1 assigned in [0B15 LEVEL 2] RLY0, RLY1 & RLY2 assigned in [0B16 LEVEL 3] The truth table would read: Command

RLY 0

RLY 1

RLY 3


0

0

0


1

0

0


0

1

0


1

1

1

The relays will retain their selected state until a new command is received. The settings will be stored when the relay is powered-down and restored again on power-up. This allows these particular outputs to be used to select other functions such as block sensitive earth fault, or inhibit instantaneous low set overcurrent elements.



Section 7. CIRCUIT BREAKER CONTROL To set-up the relay for circuit breaker control, relay RLY7 must be assigned in output mask [0B0D CB TRIP] and RLY6 in output mask [0B0E CB CLOSE]. Some circuit breakers require the closing pulse to be interrupted when a trip command is issued during the closing sequence, such as when closing onto a fault. This is to prevent pumping of the circuit breaker, ie. reclosing again when the trip signal is terminated, and it can be arranged by setting link LOG9 = 1. Some other types of circuit breaker require the close pulse to be maintained and to achieve this, set link LOG9 = 0.

SD2 0 1

Block start

0A07 L TRIP 7 6 5 4 3 2 1 0

≥

Trip circuit breaker 0A08 L CLOSE 7 6 5 4 3 2 1 0


1

0B0D CB TRIP 7 6 5 4 3 2 1 0

tTRIP

1

≥

1

≥

0A09 EXT. TRIP 7 6 5 4 3 2 1 0

1

≥

RLY3 LOGA 0 1 LOG7 0 1

I

 I o> I

1

≥

1

≥

Latch flags Generate fault records and Copy to events records

Figure 2: Circuit breaker control logic

7.1

Remote control of circuit breaker Set link SD2=1 to enable remote control of the circuit breaker. The ACCESS, PAS&T, or other suitable program that supports this feature can then be used to perform the remote control of this plant item. When using PAS&T, logic inputs must be assigned in input masks [0A0E CB CLOSED IND] and [0A0F CB OPEN IND] to indicate the status of the circuit breaker so that a table of circuit breakers and their status can be generated. If the circuit breaker can be racked into an alternative position, such that it can then be connected to busbar 2 instead of busbar 1, then a logic input must be assigned in mask [0A10 CB BUS2] if this information is required to be displayed by PAS&T. Password protection for remote circuit breaker control can be applied as follows. Set link SD2=0 to inhibit remote changes. To make a remote change, enter the password, set link SD2=1, and send the command to control the circuit breaker. Then to re-establish password protection set link SD2=0 again.

7.2

Local control of the circuit breaker If local controls are routed to the circuit breaker via the logic inputs assigned in masks [0A07 Ltrip] and [0A08 Lclose], the circuit breaker maintenance records will be updated for local control of the circuit breaker. In this case it will be the action of relay RLY7 operating that causes the record to be incremented as described in Chapter 5, Section 4.1.



Safe manual closing of the circuit breaker There have been instances of injury to personnel when closing a circuit breaker onto a fault. So, from a health and safety point of view, it is sometimes considered necessary to manually close the circuit breaker from a safe distance. This is particularly important, when the autoreclose has locked-out, or after maintenance on the primary plant when temporary earth clamps may have been left connected. If the closure of the circuit breaker is routed via the KCGG/KCEG/KCEU relay, any of the following procedures may be considered:

7.3.1

Closing the circuit breaker via the serial communication port If the serial port of the relay has no connections made to it, then the terminals 54 and 56 can be connected to a jack plug on the front of the panel. To close the circuit breaker from a safe distance it is then only necessary to plug in an extension lead and connect it to a laptop computer. The circuit breaker can then be closed as described in Section 7.1.

7.3.2

Closing the circuit breaker via a lead mounted push-button A spare logic input of the relay can be wired, via the field voltage supply of the relay, to a plug that is mounted on the panel of the cubicle. In this case a jack plug is not advised because the two terminals may be temporarily short circuited when the plug is being inserted. This logic input is then assigned in the input mask [0A08 Lclose]. To operate the circuit breaker an extension lead is plugged into the socket and a lead mounted push-button at the other end is then pressed to initiate a pulse of fixed duration to close the circuit breaker. For extra security, one of the auxiliary timers may be connected in the control path, so that the push-button has to be pressed for the set time of the timer before the circuit breaker will close.

7.3.3

Delayed manual closure of the circuit breaker If auxiliary timer tAUX3 is not being used for some other purpose and either tAUX1 or tAUX2 is also available then proceed as follows: 1. Set link LOGB = 1 to give tAUX3 a delay on drop-off. 2. Allocate an output relay in mask [0B12 AUX3] and connect its contact to a spare logic input. 3. Assign this logic input in input mask [0A0A AUX1] to start tAUX1 or [0A0C AUX2] to start tAUX2. 4. Assign an output relay in mask [0B10 AUX1] or [0B11 AUX2] depending on the timer to be used. 5. Energise a logic input via the contact of this output relay and assign it in input mask [0A08 Lclose] to initiate the closing pulse. 6. Allocate a logic input in mask [0A0C AUX3] and arrange for this to be energised via a switch (preferably a key switch) that is spring loaded in the off position. When the initiating switch is closed momentarily timer tAUX3 will pick-up its output relay which will remain picked-up for the set time of tAUX3. Timer tAUX1 (or tAUX2) will be picked up by the output relay assigned to tAUX3 and when it times out it will pick-up a relay that triggers the close pulse via the Lclose input. The time setting for tAUX1 (ortAUX2) should be the required delay and tAUX3 should be set 2 seconds longer. When tAUX3 times out the circuit resets.



The close sequence can be interrupted by breaking the link, from the output of tAUX3 to the logic input initiating tAUX1 (or tAUX2, whichever is being used), with a push-button or an alternative position on the key switch. Note that these timers have very wide setting ranges and that the delay is in the order of 20 to 30 seconds only. Where no auxiliary timers are available the close pulse could be initiated by energising a logic input assigned in the input mask [0A08 Lclose] via a push button connected via a twisted pair of wires of sufficient length. If an auxiliary timer is available and is connected in the initiating path it would add to the security.

Section 8. AIDS TO CIRCUIT BREAKER MAINTENANCE The information gathered by the relay can be of assistance in determining the need for circuit breaker maintenance. The circuit breaker opening time is recorded under FAULT RECORDS. If this value is monitored, any significant increase may be used as an indication that circuit breaker maintenance is required. Additionally the number of circuit breaker operations is recorded under MEASUREMENTS (2). An indication of the summated contact breaking duty which is recorded separately for each phase will also be found under this heading.


Chapter 7 Technical Data

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242 1. 1.1 1.2 2. 2.1 2.2 2.3 2.4 3. 3.1 3.2 4. 4.1 4.2 4.3 5. 5.1 5.2 5.3 5.4 5.5 6. 7. 7.1 7.2 7.3 7.4 7.5 7.6 7.7 7.8 7.9 8. 8.1 8.2 8.2.1 8.2.2 8.3 8.4 9. 10. 10.1 10.2 11. 12. 13. 14.

RATINGS Inputs Outputs BURDENS Current circuits Reference voltage Auxiliary voltage Opto-isolated inputs OVERCURRENT SETTING RANGES Auxiliary powered relays Dual powered relays TIME SETTING RANGES Inverse definite minimum time (IDMT) Definite independent time Auxiliary time delays OTHER PROTECTION SETTINGS Directional Thermal Undervoltage Underfrequency Ratios MEASUREMENT (DISPLAYED) ACCURACY Reference conditions Current Time delays Directional Thermal Undervoltage Under frequency Auxiliary timers Measurements INFLUENCING QUANTITIES Ambient temperature Frequency With frequency tracking Without frequency tracking (KCGG 122 KCEG 112) Auxiliary supply System X/R OPTO-ISOLATED INPUTS Output Relays Output relays 0 to 7 Watchdog OPERATION INDICATOR COMMUNICATION PORT CURRENT TRANSFORMER REQUIREMENTS HIGH VOLTAGE WITHSTAND


1 1 1 2 2 2 3 3 3 3 3 4 4 5 5 5 5 5 6 6 6 6 6 6 6 7 7 7 7 7 8 8 8 8 8 8 8 9 9 9 10 10 10 10 10 10 12



14.1 14.2 14.3 14.4 14.5 14.6 14.7 15. 15.1 15.2 15.3 16. 16.1 16.2 16.3 16.4 16.5 16.6 17. 18. 18.1 18.2 18.3

Dielectric withstand IEC 60255-5: 1977 High voltage impulse IEC 60255-5: 1977 Insulation resistance IEC 60255-5: 1977 High frequency disturbance IEC 60255-22-1: 1988 Fast transient IEC 60255-22-4: 1992 EMC compliance Electrostatic discharge test IEC 60255-22-2: 1996 IEEE/ANSI SPECIFICATIONS Standard for relay systems associated with electrical power apparatus Surge withstand capability Radio electromagnetic interference ENVIRONMENTAL Temperature IEC 60255-6: 1988 Humidity IEC 60068-2-3: 1969 Enclosure protection IEC 60529:1989 Vibration IEC 60255-21-1:1988 Shock and bump IEC 60255-21 2:1988 Seismic IEC 60255-21-3:1993 MODEL NUMBERS FREQUENCY RESPONSE Transient overreach Peak measurement Frequency response of directional elements

12 12 12 12 12 12 12 13 13 13 13 13 13 13 13 13 13 13 14 16 17 17 18

Figure 1: Figure 2: Figure 3:

Response of Fourier filtering Response when frequency tracking Frequency response when relay responds to both peak and Fourier values

16 17 18



Section 1. RATINGS 1.1

Inputs Current input (In)

Rated (In) (A)

Continuous (xIn)

3s (xIn)

1s (A)

Auxiliary powered

1 5

3.2 3.2

30 30

100 400

Dual powered

1 5

2.4 2.4

30 30

100 400

Voltage input (Line)

Rated (Vn) (V)

Continuous (xVn)

10s (xVn)

110 440

4 2

5.4 2.6

Rated voltage (V)

DC supply (V)

AC supply (V)

Crest (V)

Auxiliary powered

24-125 48-250

19-150 33-300

50-133 87-265

190 380

Dual powered

100-250

60-300

60-265

380

Nominal rating (Hz)

Operative range (Hz)

50 or 60

45-65

Non-tracking

50

47-52.5

Non tracking

60

57-63

Rating (Vdc)

Off state (Vdc)

On state (Vdc)

50

≤12

≥35

Operative range Auxiliary voltage (Vx)

Frequency (Fn) Frequency tracking

Logic inputs 1.2

Outputs Field Voltage

48V dc (Current limited to 60mA)

Capacitor Trip

50V dc (680µF capacitor - Energy = 0.85J)



Section 2. BURDENS 2.1

Current circuits Auxiliary powered

Phase

Earth(1)

SEF(2)

Conditions

In

= 1A In = 1A In = 5A In = 5A

0.06 0.06 0.006 0.006

0.06 0.06 0.006 0.006

0.08 0.06 0.006 0.006

ohms at In ohms at 30In ohms at In ohms at 30In

Dual powered

Phase

Earth

SEF

In=1A

0.58 0.45 0.37 0.33 0.31 0.31 0.31

2.7 2.3 2.0 1.9 1.9 1.9 1.7

2.6 2.2 2.0 1.8 1.7 1.7 1.5

ohms at 0.5In for Vx =110V ohms at 1.0In for Vx = 110V ohms at 2.0In for Vx = 110V ohms at 5.0In for Vx = 110V ohms at 10In for Vx = 110V ohms at 20In for Vx = 110V ohms at 30In for Vx = 110V

In=1A

8.1 5.4 2.1 0.8 0.46 0.35 0.32

27.3 11.4 5.2 2.6 2.0 1.8 1.6

29.9 12.4 5.6 2.6 2.0 1.8 1.6

ohms at 0.5In for Vx = 0V ohms at 1.0In for Vx = 0V ohms at 2.0In for Vx = 0V ohms at 5.0In for Vx = 0V ohms at 10In for Vx = 0V ohms at 20In for Vx = 0V ohms at 30In for Vx = 0V

In=5A

0.034 0.027 0.024 0.022 0.021 0.021 0.021

0.106 0.088 0.078 0.072 0.071 0.069 0.062

0.108 0.089 0.079 0.071 0.068 0.066 0.064


In=5A

0.333 0.220 0.091 0.037 0.026 0.022 0.021

1.082 0.454 0.207 0.103 0.078 0.073 0.070

1.219 0.500 0.225 0.101 0.077 0.071 0.066


Note 1: For standard and special earth fault settings in KCEG relays Note 2: For sensitive earth fault settings in KCEG 112/152 and KCEU relays 2.2

Reference voltage Vn = 110V Vn = 440V

0.02VA 0.08VA

@ 110V phase/phase @ 440V phase/phase



Auxiliary voltage DC supply 2.5 – 6.0W at Vx max with no output relays or logic inputs energized 4.0 – 8.0W at Vx max with 2 output relays & 2 logic inputs energized 5.5 – 12W at Vx max with all output relays & logic inputs energized AC supply 6.0 – 12VA at Vx max with no output relays or logic inputs energized 6.0 – 14VA at Vx max with 2 output relays & 2 logic inputs energized 13 – 23VA at Vx max with all output relays & logic inputs energized

2.4

Opto-isolated inputs DC supply 0.25W per input (50V 10kΩ)

Section 3. OVERCURRENT SETTING RANGES 3.1

Auxiliary powered relays Phase fault

Threshold (Is)

Step size

0.08 – 3.2In 0.08 – 32In 0.08 – 32In 0.02 – 3.2In

0.01In 0.01In 0.01In 0.01In

0.005 – 0.8In 0.005 – 8.0In 0.005 – 8.0In 0.005 – 0.8In

0.0025In 0.0025In 0.0025In 0.0025In

0.02 – 32In 0.02 – 32In 0.02 – 32In 0.02 – 3.2In

0.01In 0.01In 0.01In 0.01In

Io<

0.001 – 0.16In 0.001 – 1.6In 0.001 – 1.6In 0.0005 – 0.16In

0.0005In 0.0005In 0.0005In 0.0005In

General

0.95Is

I> I>> I>>> I<

Standard earth fault

Io> Io>> Io>>> Io<

Special earth fault

Io> Io>> Io>>> Io<

Sensitive earth fault

Io> Io>> Io>>>

Reset 3.2

Dual powered relays Phase fault

I> I>> I>>> I<

Standard earth fault

Io> Io>> Io>>> Io<

Special earth fault

Io> Io>> Io>>> Io<

Threshold (Is)

Step size

0.4 – 2.4In 0.4 – 32In 0.4 – 32In 0.02 – 2.4In

0.01In 0.01In 0.01In 0.01In

0.005 – 0.6In 0.005 – 8.0In 0.005 – 8.0In 0.005 – 0.6In

0.0025In 0.0025In 0.0025In 0.0025In

0.02 – 2.4In 0.02 – 32In 0.02 – 32In 0.02 – 2.4In

0.01In 0.01In 0.01In 0.01In



Sensitive earth fault

Io>

Io<

0.001 – 0.16In 0.001 – 1.6In 0.001 – 1.6In 0.0005 – 0.16In

General

0.95Is

Io>> Io>>>

Reset

0.0005In 0.0005In 0.0005In 0.0005In

The sensitive earth fault settings are only available on KCEU 142/242 and sensitive versions of KCEG 112/152 relays Note:

Operation is not guaranteed for earth faults below 0.2In, regardless of the actual setting, when the load current is below 0.4 In and the auxiliary voltage is not available. See also the special application notes for dual powered relays and the table in Chapter 4, Section13.3 regarding the maximum number of outputs and inputs that may be energized at any one time.

Section 4. TIME SETTING RANGES 4.1

Inverse definite minimum time (IDMT) Nine inverse reset time characteristics are available and the general mathematical expression for the curves is: k t = TMS

I

a

Is

where TMS

+c Ð1

= = I = Is k, c, a =

Time Multiplier (0.025 to 1.5 in 0.025 steps) Fault current Overcurrent setting Constants specifying curve

Curve No. Description 0 1 2 3 4 5 6 7 8 9

seconds

Definite Time Standard Inverse Very Inverse Extremely Inverse Long Time Inverse Moderately Inverse Very Inverse Extremely Inverse Short Time Inverse Rectifier Protection

Name DT SI30xDT VI30xDT EI10xDT LTI30xDT MI VI EI STI30xDT RECT

IEC Curve

k

c

a

– A B C – D E F – –

0 0.14 13.5 80 120 0.103 39.22 56.4 0.05 45900

0 to 100 0 0 0 0 0.228 0.982 0.243 0 0

1 0.02 1 2 1 0.02 2 2 0.04 5.6

Although the curves tend to infinity at the setting current value ( Is), the guaranteed minimum operation current is 1.05 Is ±0.05Is for all inverse characteristic curves, except curve 10 for which the minimum operating current is 1.6 Is ±0.05Is (see section on rectifier protection).



Curves numbers 1, 2, 4, and 8 become definite time for currents in excess of 30xIs. Curve 3 becomes definite time for currents above 10x Is to give extra time grading steps at high current levels. Curves 1, 2 and 3 are curves A, B and C in IEC 60255-3. Curves 5, 6 and 7 are slightly different in that they tend to a definite operating time given by the constant (a) at high fault levels. Curves 5, 6 and 7 were proposed by IEEE/ANSI, for inclusion in the IEC standard IEC 60255-3, as curves D, E and F. 4.2

Definite independent time to>/t> tRESET to>>/t>> to>>>/t>>>

4.3

Definite time Definite time Definite time Definite time

Setting range

Step size

0 to 100s 0 to 60s 0 to 100s 0 to 10s

0.01s 0.1s 0.01s 0.01s

Setting range

Step size

0 to 10s 0 to 28 days 0 to 28 days 0 to 28 days 0 to 10s 0.5 to 5s 0.5 to 5s

0.01s 0.01s min – graded 0.01s min – graded 0.01s min – graded 0.01s 0.1s 0.1s

Auxiliary time delays tV< tAUX1 tAUX2 tAUX3 tBF tTRIP tCLOSE

Definite time Definite time Definite time Definite time Definite time Definite time Definite time

Section 5. OTHER PROTECTION SETTINGS 5.1

Directional Characteristic angle (Øc) –180°.....0°.....+180° Operating boundary

Øc ±90° (±85° for wattmetric)

Voltage threshold Vp>

0.6V 2.4V

for Vn = 110V for Vn = 440V

Voltage threshold Vop>

0.6V to 80V – step 0.2V 2.4V to 320V – step 0.8V

for Vn = 110V for Vn = 440V

Additional settings for KCEU 142/242 relays

5.2

Po> (1A)

0 – 20W

50mW steps

Po> (2A)

0 – 100W

250mW steps

Thermal Time Constant

1 to 120 minutes – step 1 minute

Current Rating Ith>

0.08In to 3.2In – step 0.01In

Thermal alarm level th>

0 – 110% of Ith> 1% of Ith> steps



Undervoltage Undervoltage (V<)

5.4

0 to 220V for Vn = 110V 0 to 880V for Vn = 440V

Underfrequency Under frequency (F<)

46 to 64Hz step 0.01Hz

Reset

F<+0.05Hz

Underfrequency function is not available on KCEU 142/242 relays 5.5

Ratios CT ratios

9999 : 1

Default = 1 : 1

VT ratios

9999 : 1

Default = 1 : 1

Section 6. MEASUREMENT (DISPLAYED) Voltage

(0 – 327) x VT ratio

volts phase/neutral

Current

(0 – 64)In x CT ratio

amps per phase

Power

(0 – 9.999)x1021

W

VAr

(0 – 9.999)x1021

VAr

VA

(0 – 9.999)x1021

VA

CB Operations

(0 – 65535)

Current2 broken

(0 – 9.999)x1021

A2 (or A)

Frequency

45 – 65 (or 0 )

Hz

Section 7. ACCURACY 7.1

7.2

Reference conditions Ambient temperature

20°C

Frequency

50Hz or 60Hz (whichever is set)

Time multiplier setting

1.0

Auxiliary voltage

24V to 125V (auxiliary powered) 48V to 250V (auxiliary powered) 100V to 250V (dual powered)

Fault Position

Within ±80 ° of the RCA where appropriate.

Current Undercurrent

Minimum operation

±10% (> 4 x minimum setting) ±20% (< 4 x minimum setting)

Overcurrent

Minimum operation Reset Repeatability

±5% ±5% ±2.5%

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242 Earth Fault

7.3


Minimum operation

±20% (@ minimum setting) ±10% (@2x minimum setting) ±5% (@ >4x minimum setting)

Time delays Reference range Operating time

IDMT except (EI) and (Rectifier)

±5% + (20 to 40)ms

2Is to 30Is

(t>/to>)

Extremely inv (EI) Rectifier Definite time

±7.5% + (20 to 40)ms ±7.5% + (20 to 40)ms ±0.5% + (20 to 40)ms

2Is to 10Is 2Is to 5Is 3Is to 30Is

Repeatability

Inverse time Definite time

±2% ±40ms ±0.5% or10ms

Overshoot time Reset time t>/to>

Less than 50ms Definite time

when current reduced to zero. ±1% ±50ms

Disengagement

I<

typically 35ms typically 30ms typically 30ms* typically 50ms* typically 50ms*

I>/Io>

t>/to> t>>/to>> t>>>/to>>>

*Minimum dwell disengagement time is affected if measuring circuit resets within 100ms of pick-up. For further information see Chapter 3, Section 5.6. 7.4

7.5

7.6

7.7

Directional Characteristic angle Øc

±2°

Operating boundary

Øc ±90° accuracy ±2°

PU – DO differential

less than 3° (typically <1°)

Polarizing voltage (Vp>)

±10% (at Øc ±80°)

Polarizing voltage (Vop>)

±10% (at Øc ±80°)

Wattmetric characteristic

±4% (typical)

Thermal Thermal (Ith>)

Minimum operation ±5%

Operation Time

±2% of TC from 1.2Ith> to 5Ith>

Undervoltage Undervoltage (V<)

±10%

Undervoltage delay (tV<)

±0.5%+(20 to 70)ms

Under frequency Under frequency (F<)

±0.02Hz from 46Hz to 64Hz



Auxiliary timers Operating time

Set time ±0.5%(set time)+(15 to 35)ms

Disengagement time

0 to 10ms (for timers alone) 15 to 30ms (including output relays and opto-inputs)

Breaker Fail Timer tBF 7.9

±0.5% or ±10ms

Measurements Voltage

±2%Vn (typical) – Reference range = 1 to 320 V

Current

±2%In (typical) – Reference range = setting range

Power

±2%Pn (typical)

VAr

±2%Pn (typical)

VA

±2%Pn (typical)

Frequency

(45 – 65Hz) ±0.02Hz (typical)

Section 8. INFLUENCING QUANTITIES 8.1

Ambient temperature

Operative range Current settings

±1%

Voltage settings

±0.03% per °C

Operation times

±1%

Angle measurement

<2°

8.2

Frequency

8.2.1

With frequency tracking

8.2.2

–25°C to +55°C

Operative range

46 to 65Hz (47 to 52Hz for KCEU relays)

Current setting

±1%

Voltage settings

±1%

Operating times

±1%

Angle measurement

<1°

Without frequency tracking (KCGG 122 KCEG 112) Reference range

47 to 52Hz or 57 to 61Hz

Current settings

±2%

Operating times

±2%

Angle measurement

<2°



Auxiliary supply

Current settings Voltage settings Operation times Angle measurement 8.4

Nominal

Operative range

24/125V

19 to 150V dc (aux powered) 50 to 133V ac (aux powered)

48/250V

33 to 300V dc (aux powered) 87 to 265V ac (aux powered)

100/250V

60 to 300V dc (dual powered) 60 to 265V ac (dual powered)

±0.5% ±0.5% ±0.5% ±0.5°

System X/R Transient overreach

<5%

Effect upon directional characteristics Effect upon Operating Times (fault 45° from RCA) <40ms (X/R < 30, I ≥5Is) <75ms (X/R ≤90, I ≥5Is) Minimum protection time delay for directional stability (fault 45° from RCA) 40ms (X/R ≤15, I ≤40In) Additional time delay incurred for forward direction fault (45° from RCA) ≤60ms (X/R ≤5, I <16In) ≤100ms (X/R ≤15, I <40In)

Section 9. OPTO-ISOLATED INPUTS Capture time

12.5 ±2.5ms at 50Hz 10.4 ±2.1ms at 60Hz

Release time

12.5 ±2.5ms at 50Hz 10.4 ±2.1ms at 60Hz

Minimum operating voltage

>35V dc

Maximum operating voltage

50Vdc

Input resistance

10kΩ (add 12kW for every additional 50V in excess of 50V)

Maximum series lead resistance

2kΩ for single input at 40V min. 1kΩ for 2 inputs in parallel at 40V min. 0.5kΩ for 4 inputs in parallel at 40V min.

Maximum ac induced loop voltage

50V rms (thermal limit)

Maximum capacitance coupled ac voltage

250V rms via 0.1µF



Section Section 10. OUTPUT OUTPUT RELAYS RELAYS 10.1

Output relays 0 to 7 Type Rating

10.2

1 make Make

30A and carr y for 0.2s

Carr y

5A continuous

Break

DC – 50W resistive 25W inductive (L/R = 0.04s) AC – 1250V 1250VA (maxi (maxima ma of of 5A) 5A) Subject to maxima of 5A and 300V

Watchdog Type Rating

1 make + 1 break Make

10A and carr y for 0.2s

Carr y

5A continuous

Break

DC – 30W resistive DC – 15W inductive (L/R = 0.04s) AC – 1250VA (maxima of 5A) Subject to a maxima of 5A and 300V

Durability

>10,000 op operations

Section 11. OPERATION OPERATION INDICATOR INDICATOR 3 light emitting diodes – internally powered. 16 character by 2 line liquid crystal display (with backlight).

Section Section 12. COMMUNIC COMMUNICA ATION PORT Language

Courier

Transmission

Synchronous – RS485 voltage levels

Format

HDLC

Baud Rate

64kbit/s

K-Bus Cable

Screened twisted pair

Length

1000m

Bus Loading

32 units (mulitdrop system)

Section 13. CURRENT TRANSFORMER TRANSFORMER REQUIREMENTS REQUIREMENTS CT requirements for use in typical applications are shown below. These CT requirements are based on a maximum prospective fault current of 50x relay rated current (In) and the relay having a maximum high-set setting of 25In. The CT requirements are designed to provide operation of the phase and earth fault elements.



Where the criteria for a specific application are in excess of those detailed above, or the actual lead resistance exceeds the limiting value quoted, the CT requirements may need to be increased. CT requirements for a variety of further applications are provided in publication R6096. Auxiliary powered relays relays – KCGG 122, 122, 142 and KCEG 112, 112, 142, 152 and KCEU 142 Relay and CT secondar y rating

Nominal output

Accuracy class

Accuracy limit factor

Limiting lead resistance (one way)

1A

2.5VA

10P

20

0.6Ω

5A

7.5VA

10P

20

0.06Ω

Dual powered relays – KCEG 242 and KCEU 242 Relay and CT secondar y rating

Nominal output

Accuracy class

Accuracy limit factor

Limiting lead resistance (one way)

1A

7.5VA

10P

15

0.7Ω

5A

10VA

10P

20

0.06Ω

Core balance current transformer requirements for earth faults Core balance CTs of metering class accuracy are required and should have a knee-point voltage satisfying the following formulae. (The value of current used for Ifn should be the maximum possible earth fault current that may flow). In addition, it should be ensured that the phase error of the applied CT is less than 90' at 10% of rated current and less than 150' at 1% of rated current. For the IDMT characteristic of the first element, Io>: Vk > (Icn/2).(Rct + Rwp + Rwn + Rrp + Rrn) earth faults Vk > (Ifn/2).(Rct + Rwp + Rwn + Rrp + Rrn) earth faults wher where: e: Vk = Requ Requir ired ed CT knee knee-p -poi oint nt volt voltag agee Icn

= Maximum Maximum prospectiv prospectivee secondary secondary current current for earth earth faults faults or 31 times Io> setting (whichever is lower)

Ifn

= Maximu Maximum m prospecti prospective ve seconda secondary ry current current for earth earth faults faults

Rct = CT second secondary ary windin winding g resista resistance nce Rwp = Resistan Resistance ce of each each CT CT phas phasee lead lead Rwn = Resistan Resistance ce of each each CT neut neutral ral lead Rrp = Impedanc Impedancee of relay relay phase phase curre current nt input input Rrn = Impedan Impedance ce of rela relayy neutra neutrall curren currentt input input Where the K Range relays are being used for restricted earth fault protection the CTs must be sized to assure stability as described in Chapter 4, Section 5.10. The accuracy class of the CTs should be chosen to suit the required accuracy of measurement values.



Limits of error for accuracy classes 5P and 10P Accuracy class

Current error (%)

Composite error (%)

5P

±1

±5

10P

±3

±10

The accuracy limit factors detailed above should be used to ensure full range fault recording.

Section 14. HIGH VOLT VOLTAGE WITHSTAND WITHSTAND 14.1 14 .1

Diel Dielec ectr tric ic wit withs hsta tand nd IEC IEC 602 60255 55-5 -5:: 1977 1977 2.0kV rms for one minute between all terminals and case earth, except terminal 1. 2.0kV rms for one minute between terminals of independent circuits, including contact circuits. 1.5kV rms for 1 minute across open contacts of output relays 0 to 7. 1.0kV rms for 1 minute across open contacts of the watchdog relay.

14.2 14 .2

High High volt voltag age e imp impul ulse se IEC IEC 602 60255 55-5 -5:: 197 1977 7 5kV peak, 1.2/50µs, 0.5J between all terminals and all terminals to case earth.

14.3 14 .3

Insu Insula lati tion on resi resist stan ance ce IEC IEC 60 6025 2555-5: 5: 19 1977 77 >100MW when measured at 500Vdc

14.4 14 .4

High High fre frequ quen ency cy dis distu turb rban ance ce IEC IEC 602 60255 55-2 -222-1: 1: 198 1988 8 Class III 2.5kV peak between independent circuits and case. 1.0kV peak across terminals of the same circuit.

14.5 14 .5

Fast Fa st tra trans nsie ient nt IEC IEC 602 60255 55-2 -222-4: 4: 19 1992 92 Class IV 4kV, 4kV, 2.5kHz applied to all inputs and outputs.

14.6

EMC co compliance 89/336/EEC Compliance to the European Commission Directive on EMC is claimed via the Technical Construction File route. EN 50081-1 EN 50082-2 Generic Standards are used to establish conformity.

14.7 14 .7

Elec Electr tros osta tatic tic dis discha charg rge e test test IEC IEC 602 60255 55-2 -222-2: 2: 199 1996 6 Class Class 3 (8kV (8kV))

disc dischar harge ge in in air air wit withh cov cover er in in pla place ce

Class Class 2 (4kV) (4kV)

point point contact contact dischar discharge ge with with cove coverr remo removed ved



Section 15. IEEE/ANSI IEEE/ANSI SPECIFICA SPECIFICATIONS TIONS 15.1 15.1

Stan Standa dard rd for for rela relay y syst system emss assoc associa iate ted d with with elect electri rica call power power apparatus C37.90 - 1989

15.2

Surge urge with withsstand tand capa capab bilit ility y C37.90.1 - 1989

15.3 15.3

Radi Ra dio o ele elect ctro roma magn gnet etic ic int inter erfe fere renc nce e C39.90.2 - 1989

Section Section 16. ENVIRONME ENVIRONMENT NTAL AL 16.1

16.2

Tempe empera ratu ture re IEC IEC 60 60255-6 55-6:: 19 1988 Storage and transit

–25°C to +70°C

Operating

–25°C to +55°C

Hum Humidit idity y IEC IEC 6006 068 8-2-3 -2-3:: 19 1969 56 days at 93% relative humidity and 40°C

16.3 16 .3

Encl Enclos osur ure e pro prote tect ctio ion n IEC IEC 605 60529 29:1 :198 989 9 IP50 (Dust protected)

16.4 16 .4

Vibr Vibrat atio ion n IEC IEC 60 6025 2555-21 21-1 -1:1 :198 988 8 Class 1

16.5 16 .5

Shoc Shock k and and bump bump IEC IEC 602 60255 55-2 -21 12 2:1 :198 988 8 Class 1

16.6

Seism eismic ic IEC IEC 60 60255-2 55-21 1-3:1 -3:19 993 Class 1



Section Section 17. MODEL MODEL NUMBERS NUMBERS Relay type:

KCGG

122 142

1 1

2 4

0

1

0 X 0 X

1 X 2 Y

D

0

2 2

Configuration: Standard Customer Settings (standard only) Reduced input/output Customer settings (reduced I/O) Case size: Size 4 Midos flush mounting

D

Auxiliary voltage: 24/125V 48/250V

2 5

Not used CT rating: 1A CT standard (0.005 In to 0.8In for earth faults) 1A CT special (0.02 In to 3.2In for earth faults) 5A CT standard (0.005 In to 0.8In for earth faults) 5A CT special (0.02 In to 3.2In for earth faults)

C D E F

Language: English French German Spanish

E F G S

Relay type:

KCEG

112 142 152 242

1 1 1 2

Configuration: Standard Case size: Size 4 Midos flush mounting (KCEG112 only) Size 6 Midos flush mounting (KCEG142/152 only) Size 8 Midos flush mounting (KCEG242 only) Auxiliary voltage: 24/125V (except KCEG242) 48/250V (except KCEG242) 110/250V (KCEG242 only) Operating voltage: 110V ac; 50-60Hz 440V ac; 50-60Hz CT rating: 1A CT st stan anda dard rd 1A CT sp special 5A CT st stan anda dard rd 5A CT sp special Language: English French German Spanish

(0.0 (0 .005 05In to 0.8In for for ea eart rthh fau faullts ts)) (0.02In to 3.2In for eart rthh faults) (0.0 (0 .005 05In to 0.8In for for ea eart rthh fau faullts ts)) (0.02In to 3.2In fo for earth fa faults)

1 4 5 4

0

1

0

1

2 2 2 2

D F H 2 5 9 1 4 (0.00 (0.0 05In to 0.6In for for ea eart rthh fau faultlts) s) (0..002In to 2.4In for (0 for ea eart rthh fau faultlts) s) (0.0 (0 .00 05In to 0.6In for for ea eart rthh fau faultlts) s) (0.02In to 2.4In for earth fa faults)

C D E F E F G S


Relay type:


KCEU

142 242

1 2

Configuration: Standard Case size: Size 6 Midos flush mounting (KCEU 142 only) Size 8 Midos flush mounting (KCEU 242 only) Auxiliary voltage: 24/125V (except KCEU242) 48/250V (except KCEU242) 110/250V (KCEU242 only) Operating voltage: 110V ac; 50-60Hz 440V ac; 50-60Hz CT rating: 1A CT standard 1A CT special 5A CT standard 5A CT special Language: English French German Spanish

(0.005In to 0.8In for earth faults) (0.02In to 3.2In for earth faults) (0.005In to 0.8In for earth faults) (0.02In to 3.2In for earth faults)

4 4

0

1

0

1

2 2

F H 2 5 9 1 4 (0.005In to 0.6In for earth faults) (0.002In to 2.4In for earth faults) (0.005In to 0.6In for earth faults) (0.02In to 2.4In for earth faults)

C D E F E F G S



Section 18. FREQUENCY RESPONSE The operating criteria for each element have been chosen to suit the applications for which it is most likely to be used. Knowing how these elements respond under operating conditions will help to apply them effectively.

1

Fourier filter response Anti-aliasing filter response

0

1

2

3

4 5 Harmonic

6

7

8

Figure 1: Response of Fourier filtering

Measurement is based on the Fourier derived value of the fundamental component of current and Figure 1 shows the frequency response that results from this filtering. The '1' on the horizontal scale relates to the selected rated frequency of the relay and the figures '2', '3', '4' etc. are the second, third and fourth harmonic frequencies respectively. It can be seen that harmonics up to and including the 6th are suppressed, giving no output. The 7th is the first predominant harmonic and this is attenuated to approximately 30% by the anti-aliasing filter. For power frequencies that are not equal to the selected rated frequency. ie. the frequency does not coincide with '1' on the horizontal scale, the harmonics will not be of zero amplitude. For small frequency deviations of ±1Hz, this is not a problem but to allow for larger deviations, an improvement is obtained by the addition of frequency tracking. With frequency tracking the sampling rate of the analogue/digital conversion is automatically adjusted to match the applied signal. In the absence of a signal of suitable amplitude to track, the sample rate defaults to that to suit the selected rated frequency (Fn) for the relay. In presence of a signal within the tracking range (45 to 65Hz), the relay will lock on to the signal and the '1' on the horizontal axis in diagram above will coincide with the measured frequency of the measured signal. The resulting output for 2nd, 3rd, 4th, 5th and 6th harmonics will be zero. Thus this diagram applies when the relay is not frequency tracking the signal and also if it is tracking a frequency within the range 45 to 65Hz. Power frequency signals are predominant in phase quantities and are therefore used in the frequency tracking routine, whereas, earth fault quantities often contain a high proportion of harmonic signals. The earth fault element of multi-pole relays will generally be locked to the power frequency as the relay tracks it using the phase quantities. If the relay were to track a frequency above 65Hz then it would try to lock on to a sub-harmonic frequency and the response would then be as shown in diagram below. The horizontal axis of this graph is in Hz, the unit of



frequency, and a substantial output is produced for the 2nd harmonic of the system frequency and also for the 3rd, etc. Hence it is for this reason the relays are restricted to tracking the phase quantities and do not track earth fault signals.

1

0

100

200 Frequency - Hz

300

400

Figure 2: Response when frequency tracking

18.1

Transient overreach The I>>/Io>> and I>>>/Io>>> elements are often required for instantaneous high set and/or low set functions and for these applications they need to be unaffected by offset waveforms, which may contain a large dc exponential component, and by transformer inrush currents. To achieve this, two criteria for operation are applied independently. The first is that the Fourier derived power frequency component of the fault current is above the set threshold, as for I>/Io>. The second is that the peak of any half cycle of current exceeds twice the set threshold value and is provided to reduce the operation time to less than that which could be obtained with the Fourier measurement alone.

18.2

Peak measurement Another point to be aware of is that the second criterion uses peak values and these are only filtered by the anti-aliasing filter. However, the peak measurements are still based on sampled values and the position of the samples relative to the peak of the harmonic will depend on the phase relationship. The frequency response will therefore be modified for the I>>/Io>> and I>>>/Io>>> elements for which the diagram below is typical only. For certain applications it may be necessary to set the I>> or Io>> element to a low setting, possibly lower than that for the I> or Io> elements. In these situations the modified frequency response shown may not be acceptable because of the lack of harmonic rejection. To overcome this problem a software link is provided to select or deselect the peak detection feature for the I>> and Io>> overcurrent elements. The peak measurement is not used for the I>>/Io>> and I>>>/Io>>> elements of directional overcurrent relays. This is to ensure that the overcurrent and directional measurement is made from the same data to ensure decisive operation. Therefore, the following diagram will apply to KCEG/KCEU relays and a KCGG relay that has been set so as not to respond to peak values.



Filter response for I >>/I >>> with peak measurement tracking a single frequency

1

0

Figure 3:

18.3

50

100

200 Frequency Hz

300

400

Frequency response when relay responds to both peak and Fourier values

Frequency response of directional elements The phase directional elements are provided with synchronous polarization which is maintained for 320ms, or 3.2s, after the voltage collapses so that decisive operation is ensured. During the period of synchronous polarization the relay tracks the frequency on a current signal so that the phase correction is maintained, even with some deviation in frequency.


Chapter 8 Commissioning

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242 1. 2. 3. 3.1 3.2 3.3 4. 4.1 4.1.1 4.1.2 4.1.3 4.1.4 4.1.5 4.2 4.2.1 4.2.2 4.2.3 4.2.4 4.2.5 4.2.6 4.2.7 4.2.8 4.2.9 4.2.10 4.2.11 5. 5.1 5.2 5.3 5.3.1 5.3.1.1 5.3.1.2 5.3.1.3 5.3.2 5.3.2.1 5.3.2.2 5.3.2.3 5.3.3 5.3.3.1 5.3.3.2 5.3.3.3


INTRODUCTION PRODUCT SETTING FAMILIARISATION EQUIPMENT REQUIRED FOR TESTING Minimum equipment required for KCGG relays Additional equipment required for KCEG and KCEU relays Optional equipment PRODUCT VERIFICATION TESTS With the relay de-energised Visual inspection Insulation External wiring Watchdog contacts Auxiliary supply With the relay energised Watchdog contacts Light emitting diodes (LEDs) Liquid crystal display (LCD) Field supply Capacitor trip voltage (KCEG 242 and KCEU 242 relays only) Input opto-isolators Output relays Communications ports Current inputs Voltage inputs (KCEG and KCEU relays only) Energisation from line current transformers (KCEG 242 and KCEU 242 only) SETTING TESTS Apply customer settings Ckeck settings Demonstrate correct relay operation Non-directional phase fault test (KCGG 122/142 relays) Connect the test circuit Perform the test Check the operating time Directional phase fault test (KCEG 142/242 and KCEU 142/242 relays) Connect the test circuit Perform boundary of operation test Perform the timing test Directional earth fault function test (KCEG 112/152 relays) Connect the test circuit Perform boundary of operation test Perform the timing test

1 1 3 3 3 3 3 4 4 5 5 5 6 6 6 6 7 7 7 7 8 9 9 10 10 11 11 11 11 11 11 12 12 12 12 13 14 14 14 14 15

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242 6. 6.1 6.1.1 6.1.2 6.2 7. 8. 8.1 8.2 8.2.1 8.2.2 8.2.3 8.2.4 8.3 8.3.1 8.3.2 8.3.3 8.3.4 8.3.5 8.3.6 8.3.7 8.3.8 8.3.9 8.4 8.4.1 8.4.2 8.5 8.6 8.6.1 8.6.2 8.6.3 8.7 8.8 8.8.1 8.8.2

ON-LOAD CHECKS Check current and voltage transformer connections (KCEG and KCEU relays) Voltage connections Current connections Check current transformer connections (KCGG relays) FINAL CHECKS PROBLEM SOLVING Password lost or not accepted Protection settings Settings for high sets not displayed Second setting group not displayed Function links can not be changed Curve selection can not be changed Alarms Watchdog alarm Cell [0022 Alarms] link 0 = ‘1’ Cell [0022 Alarms] link 1 = ‘1’ Cell [0022 Alarms] link 2 = ‘1’ Cell [0022 Alarms] link 3 = ‘1’ Cell [0022 Alarms] link 4 = ‘1’ Cell [0022 Alarms] link 5 = ‘1’ Cell [0022 Alarms] link 7 = ‘1’ Fault flags will not reset Records Problems with event records Problems with disturbance records Circuit breaker maintenance records Communications Measured values do not change Relay no longer responding No response to remote control commands Output relays remain picked up Thermal state Thermal state reset to zero Thermal ammeter time constants


15 15 15 16 16 17 18 18 18 18 18 18 18 19 19 19 19 20 20 20 20 20 20 20 20 21 22 22 22 22 22 23 23 23 23



9. 9.1 9.2 921 9.2.1.1 9.2.1.2 9.2.1.3 9.2.1.4 9.2.2 9.2.2.1 9.2.2.2 9.2.2.3 9.2.2.4 9.2.2.5 9.3 9.3.1 9.3.1.1 9.3.1.2 9.3.1.3 9.3.2 9.3.3 9.3.4 9.4

MAINTENANCE Remote testing Maintenance checks Remote testing Alarms Measurement accuracy Trip test Circuit breaker maintenance Local testing Alarms Measurement accuracy Trip test Circuit breaker maintenance Additional tests Method of repair Replacing a PCB Replacement of user interface Replacement of main processor board Replacement of auxiliary expansion board Replacing output relays Replacing the power supply board Replacing the back plane (size 4 and 6 cases) Recalibration

23 23 24 24 24 24 24 25 25 25 25 25 25 25 26 26 26 26 26 27 27 27 27

Figure 1: Figure 2:

Connections for directional phase fault tests Connections for directional earth fault tests

13 14



Section 1. INTRODUCTION The KCEG, KCGG and KCEU relays are fully numerical in their design, implementing all protection and non-protection functions in software. The relays employ a high degree of self-checking and, in the unlikely event of a failure, will give an alarm. As a result of this, the commissioning tests do not need to be as thorough as with non-numeric electronic or electro-mechanical relays. To commission numeric relays it is only necessary to verify that the hardware is functioning correctly and the application-specific software settings have been applied to the relay. It is considered unnecessary to test every function of the relay if the settings have been verified by one of the following methods: • Extracting the settings applied to the relay using appropriate setting software (Preferred method) • Via the operator interface. To confirm that the product is operating correctly once the customer’s settings have been applied, a test should be performed on a single element. Unless previously agreed to the contrary, the customer will be responsible for determining the application-specific settings to be applied and testing scheme logic applied by external customer wiring. Blank commissioning test and setting records are provided in Appendix 4 for completion as required. Before carrying out any work on the equipment, the user should be familiar with the contents of the ‘Safety Section’ and Chapter 2, ‘Handling and Installation’ of this manual.

Section 2. PRODUCT SETTING FAMILIARISATION When commissioning a KCEG, KCGG or KCEU relay for the first time, sufficient time should be allowed to become familiar with the method by which settings are applied. Chapter 3, Section 3 contains a detailed description of the menu structure of the KCEG, KCGG and KCEU relays but the key functions are summarised in Table 1. With the cover in place only the [F] and [0] keys are accessible. Data can only be read or flag and counter functions reset. No protection or configuration settings can be changed. Removing the cover allows access to the [+] and [–] keys so that all settings can be changed and there is greater mobility around the menu. In Table 1, [F]long indicates that the key is pressed for at least 1 second and [F]short for less than 0.5 second. This allows the same key to perform more than one function. Alternatively, if a portable PC is available together with a K-Bus interface and suitable setting software, the menu can be viewed a page at a time to display a full column of data and text. Settings are also more easily entered and the final settings can be saved to a file on a disk for future reference or printing a permanent record. Refer to the software user manual for details and allow sufficient time to become familiar with its operation if it is being used for the first time.



Current Display

Key Press

Default display

[F]short or Display changes to menu column heading [F] long “SYSTEM DATA”.

Flag faults after a trip

Effect of Action

[+] †

Backlight turns ON – no other effect.

[–] †


[0]short

Steps through the available default displays.

[0]long


[F]short or Display moves to menu column heading [F] long “SYSTEM DATA”. [+] †


[–] †


[0]short


[0]long

Resets trip LED and returns to default display.

[F] short

Move to next item in menu column.

[F] long

Move to next column heading.

[+] †

Move to previous column heading.

[–] †


[0]short


[0]long

Re-establishes password protection and returns to default display.

[F] short

Move to next item in menu column.

[F]+ [0]

Move to previous item in menu column.

[F] long


[0] short


[0] long

Resets the value if cell is resettable.

A settable cell †

[+] or [–]

Puts relay in the setting mode (flashing cursor on bottom line of display). The password must first be entered for protected cells.

Setting mode †

[F]

Changes to the confirmation display. If function links, relay or input masks are displayed, the [F] key will step through them from left to right and finally changing to the confirmation display.

[+]

Increments value – rapidly increases if held depressed.

[–]

Decrements value – rapidly decreases if held depressed.

[0]

Escapes from the setting mode without the setting being changed.

[+]

Confirms setting and enters the new value.

[–]

Returns prospective value of setting for checking and further modification.

[0]

Escapes from the setting mode without a setting change.

Column heading

Any menu cell

Confirmation mode †

† Only

available with front cover removed

Table 1: Functions of keys



Section 3. EQUIPMENT REQUIRED for COMMISSIONING 3.1

Minimum equipment required for KCGG relays Overcurrent test set with interval timer. Multimeter with suitable ac and dc voltage, and ac current, ranges. Audible continuity tester (if not included in multimeter).

3.2

Additional equipment required for KCEG and KCEU relays Phase-shifting transformer Variable transformer (Variac) and resistors (if overcurrent test can not change the phase angle between current and voltage). Phase angle meter. Phase rotation meter (not required for the KCEG 112).

3.3

Optional equipment Multi-finger test plug type MMLB01 (if test block type MMLG installed). A portable PC, with appropriate software and a KITZ 101 K-Bus/IEC60870-5 interface unit (if one is not already installed at site) will be useful and save considerable time. However, it is not essential to commissioning. A printer (for printing a setting record from the portable PC).

Section 4. PRODUCT CHECKS These product checks cover all aspects of the relay that need to be checked to ensure that it has not been physically damaged prior to commissioning, is functioning correctly and all measurements are within the stated tolerances. If the application-specific settings have been applied to the relay prior to commissioning, it is advisable to make a copy of the settings so as to allow their restoration later. This can be done by: • Obtaining a setting file on a diskette from the customer (this requires a portable PC with appropriate software for downloading the settings to the relay.) • Extracting the settings from the product itself (this again requires a portable PC with appropriate software.) • Manually creating a setting record. This could be done using a copy of the setting record located in Appendix 4. If the customer has changed the password preventing unauthorised changes to some of the settings, either the revised password should be provided or the customer should restore the original password prior to commencement of testing. Note: In the event that the password has been lost, a recovery password can be obtained from ALSTOM T&D Protection & Control Ltd by quoting the model and serial numbers of the particular relay. The recovery password is unique to that relay and will not work on any other relay.



With the relay de-energised The following group of tests should be carried out without the auxiliary supply or measured voltages being applied to the relay and the trip circuit isolated. If an MMLG test block is provided, this can easily be achieved by inserting test plug type MMLB01 which effectively open-circuits all wiring routed through the test block. Before inserting the test plug, reference should be made to the scheme diagram to ensure that this will not potentially cause damage or a safety hazard. For example, the test block may also be associated with protection current transformer circuits. It is essential that the sockets in the test plug, which correspond to the current transformer secondary windings, are linked before the test plug is inserted into the test block. DANGER: Never open circuit the secondary circuit of a current transformer since the high voltage produced may be lethal and could damage insulation. If an MMLG test block is not provided, the voltage transformer supply to the relay should be isolated by means of the panel links or connecting blocks. The line current transformers should be short-circuited and disconnected from the relay terminals. Where means of isolating the auxiliary supply and trip circuit (eg. isolation links, fuses, MCB etc.) are provided, these should be used. If this is not possible, the wiring to these circuits will have to be disconnected and the exposed ends suitably terminated to prevent them being a safety hazard.

4.1.1

Visual inspection Loosen the cover screws and remove the cover. The relay module can now be withdrawn from its case. In accordance with Chapter 2, Section 2 (Handling of Electronic Equipment), carefully examine the module and case to see that no damage has occurred since installation. Check that the serial and model numbers on the front plate and label on the left-hand, inside face of the case are identical. The only time that the serial numbers may not match is when a failed relay has been replaced to provide continuity of protection. The rating information on the front of the relay should also be checked to ensure it is correct for the particular installation. Visually check that the current transformer shorting switches, fitted on the terminal block inside the rear of the case, are wired into the correct circuit. The shorting switches are between terminals 21 and 22, 23 and 24, 25 and 26, and 27 and 28 for all versions of KCEG, KCGG and KCEU. Ensure that, while the relay module is withdrawn, the shorting switches are closed by checking with a continuity tester. Ensure that the case earthing connection, above the rear terminal block, is used to connect the relay to a local earth bar. Where there is more than one relay in a tier, it is recommended that a copper earth bar should be fitted connecting the earth terminals of each case in the same tier together. However, as long as an adequate earth connection is made between relays, the use of a copper earth bar is not essential.

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242 4.1.2


Insulation Insulation resistance tests only need to be done during commissioning if the customer requires them to be done and if they have not been performed during installation. If insulation resistance tests are required, isolate the relay trip contacts and re-insert the relay module. Isolate all wiring from the earth and test the insulation with an electronic or brushless insulation tester at a dc voltage not exceeding 500V and internal impedance greater than 100Mý. Terminals of the same circuits should be temporarily strapped together. The main groups of relay terminals are: a) Voltage transformer circuits b) Current transformer circuits c) Auxiliary voltage supply d) Field voltage output and opto-isolated control inputs e) Relay contacts f) Communication port g) Case earth On completion of the insulation resistance tests, ensure all external wiring is correctly reconnected to the unit.

4.1.3

External wiring Check that the external wiring is correct to the relevant relay diagram or scheme diagram. The relay diagram number appears on a label on the left-hand, inside face of the case and the corresponding connection diagram can be found in Appendix 3 of this manual. If a connection diagram from the service manual is used, the customer’s mask allocations for the input opto-isolators and output relays should be checked to see which functions have been configured in each mask. If an MMLG test block is provided, the connections should be checked against the scheme diagram. It is recommended that the supply connections are to the live side of the test block (coloured orange with the odd numbered terminals (1, 3, 5, 7 etc.)). The auxiliary supply is normally routed via terminals 13 (supply positive) and 15 (supply negative), with terminals 14 and 16 connected to the relays positive and negative auxiliary supply terminals respectively. However, check the wiring against the schematic diagram for the installation to ensure compliance with the customer’s normal practice.

4.1.4

Watchdog contacts If not already done to perform the insulation resistance tests, isolate the relay trip contacts and re-insert the relay module. Using a continuity tester, check the watchdog contacts are in the states given in Table 2 for a de-energised relay. Terminals 3 and 5 4 and 6

Contact state Relay de-energised Relay energised Closed Open Open Closed

Table 2: Watchdog contact status



Auxiliary supply The relay can be operated from either an ac or a dc auxiliary supply but the incoming voltage must be within the operating ranges specified in Table 3. Without energising the relay, measure the auxiliary supply to ensure it is within the operating range. Relay rating (V) 24/125 48/250

DC operating range (V) 19 – 150 33 – 300

AC operating range (V) 50 – 133 87 – 265

Maximum crest voltage (V) 190 380

Table 3: Operational range of auxiliary supply

It should be noted that the relay can withstand an ac ripple of up to 12% of the upper rated voltage on the dc auxiliary supply. However, in all cases the peak value of the auxiliary supply must not exceed the maximum crest voltage. Do not energise the relay using the battery charger with the battery disconnected as this can seriously damage the relays power supply circuitry. Energise the relay if the auxiliary supply is within the operating range. If an MMLG test block is provided, it may be necessary to link across the front of the test plug to restore the auxiliary supply to the relay. 4.2

With the relay energised The following group of tests verify that the relay hardware and software is functioning correctly and should be carried out with the auxiliary supply applied to the relay. The measured currents and voltages must not be applied to the relay for these checks.

4.2.1

Watchdog contacts Using a continuity tester, check the watchdog contacts are in the states given in Table 2 for an energised relay. Note: This test can not be performed with dual powered relays because their watchdog contacts work in a different way to those of an auxiliary powered relay (ie. they do not give an alarm when the supply fails and only pick-up when the relay is not healthy).

4.2.2

Light emitting diodes (LEDs) On power up the green LED should have illuminated and stayed on indicating the relay is healthy. The relay has non-volatile memory which remembers the state (on or off) of the yellow alarm and red trip LED indicators when the relay was last powered, and therefore these indicators may also be on. If either the alarm or trip, or both LEDs are on then these should be reset before proceeding with further testing. If the LEDs successfully reset (the LED goes out), there is no testing required for that LED because it is known to be operational. Testing the alarm LED The alarm LED can simply be tested by entering the password in the [0002 Password] cell as this will cause it to flash.



Testing the trip LED The trip LED can be tested by initiating a manual circuit breaker trip from the relay. However, if the customer settings do not allocate output relays 3 or 7 in the relay masks for circuit breaker tripping from the phase fault protection function (KCEG 142/152/242, KCGG 122/142 and KCEU 142, 242 relays) or earth fault protection function (KCEG 112 relay), the trip LED will operate during the setting checks performed later. Otherwise the trip LED will need testing. If testing the LED is necessary but neither output relay 3 or 7 has been assigned for manual circuit breaker tripping, with the password entered (use the [0002 Password] cell if not already in this mode), set relay mask [0B0D CB Trip] bit 7 to‘1’. Set the [0010 CB Control] to ‘Trip’ and confirm the operation by pressing [F] then [+]. Check the trip LED to ensure it comes on. Restoring password protection To restore password protection (stopping changes to password-protected cells), press and hold the [F] key for over 1 second then press and hold the [0] key for over 1 second. Password protection will also be restored automatically 15 minutes after the last key press. The alarm LED stops flashing to indicate that password protection has been restored. 4.2.3

Liquid crystal display (LCD) There are no in-built self test routines for the LCD. The display itself can be checked by moving around the relay menu looking for pixels (the dots on the display used to form the text) that are not working. There is an integral backlight in the display that allows settings to be read in all conditions of ambient lighting. It is switched on when any key on the frontplate is momentarily pressed and is designed to switch off 10 minutes after the last key press. Check that the backlight does switch off as it will impose an unnecessary burden on the station battery if it stays on.

4.2.4

Field voltage supply The relay generates a field voltage of nominally 48V that should be used to energise the opto-isolated inputs. Measure the field voltage across terminals 7 and 8. Terminal 7 should be positive with respect to terminal 8 and the voltage should be within the range 45V to 60V when no load is connected.

4.2.5

Capacitor trip voltage (KCEG 242 and KCEU 242 relays only) The relay generates a capacitor trip voltage of nominally 50V. Measure the field voltage across terminals 9 and 10. Terminal 9 should be positive with respect to terminal 10 and the voltage should be within the range 45V to 55V when no load is connected.

4.2.6

Input opto-isolators This test is to check that all the opto-isolated inputs are functioning correctly. The KCEG 112, KCGG 122 and KCGG 142 02 have only 3 inputs (L0, L1 and L2) while the remaining KCEG 142/152/242, KCGG 142 01 and KCEU 142/ 242 have the full 8 opto-isolated inputs (L0, L1, L2, L3, L4, L5, L6 and L7). To allow the opto-isolated inputs to work, terminal 8 (field voltage supply negative) should be linked to terminal 52 for all models and additionally to 55 where the relay has 8 opto-isolated inputs.



The opto-inputs can then be individually energised by connecting terminal 7 (field voltage supply positive) to the appropriate opto-isolated input listed in Table 4. Note: The opto-isolated inputs may be energised from an external 50V battery in some installations. Check that this is not the case before connecting the field voltage otherwise damage to the relay may result. Opto-isolator

L0

L1

L2

L3

L4

L5

L6

L7

Terminal number

46

48

50

45

47

49

51

53

Table 4: Opto-isolator connections

The status of each opto-isolated input can be viewed using cell [0020 Log Status]. When each opto-isolated input is energised one of the characters on the bottom line of the display will change to indicate the new state of the inputs. The number printed on the frontplate under the display will identify which opto-isolated input each character represents. A ‘1’ indicates an energised state and a ‘0’ indicates a de-energised state.. 4.2.7

Output relays This test is to check that all the output relays are functioning correctly. With the password entered (use the [0002 Password]), set relay mask [0B0D CB Trip] bit 0 to ‘1’ and the rest (bits 1 to 7) to ‘0’. Connect an audible continuity tester across the terminals corresponding to output relay 0 given in Table 5. Select the [0010 CB Control] cell and press the [+] key until ‘Trip CB’ is displayed. Press the [F] once followed by the [+] key to confirm the change. Operation of output relay 0 will be confirmed by the continuity tester sounding for the duration of the trip pulse time in the [0906 tTRIP] cell. Repeat the test for output relays 1 to 3 inclusive for a KCEG 112, KCGG 142 02 or KCGG 122 relay and relays 1 to 7 inclusive for the remaining KCEG 142/ 152/242, KCGG 142 or KCEU 142/242 relays. Output relay

[CB Trip] Mask setting

Terminal numbers

0

0

0

0

0

0

0

0

1

30 and 32

1

0

0

0

0

0

0

1

0

34 and 36

2

0

0

0

0

0

1

0

0

38 and 40

3

0

0

0

0

1

0

0

0

42 and 44

4

0

0

0

1

0

0

0

0

29 and 31

5

0

0

1

0

0

0

0

0

33 and 35

6

0

1

0

0

0

0

0

0

37 and 39

7

1

0

0

0

0

0

0

0

41 and 43

Table 5: Settings for output tests

If an output relay is found to have failed, an alternative relay can be temporarily re-allocated until such time as the relay module can be repaired or a replacement can be installed.



To restore password protection (stopping changes to password-protected cells), press and hold the [F] key for over 1 second then press and hold the [0] key for over 1 second. Password protection will also be restored automatically 15 minutes after the last key press. The alarm LED stops flashing to indicate that password protection has been restored. 4.2.8

Communications ports This test should only be performed where the relay is to be accessed from a remote location and a portable PC has not been used to read and change settings during commissioning. It is not the intention of the test to verify the operation of the complete system from the relay to the remote location, just the relays K-bus circuitry and the protocol converter. Connect a portable PC running the appropriate software to the incoming (remote from relay) side of the protocol converter and ensure that the communications settings in the application software are set the same as those on the protocol converter. Check that communications with the relay can be established.

4.2.9

Current inputs This test verifies the accuracy of current measurement is within the acceptable tolerances. All relays will leave the factory set for operation at a system frequency of 50Hz. If operation at 60Hz is required then this must be set in cell [0009 Freq]. Press the [+] key until the frequency is 60Hz, then press the [F] key once followed by the [+] key to confirm the change. Apply rated current to each current transformer input in turn, checking its magnitude using a multimeter. Refer to Table 6 for the corresponding reading in the relays MEASURE 1 column and record the value displayed. All measured current values on the relay should equal the applied current multiplied by the current transformer ratio set in the [0502 CT Ratio] cell for earth fault current transformer inputs or [0602 CT Ratio] cell for phase current transformer inputs, as applicable. The acceptable tolerance is ±5%. Current applied to

Menu cell

Terminals 21 and 22

[0201 Ia]

Terminals 23 and 24

[0202 Ib]

Terminals 25 and 26

[0203 Ic]

Terminals 27 and 28

[0204 Io]

KCGG 122/142 (KCEG 142/152/242, ) and KCEU 142/242 KCGG 122/142 (KCEG 142/152/242, ) and KCEU 142/242 KCGG 122/142 (KCEG 142/152/242, ) and KCEU 142/242 112/142/152/242, (KCGGKCEG 122/142 and KCEU 142/242)

Table 6: Current inputs and corresponding displayed values



4.2.10 Voltage inputs (KCEG and KCEU relays only) This test verifies the accuracy of voltage measurement is within the acceptable tolerances for relays with directional protection functions. Apply rated voltage to each voltage transformer input in turn, checking its magnitude using a multimeter. Refer to Table 7 for the corresponding reading in the relays MEASURE 1 column and record the value displayed. All measured voltage values on the relay should equal the applied voltage multiplied by the voltage transformer ratio set in the [0503 VT Ratio] cell for earth fault voltage transformer inputs or [0603 VT Ratio] cell for phase voltage transformer inputs, as applicable. The acceptable tolerance is ±5%. Voltage applied to

Menu cell

Terminals 17 and 20

[0208 Va]

(KCEG 142/242 and KCEU 142/242)

Terminals 18 and 20

[0209 Vb]

(KCEG 142/242 and KCEU 142/242)

Terminals 19 and 20

[020A Vb] [020B Vo]

(KCEG 142/242 and KCEU 142/242) (KCEG 112/152)

Table 7: Voltage inputs and corresponding displayed values

4.2.11 Energisation from line current transformers (KCEG 242 and KCEU 242 only) This test ensures that the KCEG 242 or KCEU 242 relays will operate from the line current transformers should the auxiliary voltage be unavailable or has failed. The currents used in the tests are the minimum values for which the relay should operate, regardless of setting. Remove the auxiliary supply from the relay. Inject the current stated in Table8 to the relay terminals specified. In each case the relay should power up correctly with the LCD showing the default display and the green healthy LED illuminated. Repeat the field supply and capacitor trip voltage tests (4.2.4 and 4.2.5 respectively) with the relay powered from the injected current. Injected current 0.4 x In

0.2 x In

Terminals Inject into Link together 21 and 23 22 and 24 25 and 21 26 and 22 23 and 25 24 and 26 23 and 28 24 and 27

Table 8: Injected currents for line current transformer energisation tests

Note:

For 0.2 x In, the relay may chatter due to the loading effect of the energised output relays. This is unlikely to occur when the relay is in service because it will not be powered from the earth fault current only.



Section 5. SETTING TESTS The setting checks ensure that all the predetermined settings for the particular installation (customer’s settings) have been correctly applied to the relay and that the relay is operating correctly at those settings. If the customer settings are not available, ignore sections 5.1 and 5.2 and perform the tests in section 5.3 at the factory default settings. 5.1

Apply customer settings There are two methods of applying the settings: • Downloading them to the relay using a portable PC running the appropriate software via a KITZ protocol converter. If a KITZ is not installed as part of the customer’s scheme, one will have to be temporarily connected to the K-Bus terminals of the relay. This method is preferred as it is much faster and there is less margin for error.

5.2

If a setting file has been created by the customer and provided on a diskette, this will further reduce the commissioning time. • Enter them manually via the relays operator interface. Check settings

The settings applied should be carefully checked against the customer’s desired settings to ensure they have been entered correctly. However, this is not considered essential if a customer-prepared setting file has been downloaded to the relay using a portable PC. There are two methods of checking the settings: • Extract the settings from the relay using a portable PC running the appropriate software via a KITZ protocol converter and compare with the customer’s original setting record. (For cases where the customer has only provided a printed copy of the required settings but a portable PC is available). • Step through the settings using the relays operator interface and compare them with the customer’s original setting record. 5.3 Demonstrate correct relay operation This test, performed on a single element, demonstrates that the relay is functioning correctly at the customers chosen settings.The test performed will depend on the protection functions provided by the relay under test. The test is usually on stage 1 of the phase fault function, except KCEG 112 and KCEG 152 where stage 1 of the directional earth fault function is tested. 5.3.1 Non-directional phase fault test (KCGG 122/142 relays) This test demonstrates that stage 1 of the KCGG phase fault function [t>] operates within the stated tolerance at the customer settings. 5.3.1.1 Connect the test circuit Determine which output relay has been selected to operate when a t> trip occurs. If the trip outputs are phase-segregated (ie. a different output relay allocated for each phase), the relay assigned in cell [0B08 tA>] should be used. The associated terminal numbers can be found either from the external connection diagram (Appendix 3) or Table 5 above. Connect the output relay so that its operation will trip the test set and stop the timer.



Connect the current output of the test set to terminals 21 and 22 (‘A’ phase current transformer input) of the relay and ensure that the timer will start when the current is applied to the relay. 5.3.1.2 Perform the test Ensure that the timer is reset. Apply a current of twice the setting in cell [ 0605 I>] to the KCGG and note the time displayed when the timer stops. 5.3.1.3 Check the operating time Check that the operating time recorded by the timer is within the range shown in Table 9. Curve

Operating time at 2Is and TMS=1 Nominal Range

DT SI30xDT VI30xDT EI10xDT LTI30xDT MI VI EI STI30xDT RECT

[t>/DT] setting 10.03 13.50 26.67 120.0 7.61 14.06 19.04 1.78 966

na 9.53 – 10.53 12.83 – 14.18 25.33 – 28.00 114.00 – 126.00 7.23 – 7.99 13.35 – 14.76 18.09 – 20.00 1.69 – 1.87 917 – 1014

Table 9: Characteristic operating times for I >

Note: The operating given in Table 9 are for a TMS of 1. Therefore, to obtain the operating time for other TMS settings, the time given in Table 9 must be multiplied by the relays actual TMS setting. This setting can be found in cell [0606 t>/TMS]). In addition, there is an additional tolerance of up to 0.04 second that should be taken into account. 5.3.2

Directional phase fault test (KCEG 142/242 and KCEU 142/242 relays) This test demonstrates that stage 1of the KCEG or KCEU phase fault function [t>] operates within the stated tolerance at the customer settings. If cell [0601 PF Links] has been set to ‘0’, stage 1 [t>] function has been set for non-directional operation and hence should be tested as per a KCGG 142 (ie. use test 5.3.1). If a KCEG 242 or KCEU 242 relay is being tested, it is recommended that the relay is energised from an auxiliary voltage supply as this will reduce the burden imposed by the relay on the current injection test set.

5.3.2.1 Connect the test circuit Determine which output relay has been selected to operate when a t> trip occurs. If the trip outputs are phase-segregated (ie. a different output relay allocated for each phase), the relay assigned in cell [0B08 tA>] should be used. The associated terminal numbers can be found either from the external connection diagram (Appendix 3) or Table 5 above.



Connect the output relay so that its operation will trip the test set and stop the timer. Connect the test equipment as shown in Figure 1. Care should be taken to ensure that the correct polarities are connected to the phase angle meter. Adjust the phase shifter so that the phase angle meter reads 0°.

A

A B C N

18 VBC

B C

19

N Phase angle meter

Relay

R 21 IA

22

Figure 1: Connections for directional phase fault tests

5.3.2.2 Perform boundary of operation test Determine the relay characteristic angle (RCA) setting that has been applied to the relay by referring to cell [060D Char Angle]. Apply rated volts and a current above the [060D I>] setting to the relay. Monitor the forward start output contact, assigned in the relay mask [0B06 I> Fwd], and the reverse start contact, assigned in the relay mask [0B07 I> Rev], to indicate when the relay is in the operate region. The contact status can be determined either by physically monitoring the output relay contacts themselves using a continuity tester or observing cell [0021 Rly Status]. Note:

If the customer settings have no output relays assigned in relay masks [0B06 I> Fwd] or [0B07 I> Rev] then an output relay should temporarily be assigned in relay mask [0B06 I> Fwd]. This will allow the boundary test to be performed.

Taking positive phase angles as the current leading the voltage and negative phase angles as the current lagging the voltage, adjust the phase shifting transformer so the phase angle meter reads 180°+RCA. Check that the reverse start contacts have closed and the forward start contacts are open. Rotate the phase shifting transformer so the phase lag is decreasing or the phase lead is increasing on the phase angle meter and continue until the forward start contacts close and the reverse contacts open. Note the angle on the phase angle meter and check it is within the 5% of either RCA–90° or RCA+90°. Rotate the phase shifting transformer in the opposite direction to check the other operating boundary. If an output relay has been temporarily assigned in the relay mask [0B06 I> Fwd] to allow the boundary test to be performed, return the mask to the customer’s setting.



5.3.2.3 Perform the timing test Ensure that the timer is reset. Apply a current of twice the setting in cell [0605 I>] to the relay and note the time displayed when the timer stops. Check that the operating time recorded by the timer is within the range shown in Table 9. 5.3.3

Directional earth fault function test (KCEG 112/152 relays) This test demonstrates that stage 1 of the KCEG earth fault function (to>) operates within the stated tolerance at the customer settings.

5.3.3.1 Connect the test circuit Determine which output relay has been selected to operate when a to> trip occurs. The associated terminal numbers can be found either from the external connection diagram (Appendix 3) or Table 5 above. Connect the output relay so that its operation will trip the test set and stop the timer. Connect the test equipment as shown in Figure 2. Care should be taken to ensure that the correct polarities are connected to the phase angle meter. Adjust the phase shifter so that the phase angle meter reads 0°. V A

A B C N

19 Vo

B C

20

N Phase angle meter

Current injection test set

A

Relay

27 Io

28

Figure 2: Connections for directional earth fault tests

5.3.3.2 Perform boundary of operation test Determine the relay characteristic angle (RCA) setting that has been applied to the relay by referring to cell [050D Char Angle]. Apply a current above the [ 0505 Io>] setting and a polarising voltage above the threshold voltage [050F Vop>] setting to the relay. Monitor the forward start output contact, assigned in the [0B01 Io> Fwd] relay mask, and the reverse start contact, assigned in the [0B02 Io> Rev] relay mask, to indicate when the relay is in the operate region. The contact status can be determined either by physically monitoring the output relay contacts themselves using a continuity tester or observing cell [0021 Rly Status].

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242 Note:


If the customer settings have no output relays assigned in relay masks [0B01 Io> Fwd] or [0B02 Io> Rev] then an output relay should temporarily be assigned in relay mask [0B01 Io> Fwd]. This will allow the boundary test to be performed.

Taking positive phase angles as the current leading the voltage and negative phase angles as the current lagging the voltage, adjust the phase shifting transformer so the phase angle meter reads 180°+RCA. Check that the reverse start contacts have closed and the forward start contacts are open. The correct polarity of connection for operation with forward current flow is current flowing in through terminal 27 and out of terminal 28. Rotate the phase shifting transformer so the phase lag is decreasing or the phase lead is increasing on the phase angle meter and continue until the forward start contacts close and the reverse contacts open. Note the angle on the phase angle meter and check it is within the 5% of either RCA–90° or RCA+90°. Rotate the phase shifting transformer in the opposite direction to check the other operating boundary. If an output relay has been temporarily assigned in the relay mask [0B01 Io> Fwd] to allow the boundary test to be performed, return the mask to the customer’s setting. 5.3.3.3 Perform the timing test Ensure that the timer is reset. Depending on the rating of the phase meter being used, it may be necessary to short-circuit it with a wire link or remove it entirely to prevent thermal damage due to the currents used for the timing test. Apply a current of twice the setting in cell [0505 Io>] to the KCEG and note the time displayed when the timer stops. Check that the operating time recorded by the timer is within the range shown in Table 9.

Section 6. ON-LOAD CHECKS Remove all test leads, temporary shorting leads, etc. and replace any external wiring that has been removed to allow testing. If it has been necessary to disconnect any of the external wiring from the relay in order to perform any of the above tests, it should be ensured that all connections are replaced in accordance with the relevant external connection or scheme diagram. The following on-load measuring checks ensure that the external (customer) wiring to the current and voltage inputs is correct but can only be carried out if there are no restrictions preventing the energisation of the plant being protected. 6.1

Check current and voltage transformer connections (KCEG and KCEU relays) These tests alone are not conclusive that the phase connections to the relay are correct. A phase angle measurement is required for conclusive testing.



Voltage connections Measure the voltage transformer secondary voltages to ensure they are correctly rated and check that the system phase rotation is correct using a phase rotation meter. If a KCEG 112 or KCEG 152 is being tested, it will not be possible to check the phase rotation as the directional earth fault protection functions are polarised from an open-delta voltage transformer winding. Compare the values of the secondary phase voltages with the relays measured values, which can be found in the MEASURE 1 menu column. If the voltage transformer ratios (cells [0503 VT Ratio] and [0603 VT Ratio] for residual and phase voltages respectively) are set to 1:1, the displayed values are in secondary volts. The relay values should be within 5% of the applied secondary voltages. Otherwise, if the voltage transformer ratios (cells [0503 VT Ratio] and [0603 VT Ratio] for residual and phase voltages respectively) are set greater than 1:1, the displayed values are in primary volts. In this case the relay values will be equal to the applied secondary voltages multiplied by the appropriate voltage transformer ratio setting. Again the relay values should be within 5%. It should be noted that directional earth fault relays are not energised under normal load conditions and it is therefore necessary to simulate a phase to neutral fault to check the voltage transformer wiring.

6.1.2

Current connections Measure the current transformer secondary values, and check that their polarities are correct by measuring the phase angle between the current and voltage. Ensure the current flowing in the neutral circuit of the current transformers is negligible. Compare the values of the secondary phase currents with the relays measured values, which can be found in the MEASURE 1 menu column. If the current transformer ratios (cells [0502 CT Ratio] and [0602 CT Ratio] for earth and phase currents respectively) are set to 1:1, the displayed values are in secondary amperes. The relay values should be within 5% of the applied secondary currents. Otherwise, if the current transformer ratios (cells [0502 CT Ratio] and [0602 CT Ratio] for earth and phase currents respectively) are set greater than 1:1, the displayed values are in primary amperes. In this case the relay values will be equal to the applied secondary currents multiplied by the appropriate current transformer ratio setting. Again the relay values should be within 5%. It should be noted that directional earth fault relays are not energised under normal load conditions and it is therefore necessary to simulate a phase to neutral fault.

6.2

Check current transformer connections (KCGG relays) Measure the current transformer secondary values. Ensure the current flowing in the neutral circuit of the current transformers is negligible. Compare the values of the secondary phase currents with the relays measured values, which can be found in the MEASURE 1 menu column.



If the current transformer ratios (cells [0502 CT Ratio] and [0602 CT Ratio] for earth and phase currents respectively) are set to 1:1, the displayed values are in secondary amperes. The relay values should be within 5% of the applied secondary currents. Otherwise, if the current transformer ratios (cells [0502 CT Ratio] and [0602 CT Ratio] for earth and phase currents respectively) are set greater than 1:1, the displayed values are in primary amperes. In this case the relay values will be equal to the applied secondary currents multiplied by the appropriate current transformer ratio setting. Again the relay values should be within 5%. It should be noted that earth fault relays are not energised under normal load conditions and it is therefore necessary to simulate a phase to neutral fault. It is therefore necessary to temporarily disconnect one or two of the line current transformer connections to the relay and short the terminals of these current transformer secondary windings.

Section 7. FINAL CHECKS The tests are now complete. Remove all test or temporary shorting leads, etc. If it has been necessary to disconnect any of the external wiring from the relay in order to perform the wiring verification tests, it should be ensured that all connections are replaced in accordance with the relevant external connection or scheme diagram. If the circuit breaker operations counter should be zero, reset it using cell [0310 Sum (ops)]. This will require the password to be entered in cell [0002 Password] beforehand. However, if a replacement relay has been fitted, the circuit breaker maintenance counter cell [0310 CB (ops)] and current squared counters (displayed in cells [0311 CBdutyA], [0312 CBdutyB] and [0313 CBdutyC]) may need to be incremented to the values on the old relay. The counter for the number of circuit breaker can be incremented manually by operating the relay the required number of times. In a similar way, the current squared counters can be incremented by applying a number of secondary injection current pulses to the current inputs of the relay, but note that the counter will increment rapidly for large current values. If a MMLG test block is installed, remove the MMLB01 test plug and replace the MMLG cover so that the protection is restored to service. Ensure that all event records, fault records, disturbance records, alarms and LEDs have been reset before leaving the relay. Replace the cover on the relay.



Section 8. PROBLEM SOLVING Before carrying out any work on the equipment, the user should be familiar with the ‘Safety Section’ and Chapter 2 ‘Handling and Installation’, of this manual. 8.1

Password lost or not accepted Relays are supplied with the password set to AAAA. Only uppercase letters are accepted. Password can be changed by the user, see Chapter 3, Section 3. There is an additional unique recovery password associated with the relay which can be supplied by the factory, or service agent, if given details of its serial number. The serial number will be found in cell [0008 Serial No.] and should correspond to the number on the label at the top right hand corner of the frontplate of the relay. If they differ, quote the one in cell [0008 Serial No.].

8.2

Protection settings

8.2.1

Settings for high sets not displayed For Group 1 settings: Set cell [0601 PF Links] link 1 to ‘1’ to turn on I>> settings. Set cell [0601 PF Links] link 2 to ‘1’ to turn on I>>> settings. Set cell [0501 EF Links] link 1 to ‘1’ to turn on Io>> settings. Set cell [0501 EF Links] link 2 to ‘1’ to turn on Io>>> settings. For Group 2 settings: Set cell [0801 PF Links] link 1 to ‘1’ to turn on I>> settings. Set cell [0801 PF Links] link 2 to ‘1’ to turn on I>>> settings. Set cell [0701 EF Links] link 1 to ‘1’ to turn on Io>> settings. Set cell [0701 EF Links] link 2 to ‘1’ to turn on Io>>> settings.

8.2.2

Second setting group not displayed Set cell [0003 SD Links] link 4 to ‘1’ to turn on the group 2 settings.

8.2.3

Function links can not be changed Enter the password in cell [0002 Password] as these menu cells are protected. Links are not selectable if associated text is not displayed.

8.2.4

Curve selection can not be changed Enter the password in cell [0002 Password] as these menu cells are protected. Curves may not have been selectable in the particular relay.



Alarms If the watchdog relay operates, first check that the relay is energised from the auxiliary supply. If it is, then try to determine the cause of the problem by examining the alarm flags in cell [0022 Alarms]. This will not be possible if the display is not responding to key presses. Having attempted to determine the cause of the alarm it may be possible to return the relay to an operable state by resetting it. To do this, remove the auxiliary power supply from the relay for approximately 10 seconds before re-establishing the supply. If the relay is powered from the CT circuit as well, remove this source of supply also, possibly by withdrawing the module from its case. The relay should return to an operating state. Recheck the alarm status in cell [0022 Alarms] if the alarm LED is still indicating an alarm state. The following notes will give further guidance:

8.3.1

Watchdog alarm Auxiliary powered relays: the watchdog relay will pick up when the relay is operational to indicate a healthy state, with its “normally open” contact closed. When an alarm condition that requires some action to be taken is detected, the watchdog relay resets and its “normally closed” contact will close to give an alarm. Note: The green LED will usually follow the operation of the watchdog relay. Dual powered relays: the watchdog relay operates in a slightly different way on this version of the relay, because it does not initiate an alarm for loss of the auxiliary power supply. This is because the auxiliary power supply may be taken from an insecure source or the relay may be powered solely from the current circuit. Operation of the watchdog is therefore inverted so that it will pick-up for a failed condition, closing its “make” contact to give an alarm and in the normal condition it will remain dropped-off with its “break” contact closed to indicate that it is in a healthy state. Note:

The green LED will usually operate in the opposite way to the watchdog relay (ie. the LED will be on when the watchdog relay is de-energised and vice versa).

There is no shorting contact across the case terminals connected to the “break” contact of the watchdog relay. Therefore, the indication for a failed/healthy relay will be cancelled when the relay is removed from its case. If the relay is still functioning, the actual problem causing the alarm can be found from the alarm records in cell [0022 Alarms] (see Chapter 3, Section 7.1). 8.3.2

Cell [0022 Alarms] link 0 = ‘1’ For an ‘Uncfg’ configuration alarm, the protection is stopped and no longer performing its intended function as there will be an error in the factory configuration settings. To return the relay to a servicable state, the initial factory configuration will have to be reloaded and the relay re-calibrated. It is recommended that the work be carried out at the factory, or entrusted to an approved service centre.

8.3.3

Cell [0022 Alarms] link 1 = ‘1’ For an ‘Uncalib’ calibration alarm, the protection will still be operational but there will be an error in its calibration that will require attention. It may be left running provided the error does not cause any problems with incorrect tripping.



To return the relay to a servicable state, the initial factory configuration will have to be reloaded and the relay re-calibrated. It is recommended that the work be carried out at the factory, or entrusted to an approved service centre. 8.3.4

Cell [0022 Alarms] link 2 = ‘1’ A ‘Setting’ alarm indicates that the area of non-volatile memory where the selected protection settings are stored has been corrupted. The current settings should be checked against those applied at the commissioning stage or any later changes that have been made. If a personal computer (PC) is used during commissioning then it is recommended that the final settings applied to the relay are copied to a floppy disk with the serial number of the relay used as the file name. The settings can then be readily loaded back into the relay if necessary, or to a replacement relay.

8.3.5

Cell [0022 Alarms] link 3 = ‘1’ The ‘No Service’ alarm flag can only be observed when the relay is in the calibration or configuration mode when the protection programme will be stopped.

8.3.6

Cell [0022 Alarms] link 4 = ‘1’ The ‘No Samples’ alarm flag indicates that there is no output from the analogue to digital converter, although the relay will remain in service. If this flag should be set to ‘1’, please contact the factory or an approved service centre for advice.

8.3.7

Cell [0022 Alarms] link 5 = ‘1’ The ‘No Fourier’ alarm flag indicates that the Fourier analysis algorithm is no longer running. If this flag should be set to ‘1’, please contact the factory or an approved service centre for advice.

8.3.8

Cell [0022 Alarms] link 7 = ‘1’ The ‘CB ops’ alarm flag indicates that, since the operations counter was last reset, the circuit breaker has operated the number of times that has been set in cell [0C07 CB Ops>]. The circuit breaker operations counter can be viewed and reset using cell [0310 Sum (ops)].

8.3.9

Fault flags will not reset These flags can only be reset when the flags Fn are being displayed or by resetting the fault records (cell [0110 Clear=0]). For more details refer to Chapter 3, Section 4.15.

8.4

Records

8.4.1

Problems with event records Fault records will only be generated if RLY3 is operated as this relay is the trigger to store the records. Fault records can be generated in response to another protection operating if one of its trip contacts is used to operate RLY3 via an opto-isolated input on the K relay. This will result in the fault values, as measured by the K relay, being stored at the instant RLY3 resets. The flag display (cell [0102 Fn G1]) will include a flag to identify the auxiliary input that initiated the record. Fault currents recorded are lower than actual values, as the fault is interrupted before measurement is completed.



Few fault records can be stored when changes in the state of logic inputs and relay outputs are stored in the event records. These inputs and outputs can generate many events for each fault occurrence and limit the total number of faults that can be stored. Setting cell [0003 SD Links] Link 7 to ‘0’ will turn off this feature and allow the maximum number of fault records to be stored. The event records are erased if the auxiliary supply to the relay is lost for a period exceeding the hold-up time of the internal power supply. Events can only be read via the serial communication port and not on the LCD. Any spare opto-isolated inputs may be used to log changes of state of external contacts in the event record buffer of the K relay. The opto-isolated input does not have to be assigned to a particular function in order to achieve this (ie. it does not have to be assigned in any of the input masks). The oldest event is overwritten by the next event to be stored when the buffer becomes full. When a master station has successfully read a record, it usually clears it automatically. When all records have been read, the event bit in the status byte within the master station programme is set to ‘0’ to indicate that there are no longer any records to be retrieved. 8.4.2

Problems with disturbance records Only one record can be held in the buffer and the recorder must be reset before another record can be stored. Automatic reset can be achieved by setting function link [0003 SD Links] link 6 to ‘1’. It will then reset the disturbance recorder 3 seconds after a current, greater than the undercurrent setting, has been restored to the protected circuit. The disturbance records are erased if the auxiliary supply to the relay is lost for a period exceeding the hold-up time of the internal power supply. Disturbance records can only be read via the serial communication port. It is not possible to display them on the LCD. No trigger has been selected in cells [0C04 Logic Trig] or [0F05 Relay Trig] to initiate the storing of a disturbance record. The disturbance recorder is automatically reset on restoration of current above the undercurrent setting for greater than 3 seconds. Change function link [0003 SD Links] link 6 to ‘0’ to select manual reset. Post trigger (cell [0C03 Post Trigger]) is set to maximum value. Thus the relay is missing the fault. When a master station has successfully read a record, it will clear the record automatically and the disturbance record bit in the status byte within the master station programme will then be set to ‘0’ to indicate that there is no longer a record to be retrieved.



Circuit breaker maintenance records When a replacement relay is fitted, it may be desirable to increment the circuit breaker maintenance counter (cell [0310 CB (ops)]) to the values of that on the old relay. The current squared counters (displayed in cells [0311 CBdutyA], [0312 CBdutyB] and [0313 CBdutyC], can be incremented by applying a number of secondary injection current pulses to the current inputs of the relay, but note that the counter will increment rapidly for large current values. The counter for the number of circuit breaker operations (displayed in cell [0310 Sum (ops)]) can be incremented manually by operating the relay the required number of times. The circuit breaker trip time for the last fault (cell [010B CB Trip Time]) cannot be cleared to zero. This is to enable the master station to interrogate the relay for this value as a supervisory function. The circuit breaker maintenance counters are not incremented when another protection trips the circuit breaker. Add a trip input from the protection to an auxiliary input of the K relay and arrange for relay RLY3 or RLY7 to operate instantaneously in response to the input.

8.6

Communications An address (cell [000B Rly Address]) cannot be automatically allocated if the remote change of setting has been inhibited by cell [0003 SD Links] link 0 being set to‘0’. This must be first set to ‘1’. Alternatively, the address must be entered manually via the user interface on the relay. An address (cell [000B Rly Address]) cannot be allocated automatically unless the address is first manually set to ‘0’. This can also be achieved by a global command including the serial number of the relay. Relay address set to 255, the global address for which no replies are permitted.

8.6.1

Measured values do not change Values in the MEASUREMENTS (1) and MEASUREMENTS (2) columns are snapshots of the values at the time they were requested. To obtain a value that varies with the measured quantity it should be added to the poll list as described in the user manual for the access software being used.

8.6.2

Relay no longer responding Check if other relays that are further along the bus are responding. If this is the case, the relays communication processor should be reset by removing the auxiliary supply from the relay for at least 10 seconds before re-energising it. This should not be necessary as the reset operation occurs automatically when the relay detects a loss of communication. If relays further along the bus are not communicating, check to find out which are responding to the master station. If some are responding, the position of the break in the bus can be determined by deduction. If none is responding then check for data on the bus or reset the communication port driving the bus with requests. Check there are not two relays with the same address (cell [000B Rly Address]) on the bus.

8.6.3

No response to remote control commands Check that cell [0003 SD Links] link 0 is not set to ‘0’ as this will inhibit the relay from responding to remote commands. If this is the case set cell [0003 SD Links] link 0 to‘1’; a password will be required.



System data function links settings can not be performed over the communication link if the remote change of settings has been inhibited by setting cell [0003 SD Links] link 0 to ‘0’. Change [0003 SD Links] link 0 to ‘1’ manually via the user interface on the relay first. Relay is not identified in the Circuit Breaker Control Menu of the Protection Access Software and Toolkit if two auxiliary circuit breaker contacts have not been connected to the opto-isolated inputs of the relay, to indicate its position via the plant status word (cell [000C Plnt Status]). Check input masks [0A0E CB Closed] and [0A0F CB Open] for correct opto-isolator allocations, and the connections to the auxiliary contacts of the circuit breaker. 8.7

Output relays remain picked up Relays remain picked-up when de-selected by link or mask. If an output relay is operated at the time it is de-selected, either due to a software link change or by de-selecting it in an output mask, it may remain operated until the K relay is powered down and up again. After such changes, it is advisable to remove the auxiliary supply from the relay for at least 10 seconds before reenergising it.

8.8

Thermal state

8.8.1

Thermal state reset to zero If the thermal ammeters (displayed in cells [0404 IthA], [0405 IthB] and [0406 IthC] are reset using an opto-isolated input allocated in cell [0A11 Reset Ith], this will also reset the thermal state of the thermal protection.

8.8.2

Thermal ammeter time constants The setting for the time constant (cell [0814 TC]) is shared between the thermal ammeter and the thermal protection. Priority would normally be given to the thermal protection.

8.9

Erratic operation at directional characteristic boundaries If commissioning testing is carried out using a digital secondary injection test set, there may be an apparent erratic operation at the boundaries of the directional characteristic. This will be particularly noticeable when observing the operation of the start relay contacts, which is the method described in the commissioning instructions in Section 5.3. This is caused by the transitional errors when changing direction or applying signals instantaneously due to the output quantities changing in steps rather than linearly. This does not happen with all designs of digital secondary injection test set. The problem is easily overcome by using the t>, t>>, t>>>, to>, to>> or to>>> outputs for indication of relay operation instead of I>. or Io>. These time delays should then be set to a minimum of 20ms. See also the notes in Chapter 4, Section 6.10 of this manual. The slight directional indecision of the start relays should not cause any problem as it will be covered by the short time delays that are applied in the blocking schemes.



Section 9. MAINTENANCE 9.1

Maintenance period It is recommended that products supplied by ALSTOM T&D Protection & Control Limited receive regular monitoring after installation. As with all products some deterioration with time is inevitable. In view of the critical nature of many of these products and in the case of protective relays, their infrequent operation, it is desirable to confirm that they are operating properly at regular intervals. The typical life of these products is about 20 years, although many are in satisfactory service considerably longer than this. Maintenance periods will depend on many factors, such as: • the operating environment • the accessibility of the site • the amount of available manpower • the importance of the installation in the power system • the consequences of failure If a preventative maintenance policy exists within the customer’s organisation then the recommended product checks should be included in the regular programme. It should be noted that K Range Midos relays are self-supervising and so require less maintenance than earlier designs of relay. Most problems will result in an alarm so that remedial action can be taken. However, some periodic tests could be done to ensure that the relay is functioning correctly. The following sections suggest checks that can be performed either remotely over the communications link using a PC running appropriate software or at site.

9.2

Maintenance checks Before carrying out any work on the equipment, the user should be familiar with the ‘Safety Section’ and Chapter 2 ‘Handling and Installation’, of this manual.

9.2.1

Remote testing If the relay can be communicated with from a remote point via its serial port, then some checks can be carried out without actually visiting the site.

9.2.1.1 Alarms The alarm status should first be checked to identify if any alarm conditions exist. The alarm records (cell [0022 Alarms]) can then be read to identify the nature of any alarm that may exist 9.2.1.2 Measurement accuracy The values measured by the relay can be compared with known system values to check that they are in the approximate range that is expected. If they are, then the analogue/digital conversion and calculations are being performed correctly. 9.2.1.3 Trip test If the relay is configured to provide remote control of the circuit breaker then a trip test can be performed remotely in several ways:



1. If the relay provides phase overcurrent protection, read the load current on each phase in the MEASURE 1 column. Reduce the stage 1 phase fault setting (cell [0605 I>]) to a known value that is less than the load current. The relay should trip in the appropriate time for the given multiple of setting current and time multiplier setting (cell [0606 t>/TMS]). The settings can then be returned to their usual value and the circuit breaker reclosed. Note:

If setting group 2 is not being used for any other purpose, it could be used for this test by having a lower setting pre-selected and issuing a command to change the setting group that is in use to initiate the tripping sequence.

2. If the relay is connected for remote control of the circuit breaker then a trip/ close cycle can be performed. This method will not check as much of the functional circuit of the relay as the previous method but it will not need the settings of the relay changed. If a failure to trip occurs, view cell [0021 Rly Status] whilst the test is repeated. This will check that the output relay is being commanded to operate. If the test trip is being performed using a trip/close cycle, the output relay assigned in cell [0B0D CB Trip] should operate and not the main trip relay used by the protection functions. If the assigned output relay is not responding then an output relay allocated to a less essential function may be re-allocated to the trip function to effect a temporary repair, but a visit to the site may be needed to effect a wiring change. See Chapter 3, Section 4.14 for how to set output relay masks. 9.2.1.4 Circuit breaker maintenance Maintenance records for the circuit breaker can be obtained at this time by reading cells [0310 Sum (ops)], [0311 CBdutyA], [0312 CBdutyB], and [0313 CBdutyC]. 9.2.2

Local testing When testing locally, similar checks to those for remote testing may be carried out to ensure the relay is functioning correctly.

9.2.2.1 Alarms The alarm status LED should first be checked to identify if any alarm conditions exist. The alarm records (cell [0022 Alarms]) can then be read to identify the nature of any alarm that may exist. 9.2.2.2 Measurement accuracy The values measured by the relay can be checked against known values injected into the relay via the test block, if fitted, or injected directly into the relay terminals. Suitable test methods will be found in Section 4.2.9 and 4.2.10 of this chapter which deals with commissioning. These tests will prove the calibration accuracy is being maintained. 9.2.2.3 Trip test If the relay is configured to provide a trip test via its user interface then this should be performed to test the output trip relays. If the relay is configured for remote control of the circuit breaker, the trip test will initiate the remote circuit breaker trip relay (assigned in cell [0B0D CB Trip]) and not the main trip relay used by the



protection functions. If the relay provides phase overcurrent protection, the main trip relay should be tested by reducing the stage 1 phase fault setting (cell [0605 I>]) to a known value that is less than the load current. The relay should trip in the appropriate time for the given multiple of setting current and time multiplier setting (cell [0606 t>/TMS]). The settings can then be returned to their usual value and the circuit breaker re-closed. Note:

If setting group 2 is not being used for any other purpose, it could be used for this test by having a lower setting pre-selected and issuing a command to change the setting group that is in use to initiate the tripping sequence.

If the assigned output relay is not responding then an output relay allocated to a less essential function may be re-allocated to the trip function to effect a temporary repair. See Chapter 3, Section 4.14 for details on how to set output relay masks. 9.2.2.4 Circuit breaker maintenance Maintenance records for the circuit breaker can be obtained at this time by reading cells [0310 Sum (ops)], [0311 CBdutyA], [0312 CBdutyB] and [0313 CBdutyC]. 9.2.2.5 Additional tests Additional tests can be selected from the Commissioning Instructions as required. 9.3

Method of repair Before carrying out any work on the equipment, the user should be familiar with the ‘Safety Section’ and Chapter 2 ‘Handling and Installation’, of this manual. This should ensure that no damage is caused by incorrect handling of the electronic components.

9.3.1

Replacing a PCB Re-calibration is not usually required when a PCB is replaced unless it happens to be one of the two boards that plugs directly on to the left hand terminal block as these directly affect the calibration.

9.3.1.1 Replacement of user interface Withdraw the module from its case. Remove the four screws that are placed one at each corner of the front plate. Remove the front plate. Lever the top edge of the user interface board forwards to unclip it from its mounting. Pull the PCB upwards to unplug it from the connector at its lower edge. Replace with a new interface board and re-assemble in the reverse order. 9.3.1.2 Replacement of main processor board This is the PCB at the extreme left of the module, when viewed from the front. To replace this board: First remove the screws holding the side screen in place. There are two screws through the top plate of the module and two more through the base plate. Remove screen to expose the PCB. Remove the two retaining screws, one at the top edge and the other directly below it on the lower edge of the PCB.



Separate the PCB from the sockets at the front edge of the board. Note that they are a tight fit and will require levering apart, taking care to ease the connectors apart gradually so as not to crack the front PCB card. The connectors are designed for ease of assembly in manufacture and not for continual disassembly of the unit. Re-assemble in the reverse of the above sequence, making sure that the screen plate is replaced with all four screws securing it. 9.3.1.3 Replacement of auxiliary expansion board This is the second board from the left hand side of the module. Remove the processor board as described in 9.3.1.2 above. Remove the two securing screws that hold the auxiliary expansion board in place. Unplug the PCB from the front bus as described for the processor board and withdraw. Replace in reverse order of the above sequence, making sure that the screen plate is replaced with all four screws securing it. 9.3.2

Replacing output relays The main processor and auxiliary expansion boards are removed and replaced as described in Section 9.3.1.2 and 9.3.1.3 above respectively. It should be noted when replacing output relays that the PCB’s have through plated holes. Care must therefore be taken not to damage these holes when a component is removed, otherwise solder may flow through the hole to make a good connection to the tracks on the component side of the PCB.

9.3.3

Replacing the power supply board Remove the two screws securing the right hand terminal block to the top plate of the module. Remove the two screws securing the right hand terminal block to the bottom plate of the module. Unplug the back plane from the power supply board. Remove the securing screws at the top and bottom of the power supply board. Withdraw the power supply board from the rear, unplugging it from the front bus. Re-assemble in the reverse order of the above sequence.

9.3.4

Replacing the back plane (size 4 and 6 cases) Remove the two screws securing the right hand terminal block to the top plate of the module. Remove the two screws securing the right hand terminal block to the bottom plate of the module. Unplug the back plane from the power supply board. Twist outwards and around to the side of the module. Replace the PCB and terminal block assembly. Re-assemble in the reverse order of the above sequence.



Recalibration Re-calibration is not usually required when a PCB is replaced unless it happens to be one of the two boards that plugs directly on to the left hand terminal block as this one directly affects the calibration. Although it is possible to carry out recalibration on site, this requires test equipment with suitable accuracy and a special calibration programme to run on a PC. It is therefore recommended that the work is carried out at the factory, or entrusted to an approved service centre. After calibration, the relay will need to have all the settings required for the application re-entered if a replacement board has been fitted. Therefore, it is useful if a copy of the settings is available on a floppy disk. Although this is not essential, it can reduce the time taken to re-enter the settings and hence the time the protection is out of service.


Appendix 1 Relay Characteristic Curves


R8551C Appendix 1 Contents

1. Figure 1: Figure 2:

TIME/CURRENT CHARACTERISTICS Operating times KCGG I>>, I>>>, Io>> and Io>>> Operating times KCEG I>>, I>>>, Io>> and Io>>>

1 1 1

2. Figure 3: Figure 4:

RELAY CHARACTERISTIC CURVES IDMT curves: IEC and special application curves IDMT curves: ANSI/IEEF curves

2 2 3

3. Figure 4:

THERMAL TIME/CHARACTERISTIC WITH PREFAULT LOAD Thermal time/current characteristic with prefault load

4 4


Section 1.

R8551C Appendix 1 Page 1 of 4

TIME/CURRENT CHARACTERISTICS

150 135 Maximum Minimum

120 105

) s m ( e m i t g n i t a r e p O

90 75 60 45 30 15 0 1

10 Multiple of setting (xIs)

100

Figure 1: Operating times KCGG I >>, I >>>, I o>> and I o>>>

150 135 Maximum Minimum

120 105

) s m ( e m i t g n i t a r e p O

90 75 60 45 30 15 0 1

10 Multiple of setting (xIs)

Figure 2: Operating times KCEG I >>, I >>>, I o>> and I o>>>

100


Section 2.


RELAY CHARACTERISTIC CURVES

10000

Rectifier curve 1000

) s d n o c e s ( e m i t g n i t a r e p O

100

10

LTI 30xDT SI 30xDT 1 EI 10xDT VI 30xDT STI 30xDT

0.1 1

10

LTI 30xDT

Long time inverse

SI 30xDT*

Sta ndard inverse

EI 10xDT*

Extremely inverse

VI 30xDT*

Very inverse

STI 30xDT

Shot time inverse

*IEC standard characteristic

100

Multiples of setting

All characteristics are definite time above 30x except extremely inverse.

Figure 3: IDMT curves: IEC and special application curves



10000

1000

) s d n o c e s ( e m i t g n i t a r e p O

100

10

MI 1

VI

EI

0.1 1

10 Multiples of setting

MI

Moderately inverse

VI

Ver y inverse

EI

Extremely inverse

All characteristics are definite time above 30x except extremely inverse.

Figure 4: IDMT curves: ANSI/IEEF curves

100


Section 3.


THERMAL TIME/CHARACTERISTIC WITH PREFAULT LOAD

10.000

1.000

) t x ( e m i T

0.100

No pre-fault load Pre-fault load at 50% thermal state Pre-fault load at 70% thermal state

0.010

Pre-fault load at 90% thermal state

0.001 1

2

3

4

Current (xlth>)

Figure 5: Thermal time/current characteristic with prefault load

5

6


Appendix 2 Logic Diagrams


R8551D Appendix 2 Contents

CONTENTS Figure 1a: Figure 1b: Figure 2a: Figure 2b: Figure 3a: Figure 3b: Figure 4a: Figure 4b: Figure 5a: Figure 5b: Figure 6a: Figure 6b:

Scheme logic diagram KCGG 122 Scheme logic diagram KCGG 122 Scheme logic diagram KCGG 142 Scheme logic diagram KCGG 142 Scheme logic diagram KCEG 112 Scheme logic diagram KCEG 112 Scheme logic diagram KCEG 142/242 Scheme logic diagram KCEG 142/242 Scheme logic diagram KCEG 152 Scheme logic diagram KCEG 152 Scheme logic diagram KCEU 142/242 Scheme logic diagram KCEU 142/242

1 2 3 4 5 6 7 8 9 10 11 12


R8551D Appendix 2 Page 1 of 12

0A01 BLK to > 7 6 5 4 3 2 1 0

&

o>

0B03 to>

to>

7 6 5 4 3 2 1 0

I

EF1 0 1 EF2 0 1

&

7 6 5 4 3 2 1 0

&

o>>

I

0B04 to>>

to>>

7 6 5 4 3 2 1 0

0A03 BLK to>>> 7 6 5 4 3 2 1 0

0B05 to>>>

&

o>>>

I

7 6 5 4 3 2 1 0

to>>>

7 6 5 4 3 2 1 0

&

>

0B09 t>

t>

7 6 5 4 3 2 1 0

I

PF2 0 1

7 6 5 4 3 2 1 0

0A02 BLK to>>

0A04 BLK t>

PF1 0 1

0B01 Io> Start

0B06 I> Start

&

7 6 5 4 3 2 1 0

0A05 BLK t>> 7 6 5 4 3 2 1 0

>>

I

0B0B t>>

&

t>>

&

t>>>

7 6 5 4 3 2 1 0

Start earth fault

Stage 2 earth fault

Stage 3 earth fault

Stage 1 overcurrent Start overcurrent

Stage 2 overcurrent

0A06 BLK t>>> 7 6 5 4 3 2 1 0 I

>>>

0B0C t>>> 7 6 5 4 3 2 1 0

0A07 L Trip

1

Trip circuit breaker

0A08 L Close

Broken conductor stage 3 overcurrent

0B0D CB Trip

7 6 5 4 3 2 1 0

0 1 SD2

Stage 1 earth fault


1

7 6 5 4 3 2 1 0

tTrip

7 6 5 4 3 2 1 0

tClose Reset

0B0E CB Close

Circuit breaker control

7 6 5 4 3 2 1 0

LOG9 0 1 1 0A09 Ext. Trip 7 6 5 4 3 2 1 0



I

o>

I

1

1

Latch flags Generate fault records & copy to event records

Figure 1a: Scheme logic diagram KCGG 122 (continued in Figure 1b)

Breaker fail protection

Fault record and flag latch initiation



0A0A Aux1

0B10 Aux1

tAux1

7 6 5 4 3 2 1 0

<

I

7 6 5 4 3 2 1 0

SD5 0 1

3Sec SD8 0 1

0A0B Aux2 SD8 0 1 LOG3 0 1 LOG4 0 1

7 6 5 4 3 2 1 0

tAux2

³1

<

o<

³1

7 6 5 4 3 2 1 0

LOGB 0 1

tAux3

0A0D Stg Grp 2

³1

7 6 5 4 3 2 1 0

SD3 0 1


Recorder stopped

Remote set Grp2

7 6 5 4 3 2 1 0

LOG6 0 1

I

0A0C Aux3 LOG8 0 1

Reset trip flags

0B11 Aux2

Recorder stopped I

³1

SD6 0 1

SD4 0 1

0B12 Aux3 7 6 5 4 3 2 1 0

LOG5 0 1 Change to setting group 2

0A0E CB Closed Ind

0A10 CB Bus 2

Cold load start

Setting control group

7 6 5 4 3 2 1 0

Load Shed Level 1

0B15 Level 2

Plant status word

Load Shed Level 2

PF0 0 1

7 6 5 4 3 2 1 0

0B16 Level 3

Load Shed Level 3

7 6 5 4 3 2 1 0

Load shedding plant status

7 6 5 4 3 2 1 0

0B17 th Alarm 7 6 5 4 3 2 1 0

Alarm 0A11 Reset Ith 7 6 5 4 3 2 1 0

LOG0 0 1

Loss of load /stage 4 EP

Auxiliary timers

0B14 Level 1

7 6 5 4 3 2 1 0 7 6 5 4 3 2 1 0

Disturbance recorder reset

Set 1 Reset 0

Remote reset Grp1

0D0F CB Open Ind

tAux1

0B18 th Trip

7 6 5 4 3 2 1 0

Trip Thermal reset

Thermal phase element

CB (ops) > 0B19 CB Alarm

CB duty >

³1

SD

EF1

LOG

EF2 F E D C B A 9 8 7 6 5 4 3 2 1 0

7 6 5 4 3 2 1 0

Circuit breaker alarms

PF1 PF2 F E D C B A 9 8 7 6 5 4 3 2 1 0

Figure 1b: Scheme logic diagram KCGG 122

F E D C B A 9 8 7 6 5 4 3 2 1 0



0A01 Blk to> 7 6 5 4 3 2 1 0

&

to>

o>

I

& EF1

0A02 Blk to>> 7 6 5 4 3 2 1 0

EF2

0A03 Blk to>>> 7 6 5 4 3 2 1 0

0 1

0 1

I

I

0B01 Io> Start 7 6 5 4 3 2 1 0

Start earth fault

&

to>>

0B04 to>> 7 6 5 4 3 2 1 0

Stage 2 earth fault

&

to>>>

0B05 to>>> 7 6 5 4 3 2 1 0

Stage 3 earth fault

0B08 tA> 7 6 5 4 3 2 1 0 0B09 tB> 7 6 5 4 3 2 1 0 0B0A tC> 7 6 5 4 3 2 1 0

Stage 1 overcurrent

0B06 I> Start 7 6 5 4 3 2 1 0

Start overcurrent

0B0B t>> 7 6 5 4 3 2 1 0

Stage 2 overcurrent

0B0C t>>> 7 6 5 4 3 2 1 0

Broken conductor Stage 3 overcurrent

o>>>

&

t>

>

I

>= 1

0 1

Stage 1 earth fault

o>>

0A04 Blk t> 7 6 5 4 3 2 1 0

PF1

0B03 to> 7 6 5 4 3 2 1 0

0A05 Blk t>> 7 6 5 4 3 2 1 0

&

t>>

&

t>>>

&

>= 1

>>

I

PFC 0 1

PF2 0 1

SD2 0 1

&

>> 7 6 5 4 3 2 1 0 I

>= 1 PF7

>>>

0A07 L TRIP 7 6 5 4 3 2 1 0

>= 1

Trip circuit breaker Close circuit breaker

0A08 L CLOSE 7 6 5 4 3 2 1 0

0

1

1

2/3 0B0D CB TRIP 7 6 5 4 3 2 1 0

tTRIP

>= 1 LOG9 >= 1

tCLOSE Reset

0B0E CB CLOSE 7 6 5 4 3 2 1 0


0 1

LOG2 0A09 EXT. TRIP 7 6 5 4 3 2 1 0

>=1

=1

tBF

0 1

0B0F CB FAIL 7 6 5 4 3 2 1 0

o<


RLY3 LOGA 0 1


>=1 RLY7 >=1

LOG7 0 1

>

I

>=1

Latch red trip LED

>=1

Latch flags generate fault record and copy to event records.

o>

I

Figure 2a: Scheme logic diagram KCGG 142 (continued in Figure 2b)



0A01 Blk to> 7 6 5 4 3 2 1 0 EF3

Io>


& EF4

0

EF5

0 1

1

0B03 to> 7 6 5 4 3 2 1 0

to> 0 1

&

0B01 Io> Fwd Start 7 6 5 4 3 2 1 0

&

0B02 Io>Rev Start 7 6 5 4 3 2 1 0

FWD REV 0A02 Blk to>> 7 6 5 4 3 2 1 0 1

EF1

EF4

1

EF2

EF5

0B04 to>> 7 6 5 4 3 2 1 0

Stage 2 earth fault

&

to>>>

0B05 to>>> 7 6 5 4 3 2 1 0

Stage 3 earth fault

0

Io>>>

1

FWD 0A07 L TRIP 7 6 5 4 3 2 1 0

>=1

TRIP CIRCUIT BREAKER

SD2 1 0

to>>

1

FWD 0A03 Blk to>>> 7 6 5 4 3 2 1 0

TRIP CIRCUIT BREAKER

0A08 L CLOSE 7 6 5 4 3 2 1 0

0B0D CB TRIP 7 6 5 4 3 2 1 0

tTRIP

>=1

tCLOSE Reset >=1

0A09 EXT. TRIP 7 6 5 4 3 2 1 0

Start earth fault

&

0

Io>>

Stage 1 earth fault

0B0E CB CLOSE 7 6 5 4 3 2 1 0


LOG9 1 0

LOG2 >=1

>=1

Io<

tBF

1 0

0B0E CB FAIL 7 6 5 4 3 2 1 0


RLY3

LOGA 1 0


>=1

Latch red trip LED

RLY7

LOG7 1 0

>=1

>=1 Io>

Latch flags Generate fault records & copy to event records

Figure 3a: Scheme logic diagram KCEG 112 (continued in Figure 3b)




0A0A AUX1 7 6 5 4 3 2 1 0 0A0B AUX2 7 6 5 4 3 2 1 0 SD8

0B10 AUX1 7 6 5 4 3 2 1 0

tAUX1

>=1

SD8

SD6

1 0

1 0

Recorder stopped Reset disturbance recorder

Recorder stopped

tAux1

Disturbance recorder reset

1 0

>=1 LOG4 1 0

tAUX2

0B11 AUX2 7 6 5 4 3 2 1 0

Loss of load /stage 4 EF

0B121 AUX3 7 6 5 4 3 2 1 0

Cold load start

Io<

LOG6 0

LOGB

0A0C AUX3 7 6 5 4 3 2 1 0

>=1

0

tAUX3

1

LOG8

LOG5

1 0

1 0

0A0D STG GRP 2 7 6 5 4 3 2 1 0

>=1 Remote set Grp2

SD3 1 0

0A0E CB CLOSED IND 7 6 5 4 3 2 1 0 Plant status word

0A10 CB BUS 2 7 6 5 4 3 2 1 0

LOG0 1 0

CB (0ps)>

SD

LOAD SHED LEVEL 1

0B14 LEVEL 1 7 6 5 4 3 2 1 0

LOAD SHED LEVEL 2

0B15 LEVEL 2 7 6 5 4 3 2 1 0

LOAD SHED LEVEL 3

0B16 LEVEL 3 7 6 5 4 3 2 1 0

0B19 CB ALARM 7 6 5 4 3 2 1 0

>=1

PF1

EF1 EF2

LOG FEDCBA98 76543210

Change to setting group 2

1 0

Setting group control

Set 1 Reset 0

Remote reset Grp1

0A0F CB OPEN IND 7 6 5 4 3 2 1 0

SD4

PF2 FEDCBA98 76543210

Figure 3b: Scheme logic diagram KCEG 112

FEDCBA98 76543210

Load shedding plant status

Cicuit breaker alarms


Appendix Appendix 3 Connection Diagrams


R8551D Appendix 3 Contents

CONTENTS 1. 2.

Connection diagrams for customising Connection diagrams for relays as supplied

Figure 1: Figure Figure 2: Figure Figure 3: Figure 4: 4: Figure Figure 5: 5: Figure Figure 6: 6: Figure Figure 7: Figure Figure 8: 8: Figure Figure 9: 9: Figure 10: Figure 11: Figu Figure re 12: 12: Figure 13: Figure 14: Figure 15 15: Figure 16: Figure 17: Figure 18: Figure 19: Figure 20: Figure 21: Figure 22:

Typical application diagram: 2 phase overcurrent relay KCGG 122 Typical ypical applica applicatio tionn diagra diagram: m: 3 phase phase overcu overcurren rrentt and and earth earth fault fault relay KCGG 142 01 Typical ypical applica applicatio tionn diagra diagram: m: 3 phase phase overcu overcurren rrentt and and earth earth fault fault relay KCGG 142 02 Typical ap application di diagram: di directional ea earth fa fault re relay KC KCEG 11 112 Typical ypical appl applica icatio tionn diagra diagram: m: 3 phase phase over overcur curren rentt and dire directi ctiona onall earth fault relay KCEG 142 Typical ypical appl applica icatio tionn diagra diagram: m: 3 phase phase over overcur curren rentt and dire directi ctiona onall earth earth fault relay KCEG 152 Typical ypical applica applicatio tionn diagra diagram: m: dual dual powere powered d 3 phase phase over overcur curren rentt and earth fault relay KCEG 242 Typical ypical appl applica icatio tionn diagra diagram: m: direc directio tional nal 3 phas phasee overcu overcurre rrent nt and and sensitive wattmetric earth fault relay KCEU 142 Typical ypical appl applica icatio tionn diagra diagram: m: direc directio tional nal 3 phas phasee overcu overcurre rrent nt and and sensitive wattmetric earth fault relay KCEU 242 Typical Typical application application diagram: diagram: KCEU 142 142 showing showing connection connection for broken delta VT winding Typical Typical application application diagram: diagram: KCEU 242 242 showing showing connection connection for broken delta VT winding Typic ypical al appl applic icat atio ionn dia diagr gram am:: 2 phas phasee ove overc rcur urre rent nt and and rel relay ay KCCG KCCG 122 122 Typical Typical application application diagram: diagram: 3 phase overcur overcurrent rent and and earth fault fault relay KCGG 142 01 Typical Typical application application diagram: diagram: 3 phase overcur overcurrent rent and and earth fault fault relay KCGG 142 02 Typical ap appli plicatio tion di diagram: am: di directional ea earth rth fa fault rel rela ay KC KCEG 112 112 Typical Typical application application diagram: diagram: 3 phase directi directional onal earth earth fault relay KCEG 142 Typical Typical application application diagram: diagram: 3 phase overcur overcurrent rent and and directional directional earth fault relay KCEG 152 Typical Typical application application diagram: diagram: dual dual powered powered 3 phase phase overcurre overcurrent nt and directional earth fault relay KCEG 242 Typical Typical application application diagram: diagram: directional directional 3 phase overcur overcurrent rent and sensitive wattmetric earth fault relay KCEU 142 Typical Typical application application diagram: diagram: directional directional 3 phase overcur overcurrent rent and sensitive wattmetric earth fault relay KCEU 242 Typical Typical application application diagram: diagram: KCEU 142 142 showing showing connection connection for broken delta VT winding Typical Typical application application diagram: diagram: KCEU 242 242 showing showing connection connection for broken delta VT winding

1 12 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22


Appendix 4 Commissioning Test Record

SERVICE MANUAL KCGG 122, 142 KCEG 112, 142, 152, 242 KCEU 142, 242 1. 2.

COMMISSIONING TEST RECORD SETTING RECORD REPAIR FORM

R8551C Appendix 4 Contents

1 6 11

SERVICE MANUAL KCGG 122, 142 KCEG 112 142, 152, 242 KCEU 142, 242


Section 1. COMMISSIONING TEST RECORD

Date Station

Circuit System Frequency

Front plate information Multifunctional overcurrent relay type

KC________

Model number Serial number Auxiliary Voltage Vx Polarising Voltage Vn Rated Current In

*Delete as appropriate 4

Product checks

4.1

With the relay de-energised

4.1.1

Visual inspection Module and case damaged?

Yes/No*

Model numbers on case and front plate match?

Yes/No*

Serial numbers on case and front plate match?

Yes/No*

Rating information correct for installation?

Yes/No*

All current transformer shorting switches closed?

Yes/No*

Case earth installed?

Yes/No*

4.1.2

Insulation resistance correct?

Yes/No/Not Tested*

4.1.3

External wiring Wiring checked against diagram?

Yes/No*

Test block connections checked?

Yes/No/na*

SERVICE MANUAL KCGG 122, 142 KCEG 112 142, 152, 242 KCEU 142, 242 4.1.4

Watchdog contacts With auxiliary supply off

4.1.5

Auxiliary supply

4.2

With the relay energised

4.2.1

Watchdog contacts With auxiliary supply on

4.2.2

4.2.3

4.2.4

4.2.5

4.2.6


Terminals 3 and 5

Open/Closed*

Terminals 4 and 6

Open/Closed* ______V ac/dc*

Terminals 3 and 5

Open/Closed*

Terminals 4 and 6

Open/Closed*

Light emitting diodes Relay healthy (green) LED working?

Yes/No*

Alarm (yellow) LED working?

Yes/No*

Trip (red) LED working?

Yes/No*

Liquid crystal display All pixels working?

Yes/No*

Backlight switches on and off?

Yes/No*

Field supply voltage Relay energised from auxiliary supply

______V dc

Relay energised from line current transformers (Section 4.2.11 – KCEG 242 and KCEU 242 only)

______V dc/na*

Capacitor trip voltage Relay energised from auxiliary supply

______V dc

Relay energised from line current transformers (Section 4.2.11 – KCEG 242 and KCEU 242 only)

______V dc/na*

Input opto-isolators Input L0 working?

Yes/No*

Input L1 working?

Yes/No*

Input L2 working?

Yes/No*

Input L3 working?

Yes/No/na*

Input L4 working?

Yes/No/na*

Input L5 working?

Yes/No/na*

Input L6 working?

Yes/No/na*

Input L7 working?

Yes/No/na*

SERVICE MANUAL KCGG 122, 142 KCEG 112 142, 152, 242 KCEU 142, 242 4.2.7


Output relays Output RL0 working?

Yes/No*

Output RL1 working?

Yes/No*

Output RL2 working?

Yes/No*

Output RL3 working?

Yes/No*

Output RL4 working?

Yes/No/na*

Output RL5 working?

Yes/No/na*

Output RL6 working?

Yes/No/na*

Output RL7 working?

Yes/No/na*

4.2.8

K-Bus communications working?

Yes/No/na*

4.2.9

Current inputs CT ratio (phase currents)

_______:1A

CT ratio (Zero sequence current)

_______:1A/na*

Input CT

Applied value

Relay value

Ia

_______A/na*

_______A

Ib

_______A/na*

_______A

Ic

_______A/na*

_______A

Io

_______A/na*

_______A

4.2.10 Voltage inputs (KCEG and KCEU relays only) VT Ratio (phase voltages)

_______:1V/na*

VT Ratio (residual voltage)

_______:1V/na*

Input VT

Applied value

Relay value

Va

_______V/na*

_______V

Vb

_______V/na*

_______V

Vc

_______V/na*

_______V

Vo

_______V/na*

_______V

4.2.11 Energisation from line current transformers (KCEG 242 and KCEU 242 relays only) Record results under Sections 4.2.4 and 4.2.5



5

Setting checks

5.1

Customer’s settings applied?

Yes/No*

If settings applied using a portable computer and software, which software and version was used?

____________________

5.2

Settings on relay verified?

Yes/No*

5.3

Protection function timing tested?

Yes/No*

Function tested

t>/to>

6

6.1.1

Polarising voltage

(KCEG/KCEU relays only)

_________V/na*

Characteristic angle

(KCEG/KCEU relays only)

_________°/na*

Operating boundary 1 (KCEG/KCEU relays only)

_________°/na*

Operating boundary 2 (KCEG/KCEU relays only)

_________°/na*

Applied current

_________A

Expected nominal operating time

_________s

Actual operating time

_________s

On-load checks Test wiring removed?

Yes/No/na*

Disturbed customer wiring re-checked?

Yes/No/na*

On-load test performed?

Yes/No*

VT wiring checked? (KCEG/KCEU relays only)

Yes/No/na*

VT ratio (Phase voltages)

____:1V/na*

VT ratio (Residual voltage)

____:1V/na*

Phase rotation correct

Yes/No*

Voltages:

Applied value

Relay value

Va

_______V/na*

_______V

Vb

_______V/na*

_______V

Vc

_______V/na*

_______V

Vo

_______V/na*

_______V


6.1.2


CT wiring checked?

Yes/No/na*

and 6.2 CT ratio (Phase currents)

____:1A/na*

CT ratio (Earth fault currents)

7

____:1A/na*

Currents:

Applied value

Relay value

Ia

_______A/na*

_______A

Ib

_______A/na*

_______A

Ic

_______A/na*

_______A

Io

_______A/na*

_______A

Final checks Test wiring removed?

Yes/No/na*

Disturbed customer wiring re-checked?

Yes/No/na*

Circuit breaker operations counter set/reset?

Set/Reset/na*

If set, value counter set to:

________/na*

Current squared counters set/reset?

Set/Reset/na*

If set, value counter set to:

(‘A’ phase)

________A2/na*

(‘B’ phase)

________A2/na*

(‘C’ phase)

________A2/na*

Event records reset?

Yes/No*

Fault records reset?

Yes/No*

Disturbance records reset

Yes/No*

Alarms reset?

Yes/No*

LEDs reset?

Yes/No*

Commissioning Engineer

Customer Witness

Date

Date



Section 2. SETTING RECORD Date

Engineer

Station

Date

Circuit

System Frequency

Front plate information Multifunctional overcurrent relay type

KC________

Model number Serial number Auxiliary Voltage Vx Polarising Voltage Vn Rated Current In

0000SYSTEM DATA 0002

Password

0003

SD Links

0004

Description

0005

Plant

0006

Model

0008

Serial No.

0009

Frequency

000A

Comms Level

000B

Rly Address

0011

Software Ref.

F E D C B A 9 8 7 6 5 4 3 2 1 0 0 0 0 0 0 0 0

0



0500

EARTH FLT 1

F E D C B A 9 8 7 6 5 4 3 2 1 0

0501 0502

EF Links CT Ratio

0

0503

VT Ratio

0504

Curve

0505

Io>

0506

to/TMS

0507

to/DT

0508

toRESET

0509

Io>>

050A 050B

to>> Io>>>

050C

to>>>

050D 050E

Char Angle Io<

050F

Vop>

0600 0601 0602 0603 0604 0605 0606 0607 0608 0609 060A 060B 060C 060D 060E 060F 0610 0611 0612 0613 0614

PHASE FLT 1 PF Links CT Ratio VT Ratio Curve I> t/TMS t/DT tRESET I>> t>> I>>> t>>> Char Angle I< V< tV< F< th> Alarm Ith> Trip TC

0 0 0 0 0 0 0

0

F E D C B A 9 8 7 6 5 4 3 2 1 0



0700 0701 0702 0703 0704 0705 0706 0707 0708 0709 070A 070B 070C 070D 070E 070F 0710

EARTH FLT 2 EF Links CT Ratio VT Ratio Curve Io> to/TMS to/DT toRESET Io>> to>> Io>>> to>>> Char Angle Io< Vop> Po>

F E D C B A 9 8 7 6 5 4 3 2 1 0 0 0 0 0 0 0 0 0 0

0800 0801 0802 0803 0804 0805 0806 0807 0808 0809 080A 080B 080C 080D 080E 080F 0810 0811 0812 0813 0814

PHASE FLT 2 PF Links CT Ratio VT Ratio Curve I> t/TMS t/DT tRESET I>> t>> I>>> t>>> Char Angle I< V< tV< F< th> Alarm Ith> Trip TC

F E D C B A 9 8 7 6 5 4 3 2 1 0



0900

LOGIC

F E D C B

0901

LOG Links

0 0 0 0

0902

tBF

0903

tAUX1

0904

tAUX2

0905

tAUX3

0906

tTRIP

0907

tCLOSE

0908

CB ops>

0909

CB duty>

090F

Display

0A00

INPUT MASKS F E D C B

0A01

Blk to>

0 0 0 0

0A02

Blk to>>

0 0 0 0 0 0 0 0

0A03

Blk to>>>

0 0 0 0 0 0 0 0

0A04

Blk t>

0 0 0 0 0 0 0 0

0A05

Blk t>>

0 0 0 0

0A06

Blk t>>>

0 0 0 0 0 0 0 0

0A07

L Trip

0 0 0 0 0 0 0 0

0A08

L Close

0 0 0 0 0 0 0 0

0A09

Ext Trip

0 0 0 0 0 0 0 0

0A0A

Aux 1

0 0 0 0 0

0A0B

Aux 2

0 0 0 0 0 0 0 0

0A0C

Aux 3

0 0 0 0 0

0A0D

Set Grp 2

0 0 0 0 0 0 0 0

0A0E

CB Closed

0 0 0 0 0 0 0 0

0A0F

CB Open

0 0 0 0 0 0 0 0

0A10

Bus2

0 0 0 0 0

0A11

Reset Ith

0 0 0 0 0 0 0 0

A 9 8 7 6 5 4 3 2 1 0

A 9 8 7 6 5 4 3 2 1 0

0 0 0 0

0 0 0 0

0 0 0 0 0 0

0 0 0



0B00

RELAY MASKS F E D C B A 9 8 7 6 5 4 3 2 1 0

0B01

Io>

Fwd

0 0 0 0

0 0 0 0

0B02

Io>

Rev

0 0 0 0

0 0 0

0B03

to>

0 0 0 0

0 0 0 0

0B04

to>>

0 0 0 0

0 0 0 0

0B05

to>>>

0 0 0 0

0 0 0 0

0B06

I>Fwd

0 0 0 0

0 0

0B07

I>Rev

0 0 0 0

0 0 0 0

0B08

tA>

0 0 0 0

0 0 0 0

0B09

tB>

0 0 0 0

0 0 0 0

0B0A

tC>

0 0 0 0

0 0

0B0B

t>>

0 0 0 0

0 0 0 0

0B0C

t>>>

0 0 0 0

0 0 0

0B0D

CB Trip

0 0 0 0

0 0 0 0

0B0E

CB Close

0 0 0 0

0 0 0 0

0B0F

CB Fail

0 0 0 0

0 0 0 0

0B10

Aux 1

0 0 0 0

0 0 0 0

0B11

Aux 2

0 0 0 0

0 0 0 0

0B12

Aux 3

0 0 0 0

0 0 0 0

0B13

tV<

0 0 0 0

0 0 0 0

0B14

Level 1

0 0 0 0

0 0 0 0

0B15

Level 2

0 0 0 0

0 0 0 0

0B16

Level 3

0 0 0 0

0 0 0 0

0B17

thAlarm

0 0 0 0

0 0 0 0

0B18

thTrip

0 0 0 0

0 0

0B19

CB Alarm

0 0 0 0

0 0 0 0

0C00

RECORDER

F E D C B A 9 8 7 6 5 4 3 2 1 0

0C01

Control

0C02

Capture

0C03

Post Trigger

0C04

Logic Trig

0C05

Relay Trig

0

0 0

0 0 0

0 0



REPAIR FORM Please complete this form and return it to ALSTOM T&D Protection & Control Limited with the equipment to be repaired. This form may also be used in the case of application queries.

ALSTOM T&D Protection & Control Limited St. Leonards Works Stafford ST17 4LX, England For:

After Sales Service Department

Customer Ref:

________________________

Model No:

__________________

ALSTOM Contract Ref: ________________________

Serial No:

__________________

Date: 1.

________________________

What parameters were in use at the time the fault occurred? AC volts

_____________ Main VT/Test set

DC volts

_____________ Battery/Power supply

AC current

_____________ Main CT/Test set

Frequency

_____________

2.

Which type of test was being used? ____________________________________________

3.

Were all the external components fitted where required? (Delete as appropriate.)

4.

List the relay settings being used

Yes/No

____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ 5. What did you expect to happen? ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________

continued overleaf

¡

SERVICE MANUAL KCGG 122, 142 KCEG 112 142, 152, 242 KCEU 142, 242 6.


What did happen? ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________

7. When did the fault occur? Instant

Yes/No

Intermittent

Yes/No

Time delayed

Yes/No

(Delete as appropriate).

By how long?

___________

8. What indications if any did the relay show? ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ 9. Was there any visual damage? ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ 10. Any other remarks which may be useful: ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________

______________________________________ Signature

_______________________________________ Title

______________________________________ Name (in capitals)

_______________________________________ Company name

¡

Kcgg142 Man

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