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MiCOM P341
Interconnection Protection Relay
P341/EN M/G74
Software Version 36 & 71
Hardware Suffix J
Technical Manual
Note
The technical manual for this device gives instructions for its installation, commissioning, and operation.
However, the manual cannot cover all conceivable circumstances or include detailed information on all topics.
In the event of questions or specific problems, do not take any action without proper authorization. Contact the appropriate Schneider Electric technical sales office and request the necessary information.
Any agreements, commitments, and legal relationships and any obligations on the part of Schneider Electric including settlements of warranties, result solely from the applicable purchase contract, which is not affected by the contents of the technical manual.
This device MUST NOT be modified. If any modification is made without the express permission of
Schneider Electric, it will invalidate the warranty, and may render the product unsafe.
The Schneider Electric logo and any alternative version thereof are trademarks and service marks of Schneider Electric.
All trade names or trademarks mentioned herein whether registered or not, are the property of their owners.
This manual is provided for informational use only and is subject to change without notice.
© 2012 , Schneider Electric. All rights reserved.
MiCOM P341
CONTENTS
Section No Description
Safety Information
1 Introduction
2 Technical Data
3 Getting Started
4 Settings
5 Operation
6 Application Notes
7
8
Programmable Logic
Measurements and Recording
9 Firmware Design
10 Commissioning
13
14
11 Maintenance
12 Troubleshooting
SCADA Communications
Symbols and Glossary
15 Installation
16 Firmware and Service Manual Version History
Contents
Publication Reference
Pxxx/EN SI/G12
P341/EN TD/G74
P34x_P341/EN GS/J96
P341/EN AP/G74
P341/EN PL/G74
P341/EN MR/G74
P341/EN FD/G74
P341/EN SC/G74
Pxxx/EN SG/A03
P341/EN VH/G74
P341/EN CO/G74 Page ( CO ) 1
Contents
Notes:
MiCOM P341
Page ( CO ) 2 P341/EN CO/G74
MiCOM Pxxx SI Safety Information
Pxxx/EN SI/G12
SAFETY INFORMATION
CHAPTER SI
Page SI-1
SI Safety Information MiCOM Pxxx
Page SI-2 Pxxx/EN SI/G12
Contents SI Safety Information
CONTENTS
3 SYMBOLS AND LABELS ON THE EQUIPMENT
4 INSTALLING, COMMISSIONING AND SERVICING
5 DE-COMMISSIONING AND DISPOSAL
6 TECHNICAL SPECIFICATIONS FOR SAFETY
Pxxx/EN SI/G12 Page SI-3
SI Safety Information
Notes:
Contents
Page SI-4 Pxxx/EN SI/G12
Introduction SI Safety Information
1 INTRODUCTION
This guide and the relevant equipment documentation provide full information on safe handling, commissioning and testing of this equipment. This Safety Information section also includes reference to typical equipment label markings.
Documentation for equipment ordered from Schneider Electric is dispatched separately from manufactured goods and may not be received at the same time. Therefore this guide is provided to ensure that printed information which may be present on the equipment is fully understood by the recipient.
The technical data in this Safety Information section is typical only, see the technical data section of the relevant product publication(s) for data specific to a particular equipment.
WARNING Before carrying out any work on the equipment the user should be familiar with the contents of this Safety Information section and the ratings on the equipment’s rating label.
Reference should be made to the external connection diagram before the equipment is installed, commissioned or serviced.
Language-specific, self-adhesive User Interface labels are provided in a bag for some equipment.
Pxxx/EN SI/G12 Page SI-5
SI Safety Information
2
Health and Safety
HEALTH AND SAFETY
The information in the Safety Information section of the equipment documentation is intended to ensure that equipment is properly installed and handled in order to maintain it in a safe condition.
It is assumed that everyone who will be associated with the equipment will be familiar with the contents of that Safety Information section, or this Safety Guide.
When electrical equipment is in operation, dangerous voltages will be present in certain parts of the equipment. Failure to observe warning notices, incorrect use, or improper use may endanger personnel and equipment and also cause personal injury or physical damage.
Before working in the terminal strip area, the equipment must be isolated.
Proper and safe operation of the equipment depends on appropriate shipping and handling, proper storage, installation and commissioning, and on careful operation, maintenance and servicing. For this reason only qualified personnel may work on or operate the equipment.
Qualified personnel are individuals who:
Are familiar with the installation, commissioning, and operation of the equipment and of the system to which it is being connected;
Are able to safely perform switching operations in accordance with accepted safety engineering practices and are authorized to energize and de-energize equipment and to isolate, ground, and label it;
Are trained in the care and use of safety apparatus in accordance with safety engineering practices;
Are trained in emergency procedures (first aid).
The equipment documentation gives instructions for its installation, commissioning, and operation. However, the manuals cannot cover all conceivable circumstances or include detailed information on all topics. In the event of questions or specific problems, do not take any action without proper authorization. Contact the appropriate Schneider Electric technical sales office and request the necessary information.
Page SI-6 Pxxx/EN SI/G12
Symbols and Labels on the Equipment
3
3.1
SI Safety Information
SYMBOLS AND LABELS ON THE EQUIPMENT
For safety reasons the following symbols and external labels, which may be used on the equipment or referred to in the equipment documentation, should be understood before the equipment is installed or commissioned.
Symbols
Caution: refer to equipment documentation
Caution: risk of electric shock
Protective Conductor (*Earth) terminal
Functional/Protective Conductor (*Earth) terminal
Note: This symbol may also be used for a Protective Conductor
(Earth) Terminal if that terminal is part of a terminal block or sub-assembly e.g. power supply.
3.2
*CAUTION: The term “Earth” used throughout this technical manual is the direct equivalent of the North American term
“Ground”.
Labels
See Safety Guide (SFTY/4L M) for typical equipment labeling information.
Pxxx/EN SI/G12 Page SI-7
SI Safety Information
4
Installing, Commissioning and Servicing
INSTALLING, COMMISSIONING AND SERVICING
Manual Handling
Plan carefully, identify any possible hazards and determine whether the load needs to be moved at all. Look at other ways of moving the load to avoid manual handling. Use the correct lifting techniques and Personal Protective Equipment to reduce the risk of injury.
Many injuries are caused by:
Lifting heavy objects
Lifting things incorrectly
Pushing or pulling heavy objects
Using the same muscles repetitively.
Follow the Health and Safety at Work, etc Act 1974, and the Management of Health and
Safety at Work Regulations 1999.
Equipment Connections
Personnel undertaking installation, commissioning or servicing work for this equipment should be aware of the correct working procedures to ensure safety.
The equipment 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.
The clamping screws of all terminal block connectors, for field wiring, using M4 screws shall be tightened to a nominal torque of 1.3 Nm.
Equipment intended for rack or panel mounting is for use on a flat surface of a Type 1 enclosure, as defined by Underwriters Laboratories (UL).
Any disassembly of the equipment may expose parts at hazardous voltage, also electronic parts may be damaged if suitable ElectroStatic voltage Discharge (ESD) precautions are not taken.
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 shall be made using insulated crimp terminations to ensure that terminal block insulation requirements are maintained for safety.
Watchdog (self-monitoring) contacts are provided in numerical relays to indicate the health of the device. Schneider Electric strongly recommends that these contacts are hardwired into the substation's automation system, for alarm purposes.
To ensure that wires are correctly terminated the correct crimp terminal and tool for the wire size should be used.
The equipment must be connected in accordance with the appropriate connection diagram.
Protection Class I Equipment
Before energizing the equipment it must be earthed using the protective conductor terminal, if provided, or the appropriate termination of the supply plug in the case of plug connected equipment.
The protective conductor (earth) connection must not be removed since the protection against electric shock provided by the equipment would be lost.
When the protective (earth) conductor terminal (PCT) is also used to terminate cable screens, etc., it is essential that the integrity of the protective (earth) conductor is checked after the addition or removal of such functional earth connections. For M4 stud PCTs the integrity of the protective (earth) connections should be ensured by use of a locknut or similar.
The recommended minimum protective conductor (earth) wire size is 2.5 mm² (3.3 mm² for North America) unless otherwise stated in the technical data section of the equipment documentation, or otherwise required by local or country wiring regulations.
The protective conductor (earth) connection must be low-inductance and as short as possible.
Page SI-8 Pxxx/EN SI/G12
Installing, Commissioning and Servicing SI Safety Information
All connections to the equipment must have a defined potential. Connections that are pre-wired, but not used, should preferably be grounded when binary inputs and output relays are isolated. When binary inputs and output relays are connected to common potential, the pre-wired but unused connections should be connected to the common potential of the grouped connections.
Pre-Energization Checklist
Before energizing the equipment, the following should be checked:
Voltage rating/polarity (rating label/equipment documentation);
CT circuit rating (rating label) and integrity of connections;
Protective fuse rating;
Integrity of the protective conductor (earth) connection (where applicable);
Voltage and current rating of external wiring, applicable to the application.
Accidental Touching of Exposed Terminals
If working in an area of restricted space, such as a cubicle, where there is a risk of electric shock due to accidental touching of terminals which do not comply with IP20 rating, then a suitable protective barrier should be provided.
Equipment Use
If the equipment is used in a manner not specified by the manufacturer, the protection provided by the equipment may be impaired.
Removal of the Equipment Front Panel/Cover
Removal of the equipment front panel/cover may expose hazardous live parts, which must not be touched until the electrical power is removed.
UL and CSA/CUL Listed or Recognized Equipment
To maintain UL and CSA/CUL Listing/Recognized status for North America the equipment should be installed using UL or CSA Listed or Recognized parts for the following items: connection cables, protective fuses/fuseholders or circuit breakers, insulation crimp terminals and replacement internal battery, as specified in the equipment documentation.
For external protective fuses a UL or CSA Listed fuse shall be used. The Listed type shall be a Class J time delay fuse, with a maximum current rating of 15 A and a minimum d.c. rating of 250 Vd.c., for example type AJT15.
Where UL or CSA Listing of the equipment is not required, a high rupture capacity
(HRC) fuse type with a maximum current rating of 16 Amps and a minimum d.c. rating of
250 Vd.c. may be used, for example Red Spot type NIT or TIA.
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. Generally, for safety, the secondary of the line CT must be shorted before opening any connections to it.
For most equipment with ring-terminal connections, the threaded terminal block for current transformer termination has automatic CT shorting on removal of the module.
Therefore external shorting of the CTs may not be required, the equipment documentation should be checked to see if this applies.
For equipment with pin-terminal connections, the threaded terminal block for current transformer termination does NOT have automatic CT shorting on removal of the module.
External Resistors, including Voltage Dependent Resistors (VDRs)
Where external resistors, including Voltage Dependent Resistors (VDRs), are fitted to the equipment, 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, buildings and persons.
Pxxx/EN SI/G12 Page SI-9
SI Safety Information Installing, Commissioning and Servicing
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
Modules and PCB cards must not be inserted into or withdrawn from the equipment whilst it is energized, since this may result in damage.
Insertion and Withdrawal of Extender Cards
Extender cards are available for some equipment. If an extender card is used, this should not be inserted or withdrawn from the equipment whilst it is energized. This is to avoid possible shock or damage hazards. Hazardous live voltages may be accessible on the extender card.
External Test Blocks and Test Plugs
Great care should be taken when using external test blocks and test plugs such as the
MMLG, MMLB and MiCOM P990 types, hazardous voltages may be accessible when using these. *CT shorting links must be in place before the insertion or removal of
MMLB test plugs, to avoid potentially lethal voltages.
*Note: When a MiCOM P992 Test Plug is inserted into the MiCOM P991
Test Block, the secondaries of the line CTs are automatically shorted, making them safe.
Fiber Optic Communication
Where fiber 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.
Cleaning
The equipment may be cleaned using a lint free cloth dampened with clean water, when no connections are energized. Contact fingers of test plugs are normally protected by petroleum jelly, which should not be removed.
Page SI-10 Pxxx/EN SI/G12
De-commissioning and Disposal
5
SI Safety Information
DE-COMMISSIONING AND DISPOSAL
De-commissioning
The supply input (auxiliary) for the equipment may include capacitors across the supply or to earth. To avoid electric shock or energy hazards, after completely isolating the supplies to the equipment (both poles of any dc supply), the capacitors should be safely discharged via the external terminals prior to de-commissioning.
Disposal
It is recommended that incineration and disposal to water courses is avoided. The equipment should be disposed of in a safe manner. Any equipment 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 the equipment.
Pxxx/EN SI/G12 Page SI-11
SI Safety Information
6
6.1
6.2
6.3
6.4
Technical Specifications for Safety
TECHNICAL SPECIFICATIONS FOR SAFETY
Unless otherwise stated in the equipment technical manual, the following data is applicable.
Protective Fuse Rating
The recommended maximum rating of the external protective fuse for equipments is 16A,
High Rupture Capacity (HRC) Red Spot type NIT, or TIA, or equivalent. Unless otherwise stated in equipment technical manual, the following data is applicable. The protective fuse should be located as close to the unit as possible.
DANGER CTs must NOT be fused since open circuiting them may produce lethal hazardous voltages.
Protective Class
IEC 60255-27: 2005
EN 60255-27: 2005
Class I (unless otherwise specified in the equipment documentation).
This equipment requires a protective conductor (earth) connection to ensure user safety.
Installation Category
IEC 60255-27: 2005
EN 60255-27: 2005
Installation Category III (Overvoltage Category III)
Distribution level, fixed installation.
Equipment in this category is qualification tested at 5 kV peak, 1.2/50 µs, 500 , 0.5 J, between all supply circuits and earth and also between independent circuits.
Environment
The equipment is intended for indoor installation and use only. If it is required for use in an outdoor environment then it must be mounted in a specific cabinet of housing which will enable it to meet the requirements of IEC 60529 with the classification of degree of protection IP54 (dust and splashing water protected).
Pollution Degree
Altitude
Pollution Degree 2 Compliance is demonstrated by reference to safety standards.
Operation up to 2000m
Page SI-12 Pxxx/EN SI/G12
MiCOM P341 (IT) 1 Introduction
P341/EN IT/G74
INTRODUCTION
CHAPTER 1
Page (IT) 1-1
(IT) 1 Introduction
Hardware Suffix:
Software Version:
Connection Diagrams:
J
31 and 71 (with DLR)
10P341xx (xx = 01 to 12)
MiCOM P341
Page (IT) 1-2 P341/EN IT/G74
Contents
CONTENTS
1 Documentation Structure
2 Introduction to MiCOM
3 Product Scope
FIGURES
TABLES
(IT) 1 Introduction
Page (IT) 1-
5
7
8
Page (IT) 1-
Page (IT) 1-
P341/EN IT/G74 Page (IT) 1-3
(IT) 1 Introduction
Notes:
TablesDocumentation Structure Documentation Structure
Page (IT) 1-4 P341/EN IT/G74
Documentation Structure (IT) 1 Introduction
The manual provides a functional and technical description of the MiCOM protection relay and a comprehensive set of instructions for the relay’s use and application.
The chapter contents are summarized below:
P341/EN IT 1. Introduction
A guide to the range of relays and the documentation structure.
General safety aspects of handling Electronic Equipment is discussed with particular reference to relay safety symbols. Also a general functional overview of the relay and brief application summary is given.
2. Technical Data P341/EN TD
Technical data including setting ranges, accuracy limits, recommended operating conditions, ratings and performance data.
Compliance with norms and international standards is quoted where appropriate.
P34x_P341/EN GS 3. Getting Started
A guide to the different user interfaces of the protection relay describing how to start using it. This chapter provides detailed information regarding the communication interfaces of the relay, including a detailed description of how to access the settings database stored within the relay.
P341/EN ST
P341/EN OP
4. Settings
List of all relay settings, including ranges, step sizes and defaults, together with a brief explanation of each setting.
5. Operation
P341/EN AP
P341/EN PL
A comprehensive and detailed functional description of all protection and non-protection functions.
6. Application Notes
This chapter includes a description of common power system applications of the relay, calculation of suitable settings, some typical worked examples, and how to apply the settings to the relay.
7. Programmable Logic
P341/EN MR
P341/EN FD
Overview of the Programmable Scheme Logic (PSL) and a description of each logical node. This chapter includes the factory default and an explanation of typical applications.
8. Measurements and Recording
Detailed description of the relays recording and measurements functions including the configuration of the event and disturbance recorder and measurement functions.
9. Firmware Design
Overview of the operation of the relay’s hardware and software.
This chapter includes information on the self-checking features and diagnostics of the relay.
P341/EN IT/G74 Page (IT) 1-5
(IT) 1 Introduction Documentation Structure
P341/EN CM
Pxxx/EN MT
Pxxx/EN TS
P341/EN SC
Pxxx/EN SG
P341/EN IN
P341/EN VH
10. Commissioning
Instructions on how to commission the relay, comprising checks on the calibration and functionality of the relay.
11. Maintenance
A general maintenance policy for the relay is outlined.
12. Troubleshooting
Advice on how to recognize failure modes and the recommended course of action. Includes guidance on whom within Schneider
Electric to contact for advice.
13. SCADA Communications
This chapter provides an overview regarding the SCADA communication interfaces of the relay. Detailed protocol mappings, semantics, profiles and interoperability tables are not provided within this manual. Separate documents are available per protocol, available for download from our website.
14. Symbols and Glossary
List of common technical abbreviations found within the product documentation.
15. Installation
Recommendations on unpacking, handling, inspection and storage of the relay. A guide to the mechanical and electrical installation of the relay is provided, incorporating earthing recommendations. All external wiring connections to the relay are indicated.
16. Firmware and Service Manual Version History
History of all hardware and software releases for the product.
Page (IT) 1-6 P341/EN IT/G74
Introduction to MiCOM (IT) 1 Introduction
MiCOM is a comprehensive solution capable of meeting all electricity supply requirements. It comprises a range of components, systems and services from Schneider
Electric.
Central to the MiCOM concept is flexibility.
MiCOM provides the ability to define an application solution and, through extensive communication capabilities, integrate it with your power supply control system.
The components within MiCOM are:
P range protection relays;
C range control products;
M range measurement products for accurate metering and monitoring;
S range versatile PC support and substation control packages.
MiCOM products include extensive facilities for recording information on the state and behavior of the power system using disturbance and fault records. At regular intervals they can provide measurements of the system to a control center, allowing remote monitoring and control.
For up-to-date information on any MiCOM product, visit our website: www.schneider-electric.com
P341/EN IT/G74 Page (IT) 1-7
(IT) 1 Introduction
3.1
Page (IT) 1-8
Product Scope
The P341 protection relay (3x software) has been designed for the protection of the interconnecting feeder at the point of connection of a Distributed Generator (DG) with the main power supply network. The relay provides flexible and reliable integration of protection, control, monitoring and measurements for this interconnection application such as voltage and frequency protection and Loss Of Mains/grid (LOM) protection (df/dt or voltage vector shift) plus feeder protection (overcurrent and earth fault) and CB control with check synchronization. Extensive functionality is available to satisfy complete protection and control for a wide range of system applications, including protection for both the connection point and DG in simple applications or the more sophisticated interconnection protection necessary for larger units or those connected at higher voltages.
TheP341 protection relay (7x software) has additionally been designed to provide
Dynamic Line Rating (DLR) protection. With the increase of embedded generation in the distribution network, there is a need for the electricity distributors to optimize their network resources.
The overhead line thermal rating is based on the highest current that a power line can carry without compromising the strength of the conductor material or without the conductor sagging too low. The conventional way of evaluating a line rating is to input fixed, generally very conservative, meteorological values into standard, internationally used formulae to calculate the summer and winter ratings. But in reality, the real capacity is not static; it varies with the meteorological (weather) conditions - wind speed and direction, ambient temperature, and solar radiation which all contribute to cooling or heating of the transmission line, which affects how much power it can carry. DLR uses real-time measurements from the weather sensors, to calculate the real time rating automatically which is compared to the line current. When the line current is close to the line thermal rating control commands can be sent to hold or lower the power output of
Renewable Energy Sources (RES) such as windfarms or as a last resort trip out the windfarm. This allows optimization of the transmission line capability and power output of the RES. The P341 relay uses the CLIO interfaces for the weather measurements – wind speed, wind direction, ambient temperature and solar radiation.
Functional Overview
The P341 interconnection and DLR protection relay contains a wide variety of protection functions. The protection features are summarized below:
81R
V
50/51/67
50N/51N/67N
PROTECTION FUNCTIONS OVERVIEW
Four rate of change of frequency elements are provided to detect a loss of mains/grid condition or can be used for load shedding applications.
One voltage vector shift element is provided to detect a loss of mains condition.
1
1
Four stages of overcurrent protection are provided which can be selected to be either non-directional, directional forward or directional reverse. Stages 1 and 2 may be set Inverse Definite
Minimum Time (IDMT) or Definite Time (DT); stages 3 and 4 may be set DT only.
1
Four stages of earth fault protection are provided which can be selected to be either non-directional, directional forward or directional reverse. Stages 1 and 2 may be set Inverse Definite
Minimum Time (IDMT) or Definite Time (DT); stages 3 and 4 may be set DT only.
1
P341
P341/EN IT/G74
Product Scope (IT) 1 Introduction
P341/EN IT/G74
67N/67W
64
59N
27
59
81U/O
32R, 32L, 32O
49
46OC
47
50BF
CTS
PROTECTION FUNCTIONS OVERVIEW
One sensitive earth fault element is provided for discriminative earth fault protection of parallel generators. The protection can be selected to be either non-directional, directional forward or directional reverse. Either Zero sequence polarizing is available.
1
The Sensitive Earth Fault element can be configured as an
Icos
, Isin
or VIcos
(Wattmetric) element for application to isolated and compensated networks.
Restricted earth fault is configurable as a high impedance or low impedance element.
1
P341
Residual overvoltage protection is available. The residual voltage can be measured from a broken delta VT, from the secondary winding of an open delta, or can be calculated from the three phase to neutral voltage measurements. Two independent stages of protection are provided for each measured neutral voltage input and also for the calculated value, each stage can be selected as either IDMT or DT.
1
One 2 stage undervoltage protection element, configurable as either phase to phase or phase to neutral measuring is provided.
1
Stage 1 may be selected as either IDMT or DT and stage 2 is
DT only.
One 2 stage overvoltage protection element, configurable as either phase to phase or phase to neutral measuring is provided to back up the automatic voltage regulator. Stage 1 may be selected as either IDMT or DT and stage 2 is DT only.
1
One 4 stage definite time underfrequency and 2 stage definite time overfrequency protection is provided for load shedding and back-up protection of the speed control governor.
1
Two definite time stages of power protection are provided and each stage can be independently configured to operate as
Reverse Power (RP), Over Power (OP) or Low Forward Power
(LFP) protection. The direction of the power measured by the protection can be reversed by selecting the operating mode, generating/motoring. The power protection can be used to provide simple back-up Overload Protection (OP), protection against motoring or loss of mains detection where export of power from the DG is not allowed (RP, generating mode), CB interlocking to prevent overspeeding during machine shutdown
(LFP, generating mode) and loss of load protection (LFP, motoring mode). The relays provide a standard 3 phase power protection element and also a single phase power protection element which can be used with a dedicated metering class CT using the sensitive current input.
1
Thermal overload protection based on I1 and I2 is provided to protect the stator/rotor against overloading due to balanced and unbalanced currents. Both alarm and trip stages are provided.
1
Four definite time stages of negative phase sequence overcurrent protection are provided for remote back-up protection for both phase to earth and phase to phase faults.
Each stage can be selected to be either non-directional, directional forward or directional reverse.
1
One definite time negative phase sequence overvoltage protection element is provided for either a tripping or interlocking function upon detection of unbalanced supply voltages.
1
One 2 stage circuit breaker failure function is provided with a 3 pole initiation input from external protection.
1
Current transformer supervision is provided to prevent maloperation of current dependent protection elements upon loss of a CT input signal.
1
Page (IT) 1-9
(IT) 1 Introduction
Page (IT) 1-10
Product Scope
VTS
49DLR
25
CLIO
PROTECTION FUNCTIONS OVERVIEW
Voltage transformer supervision is provided (1, 2 & 3 phase fuse failure detection) to prevent mal-operation of voltage dependent protection elements upon loss of a VT input signal.
1
P341
Six stages of Dynamic Rating protection which can be applied for load management and protection of overhead lines enabling a larger penetration of Distributed Generation (DG) such as windfarms. The CLIO card is required for the weather sensors – wind speed, wind direction, ambient temperature and solar radiation.
V 7x Soft.
Check synchronizing (2-stage) with advanced system split features and breaker closing compensation time is provided.
The P341 (60TE case) includes a dedicated voltage input for check synchronizing. For the P341 (40TE case) the VNeutral input can be used for neutral voltage protection or check synchronizing.
2
Four analog (or current loop) inputs are provided for transducers
(vibration, tachometers etc. or wind speed, wind direction, ambient temperature and solar radiation for DLR applications).
Each input has a definite time trip and alarm stage and each input can be set to operate for ‘Over’ or ‘Under’ operation. Each input can be independently selected as 0-1/0-10/0-20/4-20 mA.
Option
Four analogue (or current loop) outputs are provided for the analogue measurements in the relay. Each output can be independently selected as 0-1/0-10/0-20/4-20 mA.
Phase rotation - the rotation of the phases ABC or ACB for all 3 phase current and voltage channels can be selected. Also, for pumped storage applications where two phases are swapped the swapping of two phases can be emulated independently for the 3-phase voltage and 3-phase current channels.
1
Programmable LEDs (red) 8
8 to 24
7 to 24
1
Digital inputs (order option)
Output relays (order option)
Front communication port (EIA(RS)232)
Rear communication port (KBUS/EIA(RS)485). The following communications protocols are supported; Courier, MODBUS,
IEC 870-5-103 (VDEW) and DNP3.0.
Rear communication port (Fiber Optic). The following communications protocols are supported; Courier, MODBUS,
IEC 870-5-103 (VDEW) and DNP3.0.
Second rear communication port (EIA(RS)232/EIA(RS)485).
Courier protocol.
Rear IEC 61850 Ethernet communication port.
Rear redundant IEC 61850 Ethernet communication port.
Time synchronization port (IRIG-B)
1
Option
Option
Option
Option
Option
Table 1 - Functional overview
In addition to the functions in Table 1, the P341 supports the following relay management
functions:
Measurement of all instantaneous & integrated values
Circuit breaker control, status & condition monitoring
Trip circuit and coil supervision (using PSL)
Four alternative setting groups
Control
P341/EN IT/G74
Product Scope
3.2
(IT) 1 Introduction
Programmable scheme logic
Programmable allocation of digital inputs and outputs
Sequence of event recording
Comprehensive disturbance recording (waveform capture)
Fault
Fully customizable menu texts
Multi-level password protection
Power-up diagnostics and continuous self-monitoring of relay
Commissioning test facilities
Real time clock/time synchronization - time synchronization possible from IRIG-B input, opto input or communications
Application Overview
V
V
I
SENSITIVE
25
IEC
61850
VTS
27
59
2 nd
Remote
Comm. Port
81O
81U
59N
Remote
Comm. Port
Local
Communication
81R ∆ V Θ 47
Fault Records
Measurements
Disturbance
Record
64
67N
67W
CTS
50
51
67
67N
49 46
32R / 32L
32O 50BF
I
PSL LEDS 49DLR
(For description of
ANSI Code Nos, see the Functions Overview)
Figure 1 - Functional diagram
Binary
Input / Output
CLIO
Always available
Optional
Interconnection
Protection P341
P1669ENc
P341/EN IT/G74 Page (IT) 1-11
(IT) 1 Introduction Product Scope
3.3 Ordering Options
Information required with order
P341 Interconnection Protection Relay P341
Vx Aux rating
24-48 Vdc
48-110 Vdc, 40-100 Vac
110-250 Vdc, 100-240 Vac
I/n/Vn rating
In=1 A/5 A, Vn=100/120 V (40 TE case)
In=1 A/5 A Vn=380/480 V (40 TE case)
In=1 A/5 A, Vn=100/120 V, with Check Sync VT Input
(60 TE case only)
In=1 A/5 A, Vn=380/480 V, with Check Sync VT Input
(60 TE case only)
Hardware options
Nothing
IRIG-B only (Modulated)
Fiber Optic Rear Comms Port
IRIG-B (Modulated) & Fiber Optic Rear Comms Port
Ethernet (100 Mbps)**
2nd Rear Comms. Board*
IRIG-B* (Modulated) plus 2nd Rear Comms Board
Ethernet (100 Mbps) + IRIG-B (Modulated)**
Ethernet (100 Mbps) + IRIG-B (Unmodulated) **
IRIG-B (Unmodulated) **
Redundant Ethernet Self-Healing Ring, 2 multi-mode fiber ports +
(IRIG-B Modulated*)
Redundant Ethernet Self-Healing Ring, 2 multi-mode fiber ports +
IRIG-B* (Unmodulated*)
Redundant Ethernet RSTP, 2 multi-mode fiber ports + IRIG-B*
(Modulated*)
Redundant Ethernet RSTP, 2 multi-mode fiber ports + IRIG-B*
(Unmodulated*)
Redundant Ethernet Dual Homing Star, 2 multi-mode fiber ports +
IRIG-B* (Modulated*)
Redundant Ethernet Dual Homing Star, 2 multi-mode fiber ports +
IRIG-B* (Unmodulated*)
Product specific
Size 40TE Case, No Option (8 Optos + 7 Relays)
Size 40TE Case, 8 Optos + 7 Relays + CLIO *
Size 40TE Case, 16 Optos + 7 Relays*
Size 40TE Case, 8 Optos + 15 Relays*
Size 40TE Case, 12 Optos + 11 Relays*
Size 60TE Case, 16 Optos + 16 Relays**
Size 60TE Case, 16 Optos + 16 Relays + CLIO **
Size 60TE Case, 24 Optos + 16 Relays**
Size 60TE Case, 16 Optos + 24 Relays**
Size 40TE Case, 8 Optos + 11 Relays (4 High Break)
1
2
3
1
2
3
4
1
2
3
4
6
7
8
A
B
C
G
H
J
K
L
M
A
B
C
D
E
F
G
H
J
K
Page (IT) 1-12 P341/EN IT/G74
Product Scope (IT) 1 Introduction
P341 Interconnection Protection Relay P341
Size 60TE Case, 16 Optos + 20 Relays (4 High Break)
Size 60TE Case, 16 Optos + 12 Relays (4 High Break) + CLIO**
Note: HB = High Break
Protocol options
K-Bus
MODBUS
IEC 60870-5-103 (VDEW)
DNP3.0
IEC 61850 + Courier via rear EIA(RS)485 port
Mounting
Panel Mounting
Panel Mounting with Harsh Environment Coating
Language options
Multilingual - English, French, German, Spanish
Multilingual - English, French, German, Russian
Chinese, English or French via HMI, with English or
French only via Communications port**
Software number
Latest software
Latest software + Dynamic Line Rating
Settings File
Default
Customer
Design suffix
Phase 2 CPU and front panel with 2 hotkeys and dual characteristic optos
Improved power supply
Universal Optos, low powered relay outputs
Original release – phase 1
Note Design Suffix
A = Original hardware (48 V opto inputs only, lower contact rating, no I/O expansion available)
C = Universal optos, new high capacity relays, new power supply
J = Phase 2 CPU and front panel with 2 hotkeys and dual characteristic optos
* Not available in design suffix A relays
** Not available in design suffix A,B, C
L
M
1
2
3
4
6
M
P
Note For rack mounting assembled single rack frames and blanking plates are available
0
5
C
36
71
0
A
J
C
B
A
P341/EN IT/G74 Page (IT) 1-13
(IT) 1 Introduction
Notes:
Product Scope
Page (IT) 1-14 P341/EN IT/G74
MiCOM P341 (TD) 2 Technical Data
P341/EN TD/G74
TECHNICAL DATA
CHAPTER 2
Page (TD) 2-1
(TD) 2 Technical Data
Hardware Suffix:
Software Version:
Connection Diagrams:
J
36 and 71 (with DLR)
10P341xx (xx = 01 to 12)
MiCOM P341
Page (TD) 2-2 P341/EN TD/G74
Contents (TD) 2 Technical Data
CONTENTS
Page (TD) 2-
Mechanical Specifications
Terminals
Ratings
Power Supply
Output Contacts
Environmental Conditions
Type Tests
ElectroMagnetic Compatibility (EMC)
EU Directives
Mechanical Robustness
13
14
14
Third Party Compliances 14
Protection Functions 15
Sensitive/Low Forward/Overpower
Directional/Non-Directional Overcurrent
Negative Phase Sequence Overcurrent
Directional/Non-Directional Earth Fault
Transient Overreach and Overshoot
Neutral Displacement/Residual Overvoltage
Rate of Change of Frequency ‘df/dt’ df/dt 16
7
7
9
9
11
12
12
Supervisory Functions
Voltage Transformer Supervision
Current Transformer Supervision
17
P341/EN TD/G74 Page (TD) 2-3
(TD) 2 Technical Data Contents
Plant Supervision
CB State Monitoring Control and Condition Monitoring
Measurements and Recording Facilities 19
Current Loop Input and Outputs 19
Event, Fault & Maintenance Records
Settings, Measurements and Records List 20
Circuit Breaker Control (CB Control):
Sequence of Event Recorder (Record Control)
Oscillography (Disturbance Recorder)
Measured Operating Data (Measure’t Setup) 22
Optional Additional Second Rear Communication (Rear Port2 (RP2))
Circuit Breaker Condition Monitoring (CB Monitor Setup)
Opto Coupled Binary Inputs (Opto Config)
Control Inputs into PSL (Ctrl I/P Config)
Control Input User Labels (Ctrl I/P Labels)
Protection Functions
Sensitive/Reverse/Low Forward/Overpower
Phase Overcurrent (Overcurrent)
23
18
Page (TD) 2-4 P341/EN TD/G74
Contents (TD) 2 Technical Data
Inverse Time (IDMT) Characteristic
Restricted Earth Fault (High Impedance)
Voltage Protection
Frequency Protection 29
28
Supervisory Functions
Voltage Transformer Supervison
Current Transformer Supervision
System Checks Voltage Monitors
Plant Supervision
CB State Monitoring Control and Condition Monitoring
29
30
Dynamic Rating
Measurements List
Circuit Breaker Monitoring Statistics
33
31
P341/EN TD/G74 Page (TD) 2-5
(TD) 2 Technical Data
Notes:
Contents
Page (TD) 2-6 P341/EN TD/G74
Mechanical Specifications (TD) 2 Technical Data
MECHANICAL SPECIFICATIONS
Design
Modular platform relay, P341 in 40 TE or 60 TE case.
Mounting is front of panel flush mounting, or 19“ rack mounted with rack frame (ordering options).
Enclosure protection
Per IEC 60529: 1992:
IP 52 Protection (front panel) against dust and dripping water,
IP 50 Protection for rear and sides of the case, against dust,
IP 10 Protection Product safety protection for the rear due to live connections on the terminal block.
Weight
P341 (40 TE) :7 kg
P341 (60 TE) :9.2 kg
TERMINALS
AC current and voltage measuring inputs
Located on heavy duty (black) terminal block:
Threaded M4 terminals, for ring lug connection.
CT inputs have integral safety shorting, on removal of the terminal block.
General input/output terminals
For power supply, opto inputs, output contacts and
RP1 rear communications.
Located on general purpose (grey) blocks:
Threaded M4 terminals, for ring lug connection.
Case protective earth connection
Two rear stud connections, threaded M4.
Must be earthed (grounded) for safety, minimum earth wire size 2.5 mm2.
Front port serial PC interface
EIA(RS)232 DCE, 9 pin D-type female connector
Socket SK1.
Courier protocol for interface to S1 Studio software.
Isolation to ELV (extra low voltage) level.
Maximum cable length 15 m.
Front download/monitor port
EIA(RS)232, 25 pin D-type female connector Socket
SK2.
For firmware and menu text downloads.
Isolation to ELV level.
Rear communications port (RP1)
EIA(RS)485 signal levels, two wire connections located on general purpose block, M4 screw.
For screened twisted pair cable, multidrop, 1000 m max.
For K-Bus, IEC-60870-5-103, MODBUS or DNP3.0 protocol (ordering options).
Isolation to SELV (safety extra low low voltage) level.
Optional rear fiber connection for
SCADA/DCS
BFOC 2.5 -(ST
®
)-interface for glass fiber, as per
IEC 874-10.
850 nm short-haul fibers, one Tx and one Rx. For
Courier, IEC-60870-5-103, MODBUS or DNP3.0
(Ordering options).
Optional second rear communications port
(RP2)
EIA(RS)232, 9 pin D-type female connector, socket
SK4.
Courier protocol: K-Bus, EIA(RS)232, or EIA(RS)485 connection.
Isolation to SELV level.
Optional rear IRIG-B interface modulated or unmodulated
BNC plug
Isolation to SELV level.
50 ohm coaxial cable.
Optional Rear Ethernet Connection for IEC 61850
P341/EN TD/G74 Page (TD) 2-7
(TD) 2 Technical Data Terminals
Optional Rear Ethernet Connection for IEC
61850
10BaseT/100BaseTX Communications
Interface in accordance with IEEE802.3 and
IEC 61850
Isolation:
Connector type:
1.5 kV
RJ45
Cable type: Screened Twisted Pair (STP)
Max. cable length: 100 m
100 Base FX Interface
Interface in accordance with IEEE802.3 and
IEC 61850
Wavelength:
Fiber:
62.5/125
Connector type:
1300 nm multi-mode 50/125 µm or
µm
BFOC 2.5 - (ST ® )
Optional Rear Redundant Ethernet
Connection for IEC 61850
100 Base FX Interface
Interface in accordance with IEEE802.3 and
IEC 61850
Wavelength:
Fiber:
1300 nm multi-mode 50/125 µm or
62.5/125
Connector style: BFOC 2.5 -(ST
®
)
Transmitter Optical Characteristics 100 Base
FX Interface
Parameter Sym Min Typ Max Unit
Output Optical
Power BOL
62.5/125 µm,
NA = 0.275 Fiber
EOL
PO
-19
-20
Output Optical
Power BOL
50/125 µm,
NA = 0.20 Fiber
EOL
PO
-22.5
-23.5
Optical Extinction
Ratio
10
-10
Output Optical
Power at Logic “0”
State
PO
(“0”)
BOL - Beginning of life EOL - End of life
% dB
Receiver Optical Characteristics 100 Base FX
Interface
Parameter Sym Min Typ Max Unit
Input Optical Power
Minimum at Window
Edge
PIN Min.
(W)
Input Optical Power
Minimum at Eye
Center
PIN Min.
(C)
Input Optical Power
Maximum
PIN Max. -14 -11.8 dBm avg.
Fiber Defect Connector (Watchdog Relay) –
Redundant Ethernet Board
Connector (3 terminals):
Rated voltage:
Continuous current:
2 NC contacts
250 V
5 A
Short-duration current:
Breaking capacity:
30 A for 3 s
DC: 50 W resistive
DC: 25 W inductive (L/R = 40 ms)
AC: 1500 VA resistive (cos = unity)
AC: 1500 VA inductive (cos = 0.5)
Subject to maxima of 5 A and 250 V
Page (TD) 2-8 P341/EN TD/G74
Ratings (TD) 2 Technical Data
RATINGS
AC measuring inputs
Nominal frequency: 50 and 60 Hz (settable)
Operating range: 40 to 70 Hz
AC current
Nominal current (In): 1 and 5 A dual rated.
(1 A and 5 A inputs use different transformer tap connections, check correct terminals are wired).
Nominal burden:
<0.04 VA at In, <40 m (0-30 In) In = 1 A
<0.01 VA at In, <8 m (0-30 In) In = 5 A
Thermal withstand: continuous 4 In for 10 s: 30 In for 1 s; 100 In
Standard: linear to 64 In (non-offset AC current).
Sensitive: linear to 2 In (non-offset AC current).
AC voltage
Nominal voltage (Vn): 100 to 120 V or 380 to 480 V phase-phase.
Nominal burden per phase: < 0.02 VA at
110/ 3 V or 440/ 3 V
Thermal withstand: continuous 2 Vn
10
Linear to 200 V (100 V/120 V), 800 V (380/480 V).
POWER SUPPLY
Auxiliary voltage (Vx)
Three ordering options:
(i) Vx: 24 to 48 Vdc
(ii) Vx: 48 to 110 Vdc, and 40 to 100 Vac (rms)
(iii) Vx: 110 to 250 Vdc, and 100 to 240 Vac (rms)
Operating range
(i) 19 to 65 V (dc only for this variant)
(ii) 37 to 150 V (dc), 32 to 110 V (ac)
(iii) 87 to 300 V (dc), 80 to 265 V (ac).
With a tolerable ac ripple of up to 12% for a dc supply, per IEC 60255-11: 1979.
Nominal burden
Quiescent burden: 11 W or 24 VA. (Extra 1.25 W when fitted with second rear communications board).
Additions for energized binary inputs/outputs:
Per opto input: 0.09 W (24 to 54 V),
0.12 W (110/125 V),
0.19 W (220/250 V).
Per energized output relay: 0.13 W
Power-up time
Time to power up < 11 s.
Power supply interruption
3 power supply options:
(i) Vx: 24 to 48 V dc
(ii) Vx: 48 to 110 V dc, 40 to 100 V ac (rms)
(iii) (i) Vx: 110 to 250 V dc, 100 to 240 V ac (rms)
Per IEC 60255-11: 2008
The relay will withstand a 100% interruption in the DC supply without de-energizing as follows:
(i) Vx: 24 to 48 V dc
Quescent / half load: 20 ms at 24 V
50 ms at 36 V
100
Maximum loading: 20 ms at 24 V
50 ms at 36 V
100
(ii) Vx: 48 to 110 V dc
Quescent / half load: 20 ms at 36 V
Maximum loading:
50 ms at 60 V
100
200 ms at 110 V
20 ms at 36 V
100
50 ms at 60 V at
200 ms at 110 V
(iii) (i) Vx: 110 to 250 V dc
Quescent / half load: 50 ms at 110 V
100 ms at 160 V
Maximum loading:
200 ms at 210 V
20 ms at 85 V
50
100 ms at 135 V
200 ms at 174 V
P341/EN TD/G74 Page (TD) 2-9
(TD) 2 Technical Data Power Supply
Per IEC 60255-11: 2008:
The relay will withstand an interruption in the AC supply without de-energizing as follows:
(ii) Vx = 40 to 100 V ac
Quescent / half load
50 ms at 27 V for 100% voltage dip
Maximum loading:
10 ms at 27 V for 100% voltage dip
(iii) Vx = 100 to 240 V ac
Quescent / half load
50 ms at 80 V for 100% voltage dip
Maximum loading:
50 ms at 80 V for 100% voltage dip
Maximum loading = all digital inputs/outputs energized
Quescent or 1/2 loading = 1/2 of all digital inputs/outputs energized
Battery backup
Front panel mounted
Type ½ AA, 3.6 V Lithium Thionyl Chloride Battery
(SAFT advanced battery reference LS14250)
Battery life (assuming relay energized for 90% time)
>10 years
Field voltage output
Regulated 48 Vdc
Current limited at 112 mA maximum output
Operating range 40 to 60 V
Digital (“Opto”) inputs
Universal opto inputs with programmable voltage thresholds (24/27, 30/34, 48/54, 110/125, 220/220 V).
May be energized from the 48 V field voltage, or the external battery supply.
Rated nominal voltage: 24 to 250 Vdc
Operating range: 19 to 265 Vdc
Withstand: 300 Vdc, 300 Vrms.
Nominal pick-up and reset thresholds:
Nominal battery 24/27: 60 - 80% DO/PU
(logic 0) <16.2 (logic 1) >19.2
Nominal battery 24/27: 50 - 70% DO/PU
(logic 0) <12.0 (logic 1) >16.8
Nominal battery 30/34: 60 - 80% DO/PU
(logic 0) <20.4 (logic 1) >24.0
Nominal battery 30/34: 50 - 70% DO/PU
(logic 0) <15.0 (logic 1) >21.0
Nominal battery 48/54: 60 - 80% DO/PU
(logic 0) <32.4 (logic 1) >38.4
Nominal battery 48/54: 50 - 70% DO/PU
(logic 0) <24.0 (logic 1) >33.6
Nominal battery 110/125: 60 - 80% DO/PU
(logic 0) <75.0 (logic 1) >88.0
Nominal battery 110/125: 50 - 70% DO/PU
(logic 0) <55.0 (logic 1) >77.0
Nominal battery 220/250: 60 - 80% DO/PU
(logic 0) <150.0 (logic 1) >176.0
Nominal battery 220/250: 50 - 70% DO/PU
(logic 0) <110 (logic 1) >154
Recognition time:
<2 ms with long filter removed,
<12 ms with half cycle ac immunity filter on
Page (TD) 2-10 P341/EN TD/G74
Output Contacts (TD) 2 Technical Data
OUTPUT CONTACTS
Standard Contacts
General purpose relay outputs for signaling, tripping and alarming:
Continuous Carry Ratings (Not Switched):
Maximum continuous current: 10 A (UL: 8 A)
Short duration withstand carry: 30 A for 3 s
250
Rated voltage:
Make & Break Capacity:
DC: 50 W resistive
300 V
DC: 62.5 W inductive (L/R = 50 ms)
AC: 2500 VA resistive (cos = unity)
AC: 2500 VA inductive (cos = 0.7)
Make, Carry:
30 A for 3 secs, dc resistive, 10,000 operations
(subject to the above limits of make / break capacity and rated voltage)
Make, Carry & Break:
30 A for 200 ms, ac resistive, 2,000 operations
(subject to the above limits of make / break capacity & rated voltage)
4 A for 1.5 secs, dc resistive, 10,000 operations
(subject to the above limits of make / break capacity & rated voltage)
0.5 A for 1 sec, dc inductive, 10,000 operations
(subject to the above limits of make / break capacity & rated voltage)
10 A for 1.5 secs, ac resistive / inductive,
10,000 operations (subject to the above limits of make / break capacity & rated voltage)
Durability:
Loaded contact: 10 000 operations minimum,
Unloaded contact: 100 000 operations minimum.
Operate Time Less than 5 ms
Reset Time Less than 5 ms
High Break Contacts
Continuous Carry Ratings (Not Switched):
Maximum continuous current: 10 A
Short duration withstand carry: 30 A for 3 s
250
Rated voltage: 300 V
Make & Break Capacity:
DC: 7500
DC:
Make, Carry:
2500 W inductive (L/R = 50 ms)
30 A for 3 secs, dc resistive, 10,000 operations
(subject to the above limits of make / break capacity & rated voltage)
Make, Carry & Break:
30 A for 3 secs, dc resistive, 5,000 operations
(subject to the above limits of make / break capacity & rated voltage)
30 A for 200 ms, dc resistive, 10,000 operations
(subject to the above limits of make / break capacity & rated voltage)
10 A (*), dc inductive, 10,000 operations
(subject to the above limits of make / break capacity & rated voltage)
*Typical for repetitive shots – 2 minutes idle for thermal dissipation
Voltage Current L/R
No of shots in 1 sec
65 V 10 A 40 ms 5
150 V
250 V
10 A
10 A
250 V 10 A
MOV protection:
Durability:
Loaded contact:
Unloaded contact:
Operate Time:
Reset Time:
40 ms
40 ms
4
2
20 ms 4
Max Voltage 330 V dc
10 000 operations minimum,
100 000 operations minimum.
Less than 0.2 ms
Less than 8 ms
Watchdog Contacts
Non-programmable contacts for relay healthy/relay fail indication:
Breaking capacity:
DC: 30 W resistive
DC: 15 W inductive (L/R = 40 ms)
AC: 375 VA inductive (cos = 0.7)
IRIG-B Interface (Modulated)
External clock synchronization per IRIG standard 200-
98, format B12x
Input impedance 6 k at 1000 Hz
Modulation ratio:
Input signal, peak-peak:
3:1 to 6:1
200 mV to 20 V
IRIG-B 00X Interface (Demodulated)
External clock synchronization per IRIG standard 200-
98, format B00X.
Input signal TTL level
Input impedance at dc 10 k
P341/EN TD/G74 Page (TD) 2-11
(TD) 2 Technical Data Environmental Conditions
ENVIRONMENTAL CONDITIONS
Ambient Temperature Range
Per IEC 60255-6: 1988:
Operating
-25°C to +55°C (or -13°F to +131°F)
Storage and transit:
-25°C to +70°C (or -13°F to +158°F)
Tested as per
IEC 60068-2-1: 2007
-25°C storage (96 hours)
-40°C operation (96 hours)
IEC 60068-2-2: 2007
+85°C (96
+85°C operation (96 hours)
Ambient Humidity Range
Per IEC 60068-2-3: 1969:
56 days at 93% relative humidity and +40 °C
Per IEC 60068-2-30: 1980
Damp heat cyclic, six (12 + 12) hour cycles,
93% RH, +25 to +55 °C
Corrosive Environments
(For relays with harsh environment coating of PCBs)
Per IEC 60068-2-60: 1995, Part 2, Test Ke, Method
(class) 3 - Industrial corrosive environment/poor environmental control, mixed gas flow test.
21 days at 75% relative humidity and +25 o exposure to elevated concentrations of H
2
(100 ppb), NO
2
(200 ppb), Cl
Per IEC 60068-2-52 Salt mist
2
(20 ppb).
C
S
(7 days)
Per IEC 60068-2-43 for H
2
S
(21 days), 15 ppm
Per IEC 60068-2-42 for SO
2
(21 days), 25 ppm
TYPE TESTS
Insulation
Per IEC 60255-27: 2005
Insulation resistance > 100 M at 500 Vdc
(Using only electronic/brushless insulation tester).
Creepage Distances and Clearances
IEC 60255-27: 2005
Pollution degree 3,
Overvoltage category III,
Impulse test voltage 5 kV.
High Voltage (Dielectric) Withstand
(i) Per IEC 60255-27: 2005, 2 kV rms
AC, 1 minute:
Between all independent circuits.
Between independent circuits and protective
(earth) conductor terminal.
1 kV rms AC for 1 minute, across open watchdog contacts.
1 kV rms AC for 1 minute, across open contacts of changeover output relays.
1 kV rms AC for 1 minute for all D-type
EIA(RS)232/EIA(RS)485 ports between the communications port terminals and protective
(earth) conductor terminal.
(ii) Per ANSI/IEEE C37.90-1989 (reaffirmed 1994):
1.5 kV rms AC for 1 minute, across open contacts of normally open output relays.
1 kV rms AC for 1 minute, across open watchdog contacts.
1 kV rms AC for 1 minute, across open contacts of changeover output relays.
Impulse Voltage Withstand Test
Per IEC 60255-27: 2005
Front time: 1.2 µs, Time to half-value: 50 µs,
Peak value: 5 kV, 0.5 J
Between all independent circuits.
Between all independent circuits and protective
(earth) conductor terminal.
Between the terminals of independent circuits.
EIA(RS)232 & EIA(RS)485 ports and normally open contacts of output relays excepted.
Page (TD) 2-12 P341/EN TD/G74
ElectroMagnetic Compatibility (EMC) (TD) 2 Technical Data
ELECTROMAGNETIC
COMPATIBILITY (EMC)
1 MHz Burst High Frequency Disturbance
Test
Per IEC 60255-22-1: 1988, Class III,
Common-mode test voltage: 2.5 kV,
Differential test voltage: 1.0 kV,
Test duration: 2 s, Source impedance: 200
(EIA(RS)232 ports excepted).
100 kHz Damped Oscillatory Test
Per EN61000-4-18: 2007: Level 3
Common mode test voltage: 2.5 kV
Differential mode test voltage: 1 kV
Immunity to Electrostatic Discharge
Per IEC 60255-22-2: 1996, Class 4,
15 kV discharge in air to user interface, display, communication port and exposed metalwork.
6 kV point contact discharge to any part of the front of the product.
Electrical Fast Transient or Burst
Requirements
Per IEC 60255-22-4: 2002 and
EN61000-4-4:2004. Test severity Class III and IV:
Amplitude: 2 kV, burst frequency 5 kHz
(Class III),
Amplitude: 4 kV, burst frequency 2.5 kHz (Class IV).
Applied directly to auxiliary supply, and applied to all other inputs. (EIA(RS)232 ports excepted).
Amplitude: 4 kV, burst frequency 5 kHz
(Class IV) applied directly to auxiliary.
Surge Withstand Capability
Per IEEE/ANSI C37.90.1: 2002:
4 kV fast transient and 2.5 kV oscillatory applied directly across each output contact, optically isolated input, and power supply circuit.
4 kV fast transient and 2.5 kV oscillatory applied common mode to communications, IRIG-B.
Surge immunity test
(EIA(RS)232 ports excepted).
Per IEC 61000-4-5: 2005 Level 4,
Time to half-value: 1.2 / 50 µs,
Amplitude: 4 kV between all groups and protective (earth) conductor terminal.
Amplitude: 2 kV between terminals of each group.
Immunity to Radiated Electromagnetic Energy
Per IEC 60255-22-3: 2000, Class III:
Test field strength, frequency band 80 to 1000 MHz:
10 V/m,
Test using AM: 1 kHz / 80%,
Spot tests at 80, 160, 450, 900 MHz
Per IEEE/ANSI C37.90.2: 2004:
80 MHz to 1000 MHz, 1 kHz 80% AM and AM pulsed modulated.
Field strength of 35 V/m.
Radiated Immunity from Digital
Communications
Per EN61000-4-3: 2002, Level 4:
Test field strength, frequency band 800 to 960 MHz, and 1.4 to 2.0 GHz:
30 V/m,
Test using AM: 1 kHz/80%.
Radiated Immunity from Digital Radio Telephones
Per IEC 61000-4-3: 2002:
10 V/m, 900 MHz and 1.89 GHz.
Immunity to Conducted Disturbances Induced by Radio Frequency Fields
Per IEC 61000-4-6: 1996, Level 3,
Disturbing test voltage: 10 V.
Power Frequency Magnetic Field Immunity
Per IEC 61000-4-8: 1994, Level 5,
100 A/m applied continuously,
1000 A/m applied for 3 s.
Per IEC 61000-4-9: 1993, Level 5,
1000 A/m applied in all planes.
Per IEC 61000-4-10: 1993, Level 5,
100 A/m applied in all planes at 100 kHz/
1 MHz with a burst duration of 2 s.
Conducted Emissions
Per EN 55022: 1998 Class A:
0.15 - 0.5 MHz, 79 dB V (quasi peak)
66 dB V (average)
0.5 - 30 MHz, 73 dB V (quasi peak)
60 dB V (average).
Radiated Emissions
Per EN 55022: 1998 Class A:
30 - 230 MHz, 40 d B V/m at 10 m measurement distance
230 - 1 GHz, 47 dB V/m at 10 m measurement distance.
P341/EN TD/G74 Page (TD) 2-13
(TD) 2 Technical Data EU Directives
EU DIRECTIVES
EMC compliance
Per 2004/108/EC:
Compliance to the European Commission Directive on
EMC is demonstrated using a Technical File. Product
Specific Standards were used to establish conformity:
EN50263: 2000
Product safety
Per 2006/95/EC:
Compliance to the European Commission Low
Voltage Directive. (LVD) is demonstrated using a
Technical File.
A product specific standard was used to establish conformity.
EN 60255-27: 2005
R&TTE compliance
Radio and Telecommunications Terminal Equipment
(R & TTE) directive 99/5/EC.
Compliance demonstrated by compliance to both the
EMC directive and the Low voltage directive, down to zero volts.
Applicable to rear communications ports.
ATEX compliance
ATEX Potentially Explosive Atmospheres directive
94/9/EC, for equipment.
The equipment is compliant with Article 1(2) of
European directive 94/9/EC.
It is approved for operation outside an ATEX hazardous area. It is however approved for connection to Increased Safety, “Ex e”, motors with rated ATEX protection, Equipment Category 2, to ensure their safe operation in gas Zones 1 and 2 hazardous areas.
Caution Equipment with this marking is not itself suitable for operation within a potentially explosive atmosphere.
Compliance demonstrated by Notified Body certificates of compliance.
MECHANICAL ROBUSTNESS
Vibration test
Per IEC 60255-21-1: 1996:
Response Class 2
Endurance Class 2
Shock and bump
Per IEC 60255-21-2: 1996:
Shock response Class 2
Shock withstand Class 1
Bump Class 1
Seismic test
Per IEC 60255-21-3: 1995: Class 2
THIRD PARTY COMPLIANCES
Underwriters laboratory (UL)
File Number: E202519
Original Issue Date: 05-10-2002
(Complies with Canadian and US requirements).
Energy Networks Association (ENA)
Certificate Number: 104 Issue 2
Assessment Date: 16-04-2004
Page (TD) 2-14 P341/EN TD/G74
Protection Functions (TD) 2 Technical Data
PROTECTION FUNCTIONS
Reverse/Low Forward/Overpower
Accuracy
Pick-up: Setting 10%
Reverse/Over Power Drop-off:
Low forward power Drop-off: of 10% of 10%
Angle variation Pick-up: pick-up 2 degree
Angle variation Drop-off: drop-off 2.5 degree
Operating time: 2% or 50 ms whichever is greater
Repeatability: <5%
Disengagement time: tRESET:
<50 ms
5%
Instantaneous operating time: <50 ms
Sensitive/Low Forward/Overpower
Accuracy
Pick-up: Setting 10%
Reverse/Over power Drop-off: 0.9 of setting 10%
Low forward power Drop-off:
1.1 of Setting 10%
Angle variation Pick-up:
Expected pick-up angle 2 degree
Angle variation Drop-off:
Expected drop-off angle 2.5% degree
Operating time: 2% or 50 ms whichever is greater
Repeatability:
Disengagement time: tRESET:
<5%
<50 ms
5%
Instantaneous operating time: <50 ms
Directional/Non-Directional Overcurrent
Accuracy
Pick-up:
Drop-off:
Setting 5%
0.95 x Setting 5%
Minimum trip level (IDMT): 1.05 x Setting 5%
IDMT characteristic shape: 5% or 40 ms whichever is greater*
IEEE reset: 5% or 50 ms whichever is greater
DT operation: 2% or 50 ms whichever is greater
DT Reset: 5%
Directional accuracy (RCA 90 ): 2 hysteresis 2
Characteristic UK: IEC 6025-3…1998
Characteristic US: IEEE C37.112…1996
* Under reference conditions
Negative Phase Sequence Overcurrent
Accuracy
I2>Pick-up: Setting 5%
I2> Drop-off: 0.95 x Setting 5%
Vpol Pick-up: Setting 5%
Vpol Drop-off: 0.95 x Setting 5%
DT operation: 2% or 60 ms whichever is greater
Disengagement time: <35 ms
Directional accuracy (RCA 90 ): 2 hysteresis <1%
Repeatability (operating times): <10 ms
Thermal Overload
Accuracy
Setting accuracy:
Reset:
5%
95% of thermal setting
Thermal alarm Pick-up: Calculated trip time 5%
5%
Thermal overload Pick-up: Calculated trip time 5%
Cooling time accuracy: 6% of theoretical
Repeatability: <2.5%
Directional/Non-Directional Earth Fault
Earth fault accuracy
Pick-up:
Drop-off:
Setting 5%
>0.85 x Setting 5%
IDMT trip level elements: 1.05 x Setting 5%
IDMT characteristic shape: 5% or 40 ms whichever is greater*
IEEE reset: 5% or 40 ms whichever is greater
DT operation: 2% or 50 ms whichever is greater
DT reset:
Repeatability:
5%
5%
SEF accuracy
Pick-up:
Drop-off:
Setting 5%
0.95 x Setting 5%
IDMT trip level elements: 1.05 x Setting 5%
IDMT characteristic shape: 5% or 40 ms whichever is greater*
IEEE reset: 7.5% or 60 ms whichever is greater
DT operation: 2% or 50 ms whichever is greater
DT reset:
Repeatability:
5%
5%
Wattmetric SEF accuracy
P = 0 W Pick-up:
P > 0 W Pick-up:
P = 0 W Drop-off:
P > 0 W Drop-off:
Repeatability:
ISEF> 5%
P> 5%
(0.95 x ISEF>) 5%
0.9 x P>
5%
5%
Boundary accuracy: 5% with 1 hysteresis
P341/EN TD/G74 Page (TD) 2-15
(TD) 2 Technical Data Protection Functions
Zero sequence polarizing quantities accuracy
Operating boundary Pick-up: 2 of RCA 90
Hysteresis: <3
Vnpol Pick-up:
Vnpol Drop-off:
Setting 10%
0.9 x Setting or 0.7 V
(whichever is greater) 10%
Negative sequence polarizing quantities accuracy
Operating boundary Pick-up: 2 of RCA 90
Hysteresis: <3
V2pol Pick-up: Setting 10%
V2pol Drop-off:
10%
0.9 x Setting or
0.7 V (whichever is greater)
I2pol Pick-up:
I2pol Drop-off:
Setting 10%
0.9 x Setting 10%
Restricted Earth Fault
Accuracy
Pick-up:
Drop-off: differential current
Setting formula
High impedance Pick-up:
High impedance operating time:
5%
0.80 (or better) of calculated
Setting
<30 ms
5%
Transient Overreach and Overshoot
Accuracy
Additional tolerance X/R ratios:
5% over the X/R ratio of 1…90
Overshoot of overcurrent elements: <40 ms
Disengagement time: <60 ms (65 ms SEF)
Neutral Displacement/Residual
Overvoltage
Accuracy
DT/IDMT Pick-up:
Drop-off:
Setting 5%
0.95 x Setting
IDMT characteristic shape:
5%
5% or 55 ms whichever is greater
DT operation: 2% or 55 ms whichever is greater
Instantaneous operation
Reset:
Repeatability:
<55 ms
<35
<1%
Rate of Change of Frequency ‘df/dt’
Accuracy
Fixed Window
Pick-up: Setting ±0.05 Hz/s or ±3% whichever is greater
Repeatability: <5%
Rolling Window
Pick-up: Setting ±0.01 Hz/s or ±3% whichever is greater
Repeatability: <5%
Pick-up: Setting ±2% or ±0.08 Hz whichever is greater
DT Operation
Fixed Window
Setting ±2% or ±(40+20*X*Y)ms
Repeatability: <5%
Rolling Window
Setting ±2% or ±(60+20*X+5*Y)ms
Note X = average cycles, Y = Iterations
Repeatability: <20%
df/dt
Accuracy
Pick-up: Setting 0.5 Hz/s
Operating time: 2% or 160 ms whichever is greater
Lower/Upper dead band operating time:
2% or 160 ms whichever is greater
Operation over dead band:
2% or 170 ms whichever is greater
Repeatability: <5%
Voltage Vector Shift
Accuracy
0.5
Trip pulse time: 500 ms 2%
Reconnect Delay
Accuracy
Operating time: 2% or 50 ms whichever is greater
Undervoltage
Accuracy
DT Pick-up: Setting 5%
IDMT Pick-up: 0.95 x Setting 5%
Drop-off: 1.05 x Setting 5%
IDMT characteristic shape:
2% or 50 ms whichever is greater
DT operation: 2% or 50 ms whichever is greater
Reset: <7 ms
Repeatability: <1%
Page (TD) 2-16 P341/EN TD/G74
Supervisory Functions (TD) 2 Technical Data
Overvoltage
Accuracy
DT Pick-up: Setting 5%
IDMT Pick-up: Setting 5%
Drop-off: 0.98 x Setting 5%
IDMT characteristic shape:
2% or 50 ms whichever is greater
DT operation: 2% or 50 ms whichever is greater
Reset: <75 ms
NPS Overvoltage
Accuracy
Pick-up:
Drop-off:
Setting 5%
0.95 x Setting 5%
Repeatability (operating threshold): <1%
DT operation: 2% or 65 ms whichever is greater
Instantaneous operation:
Instantaneous operation:
Disengagement time:
<60 ms
(accelerated): <45 ms
<35 ms
Repeatability (operating times): <10 ms
Underfrequency
Accuracy
Pick-up: Setting 0.01 Hz
Drop-off: (Setting +0.025 HZ) 0.01 Hz
DT operation: 2% or 50 ms whichever is greater*
* The operating will also include a time for the relay to frequency track 20 Hz/ second).
Overfrequency
Accuracy
Pick-up: Setting 0.01 Hz
Drop-off: (Setting -0.025 Hz) 0.01 Hz
DT operation: 2% or 50 ms whichever is greater *
* The operating will also include a time for the relay to frequency track 20 Hz/ second).
CB Fail
Timer accuracy
Timers: 2% or 40 ms whichever is greater
Reset time: <30 ms
Undercurrent accuracy
Pick-up: 10%
Operating time: < 12 ms (Typical <10 ms)
Reset: < 15 ms (Typical < 10 ms)
SUPERVISORY FUNCTIONS
Voltage Transformer Supervision
Accuracy
Fast block operation: <25 ms
Fast block reset:
Time delay:
<30 ms
Setting 2% or
20 ms whichever is greater
Current Transformer Supervision
Accuracy
IN > Pick-up: Setting 5%
VN < Pick-up: Setting 5%
IN > Drop-off: 0.9 x Setting 5%
VN < Drop-off: (1.05 x Setting) 5% or
1 V whichever is greater
CTS block operation: < 1 cycle
CTS reset: < 35 ms
System Checks
Voltage Monitors
Accuracy
Gen/Bus Voltage Monitors
Over/Live/Diff voltage:
Pick-up:
Drop-off: setting ±3% or
0.1 V whichever is greater
(0.98 x Setting) ±3% or
0.1 V whichever is greater
Repeatability: <1%
Bus Under/Dead voltage:
Pick-up: Setting ±3% or
0.1 V whichever is greater
Drop-off: (1.02 x Setting) ±3% or
0.1 V whichever is greater
Repeatability: <1%
Generator underfrequency
Pick-up: Setting
Drop-off: (Setting +0.1 Hz) ±0.01 Hz
Repeatability: <1%
Generator overfrequency
Drop-off: (Setting -0.1 Hz) ±0.01 Hz
Repeatability: <1%
P341/EN TD/G74 Page (TD) 2-17
(TD) 2 Technical Data
Check Synch
Accuracy
CS1
CS1 Phase Angle:
±1°
±1°
Repeatability: <1%
CS1 Slip Freq:
Pick-up:
Drop-off:
Setting ±0.01 Hz
(0.95 x Setting) ±0.01 Hz
Repeatability: <1%
CS1 Slip Timer:
Timers: setting ±1% or 40 ms whichever is greater
Reset time: < 30 ms
Repeatability: <10ms
CS2
CS2 Phase Angle:
±1°
±1°
Repeatability: <1%
CS2 Slip Freq:
Pick-up: Setting ±0.01 Hz
Drop-off: (0.95 x Setting) ±0.01 Hz
Repeatability: <1%
CS2 Slip Timer:
Timer: setting ±1% or 40 ms whichever is greater
Reset time: < 30 ms
Repeatability: <1%
CS2 Advanced CB Compensation Phase
Angle:
Pick-up: 0°±1°
Drop-off: 2°±1°
Repeatability: <1%
CS2 CB Closing Timer
Timer: <30 ms ms
System Split
Accuracy
SS Phase Angle:
±1°
±1°
Repeatability: <1%
SS Undervoltage:
Pick-up: Setting
Drop-off: 1.02 x Setting
Repeatability: <1%
SS Timer:
Timers: setting ±1% or 40 ms whichever is greater
Reset time: <30 ms ms
Plant Supervision
PLANT SUPERVISION
CB State Monitoring Control and
Condition Monitoring
Accuracy
Timers: 2% or 20 ms whichever is greater
Broken current accuracy: 5%
Dynamic Rating
Accuracy
DLR I> Pick-up: Setting 2%
DLR I> Drop-off: (0.7 to 0.99) x Setting
<2 s
DT operation: 2% or 2 s whichever is greater
2%
Instantaneous operation:
Disengagement time: <1 s
Repeatability (operating times): <2 s Repeatability
(PU and DO): <3%
Programmable Scheme Logic
Accuracy
Output conditioner timer:
Setting 2% or 50 ms whichever is greater
Dwell conditioner timer:
Setting
Pulse conditioner timer:
Setting
Page (TD) 2-18 P341/EN TD/G74
Measurements and Recording Facilities (TD) 2 Technical Data
MEASUREMENTS AND
RECORDING FACILITIES
Measurements
Accuracy
Current:
Voltage:
In:
0.05…3 In: 1% of reading
0.05…2 Vn: 5% of reading
Power (W): 0.2…2 Vn, 0.05…3
5% of reading at unity power factor
Reactive Power (VArs): 0.2…2 Vn, 0.05…3
In: 5% of reading at zero power factor
Apparent Power (VA): 0.2…2 Vn, 0.05…3
In: 5% of reading
Energy (Wh): 0.2…2 Vn, 0.2…3
In: 5% of reading at zero power factor
Energy (Varh): 0.2…2 Vn, 0.2…3
In: 5% of reading at zero power factor
Phase accuracy:
Frequency:
0 …360: 5%
40…70 Hz: 0.025 Hz
IRIG-B and Real Time Clock
Performance
Year 2000: Compliant
Real time accuracy: < 1 second / day
Features
Real time 24 hour clock settable in hours, minutes and seconds
Calendar settable from January 1994 to December
2092
Clock and calendar maintained via battery after loss of auxiliary supply
Internal clock synchronization using IRIG-B Interface for IRIG-B signal is BNC
Current Loop Input and Outputs
Accuracy
Current loop input accuracy: 1% of full scale
CLI drop-off threshold Under: setting 1% of full scale
CLI drop-off threshold Over: setting 1% of full scale
CLI sampling interval: 50 ms
CLI instantaneous operating time: < 250 ms
CLI DT operating time: 2% setting or 200 ms whichever is the greater
CLO conversion interval: 5 ms
CLO latency: < 1.07 s or <70 ms depending on
CLO output parameter’s internal refresh rate
- (1 s or 0.5 cycle)
Current loop output accuracy: 0.5% of full scale
Repeatability: <5%
Note CLI - Current Loop Input
CLO - Current Loop Output
Other Specifications
CLI load resistance 0-1 mA: < 4 k
CLI load resistance 0-1 mA/0-20 mA/4 20 mA: <300
Isolation between common input channels: zero
Isolation between input channels and case earth/other circuits: 2 kV rms for 1 minute
CLO compliance voltage 0-1 mA/0 10 mA: 10 V
CLO compliance voltage 0-20 mA/4 20 mA: 8.8 V
Isolation between common output channels: zero
Isolation between output channels and case earth/other circuits: 2 kV rms for 1 minute
Disturbance Records
Accuracy
Magnitude and relative phases:
5% of applied quantities
Duration:
Trigger Position:
Record length:
2%
2% (minimum 100 ms)
50 records each 1.5 s duration (75 s total memory) with 8 analogue channels and 32 digital channels (Courier, MODBUS, DNP 3.0,
IEC 61850),
8 records each 3 s (50 Hz) or 2.5 s (60 Hz) duration (IEC 60870-5-103).
Event, Fault & Maintenance Records
Maximum 512 events in a cyclic memory
Maximum 5 fault records
Maximum 10 maintenance records
Accuracy
Event time stamp resolution 1 ms
P341/EN TD/G74 Page (TD) 2-19
(TD) 2 Technical Data Settings, Measurements and Records List
IEC 61850 Ethernet Data
100 Base FX Interface
Transmitter optical characteristics
(TA = 0°C to 70°C, VCC = 4.75 V to 5.25 V)
Parameter Sym Min. Typ. Max.
Output Optical
Power BOL
62.5/125 µm,
NA = 0.275 Fiber
EOL
PO
Output Optical
Power BOL 50/125
µm, NA =
0.20 Fiber EOL
PO
-19
-20
-22.5
-23.5
-16.8 -14
-20.3 -14
Optical Extinction
Ratio
10
-10
Output Optical
Power at Logic “0”
State
PO
(“0”)
Unit dBm avg. dBm avg.
% dB
Note BOL - Beginning of life
EOL - End of life
Receiver optical characteristics
(TA = 0°C to 70°C, VCC = 4.75 V to 5.25 V)
Parameter Sym Min. Typ. Max.
Input Optical
Power Minimum at
Window Edge
PIN
Min. (W)
Input Optical
Power Minimum at
Eye Center
PIN
Min. (C)
Input Optical
Power Maximum
PIN
Max.
-14 -11.8
Unit dBm avg.
Note The 10BaseFL connection will no longer be supported as IEC 61850 does not specify this interface
SETTINGS, MEASUREMENTS AND
RECORDS LIST
Settings List
Global Settings (System Data)
Language: English/French/German/Spanish
Frequency: 50/60 Hz
Circuit Breaker Control (CB Control):
CB Control by: Disabled
Local
Remote
Local+Remote
Opto
Opto+local
Opto+Remote
Opto+Rem+local
Close Pulse Time:
Trip Pulse Time:
Man Close t max:
0.10...10.00 s
0.10…5.00 s
0.01…9999.00 s
Man Close Delay:
CB Healthy Time:
0.01…600.00 s
0.01…9999.00 s
Check Sync. Time: 0.01...9999.00 s
Reset Lockout by: User Interface/CB Close
Man Close RstDly: 0.10...600.00 s
CB Status Input: None
52A
52B
Date and Time
IRIG-B Sync:
Battery Alarm:
LocalTime Enable:
LocalTime Offset:
DST Enable:
Disabled/Enabled
Disabled/Enabled
Disabled/Fixed/Flexible
-720 min…720 min
Disabled/Enabled
DST Offset:
DST Start:
30 min…60 min
First/Second/
Third/Fourth/Last
DST Start Day: Sun/Mon/Tues/Wed/
Thurs/Fri/Sat
DST Start Month:
Jul/Aug/Sept/Oct/Nov/Dec
DST Start Mins:
Jan/Feb/Mar/Apr/May/Jun/
0 min…1425 min
DST End: First/Second/
Third/Fourth/Last
DST End Day: Sun/Mon/Tues/Wed/
Thurs/Fri/Sat
DST End Month: Jan/Feb/Mar/Apr/May/Jun/
Jul/Aug/Sept/Oct/Nov/Dec
DST End Mins:
RP1 Time Zone:
0 min…1425 min
UTC/Local
RP2 Time Zone: UTC/Local
Tunnel Time Zone: UTC/Local
Configuration
Setting Group: Select via Menu
Page (TD) 2-20 P341/EN TD/G74
Settings, Measurements and Records List
Select
Active Settings:
Setting Group 1:
Group 1/2/3/4
Disabled/Enabled
Setting Group 2:
Setting Group 3:
Setting Group 4:
System Config:
Power:
Overcurrent:
Thermal Overload:
Earth Fault:
Disabled/Enabled
Disabled/Enabled
Disabled/Enabled
Invisible/Visible
Disabled/Enabled
Disabled/Enabled
Disabled/Enabled
Disabled/Enabled
SEF/REF/Spower: Disabled or SEF/REF or
Sensitive
Residual O/V NVD: Disabled/Enabled df/dt: Disabled/Enabled
V Vector Shift:
Reconnect Delay:
Volt Protection:
Freq Protection:
Disabled/Enabled
Disabled/Enabled
Disabled/Enabled
Disabled/Enabled
CB Fail: Disabled/Enabled
Supervision: Disabled/Enabled
Dynamic Rating
Input Labels:
Disabled/Enabled
Invisible/Visible
Output Labels:
CT & VT Ratios:
Event Recorder:
Disturb Recorder:
Invisible/Visible
Invisible/Visible
Invisible/Visible
Invisible/Visible
Measure’t Setup:
Comms Settings:
Invisible/Visible
Invisible/Visible
Commission Tests: Invisible/Visible
Setting Values: Primary/Secondary
Control Inputs:
CLIO Inputs:
CLIO Outputs:
System Checks
Ctrl I/P Config:
Ctrl I/P Labels:
Direct Access:
IEC GOOSE
RP1 Read Only
RP2 Read Only
NIC Read Only
LCD Contrast:
Invisible/Visible
Disabled/Enabled
Disabled/Enabled
Disabled/Enabled
Invisible/Visible
Invisible/Visible
Disabled/Enabled
Invisible/Visible
Disabled/Enabled
Disabled/Enabled
Disabled/Enabled
0…31
(TD) 2 Technical Data
CT and VT Ratios
Main VT Primary:
Main VT Sec'y:
C/S VT Primary:
100...1000000 V
80...140 (100/120 V)
320…560 V (380/480 V)
100 V…1 MV
C/S VT Secondary: 80…140 V
VN VT Primary (P342/3):
100…1000000
VN VT Secondary (P342/3):
80…140 V (100/120 V)
320…560 V (380/480 V)
PH CT Polarity: Standard, Inverted
Phase CT Primary: 1 A…50 kA
Phase CT Sec'y Sec'y : 1 A/5 A
ISen CT Polarity:
ISen CT Primary:
Standard/Inverted
1 A…60 KA
ISen CT Sec’y: 1 A/5 A
Sequence of Event Recorder (Record
Control)
Alarm Event:
Relay O/P Event:
Opto Input Event:
General Event:
Fault Rec Event:
Maint Rec Event:
Disabled/Enabled
Disabled/Enabled
Disabled/Enabled
Disabled/Enabled
Disabled/Enabled
Disabled/Enabled
Protection Event:
DDB 31 - 0:
Disabled/Enabled
(up to):
DDB 2047 - 2016:
Binary function link strings, selecting which
DDB signals will be stored as events, and which will be filtered out.
Oscillography (Disturbance Recorder)
Duration: 0.10…10.50
Trigger Position:
Trigger Mode:
0.0…100.0%
Single/Extended
Analog Channel 1:
Analog Channel 8:
(up to):
Disturbance channels selected from:
IA/IB/IC/VA/VB/VC/VN/ISensitive/Frequency
V Checksync
Digital Input 1: (up to):
Digital Input 32:
Selected binary channel assignment from any
DDB status point within the relay (opto input, output contact, alarms, starts, trips, controls, logic…).
Input 1 Trigger: (up to):
Input 32 Trigger: No Trigger/
Trigger/
LH (Low to High)/
Trigger H/L (High to Low)
P341/EN TD/G74 Page (TD) 2-21
(TD) 2 Technical Data Settings, Measurements and Records List
Measured Operating Data (Measure’t
Setup)
Default Display: Access Level
3Ph
3Ph
Power
Date
Description
Plant
Frequency
Local Values:
Remote Values:
Primary/Secondary
Primary/Secondary
Measurement Ref: VA/VB/VC/IA/IB/IC
Measurement Mode: 0/1/2/3
Fix Dem Period: 1…99 mins
Roll Sub Period:
Num Sub Periods:
Remote2 Values:
1…99 mins
1…15
Primary/Secondary
Communications
RP1 Address: (Courier or IEC 870-5-103):
0…255
RP1 Address: (DNP3.0):
0…65534
RP1 Address: (MODBUS):
1…247
RP1 InactivTimer:
RP1 Baud Rate:
1…30 mins
(IEC 870-5-103):
9600/19200
RP1 Baud Rate: (MODBUS, Courier):
9600/19200/38400
RP1 Baud Rate: (DNP3.0):
1200/2400/4800/
RP1 Parity:
RP1 Meas Period:
(MODBUS, DNP3.0)
Odd/Even/None
1…60 s
870-5-103)
RP1 PhysicalLink:
or
RP1 Time Sync:
Copper (EIA(RS)485/K bus)
Disabled/Enabled
MODBUS IEC Timer: Standard/Reverse
RP1 CS103Blocking: Disabled
Monitor
Command
RP1 Port Config: (Courier):
Blocking
Bus
EIA485
RP1 Comms Mode: (Courier):
IEC 60870 FT1.2
IEC 60870 10-Bit No parity
Note If RP1 Port Config is K Bus the baud rate is fixed at 64 kbits/s
Optional Ethernet Port
NIC Tunl Timeout: 1...30 mins
NIC Link Report:
NIC Link Timeout:
Alarm, Event, None
0.1...60 s
Optional Additional Second Rear
Communication (Rear Port2 (RP2))
RP2 Port Config: EIA(RS)232
EIA(RS)485
K-Bus
RP2 Comms Mode: IEC 60870 FT1.2
RP2 Address:
RP2 InactivTimer:
RP2 Baud Rate:
IEC 60870 10-Bit No parity
0…255
1…30 mins
9600/19200/38400 bits/s
Note If RP2 Port Config is K Bus the baud rate is fixed at 64 kbits/s
Commission Tests
Monitor Bit 1: (up to):
Monitor Bit 8:
Binary function link strings, selecting which
DDB signals have their status visible in the
Commissioning menu, for test purposes
Test Mode: Disabled
Test Mode
Blocked
Test Pattern:
Configuration of which output contacts are to be energized when the contact test is applied
Circuit Breaker Condition Monitoring (CB
Monitor Setup)
Broken I^:
I^ Maintenance:
I^ Maintenance:
I^ Lockout:
I^ Lockout:
No. CB Ops Maint:
No. CB Ops Maint:
No. CB Ops Lock:
No. CB Ops Lock:
CB Time Maint:
CB Time Maint:
CB Time Lockout:
CB Time Lockout:
Fault Freq Lock:
Fault Freq Count:
Fault Freq Time:
1.0…2.0
Alarm Disabled/Enabled
1…25000
Alarm Disabled/Enabled
1…25000
Alarm Disabled/Enabled
1…10000
Alarm Disabled/Enabled
1…10000
Alarm Disabled/Enabled
0.005…0.500 s
Alarm Disabled/Enabled
0.005…0.500 s
Alarm Disabled/Enabled
1…9999
0…9999 s
Page (TD) 2-22 P341/EN TD/G74
Protection Functions (TD) 2 Technical Data
Opto Coupled Binary Inputs (Opto Config)
Global Nominal V: 24 - 27 V
30 - 34 V
48 - 54 V
110 - 125 V
Custom
220 - 250 V
Opto Input 1: (up to):
Opto Input #. (# = max. opto no. fitted):
Custom options allow independent thresholds to be set per opto, from the same range as above.
Opto Filter Control:
Binary function link string, selecting which optos will have an extra 1/2 cycle noise filter, and which will not.
Characteristics: Standard 60% - 80%
Control Inputs into PSL (Ctrl I/P Config)
Hotkey Enabled:
Binary function link string, selecting which of the control inputs will be driven from Hotkeys.
Control Input 1:
Control Input 32:
(up to):
Latched/Pulsed
Ctrl Command 1:
Ctrl Command 32:
(up to):
ON/OFF
SET/RESET
IN/OUT
ENABLED/DISABLED
IED Configurator
Switch Conf. Bank: No Action/Switch Banks
Restore MCL: No Action, Restore MCL
IEC 61850 GOOSE
GoEna:
Test Mode:
Disabled/Enabled
Disabled/
Through/
Forced
VOP Test Pattern:
Ignore Test Flag:
0x00000000... 0xFFFFFFFF
No/Yes
Control Input User Labels (Ctrl I/P Labels)
Control Input 1: (up to):
Control Input 32:
User defined text string to describe the function of the particular control input
Settings in Multiple Groups
Note All settings here onwards apply for setting groups # = 1 to 4.
PROTECTION FUNCTIONS
System Config
Phase Sequence:
VT Reversal:
Standard ABC/
Reverse ACB
No Swap/
Swapped/
C-A
CT Reversal:
Swapped/
No Swap/
A-B
C/S Input:
C/S V Ratio Corr:
Swapped/
C-A
A-N, B-N, C-N, A-B, B-C, C-A
0.500...2.000
Main VT Vect Grp: 0...11
Main VT Location: Gen/Bus
Reverse/Low Forward/Overpower
Operating mode: Generating
Motoring
Power 1 Function: Reverse
Low
Over forward
-P>1 Setting (reverse power/P<1
Setting (Low forward power)/ P>1
Setting (Overpower):
4…300.0 W (1 A, 100 V/120 V)
16…1200.0 W (1 A, 380 V/480 V)
20…1500.0 W (5 A, 100 V/120 V)
80…6000.0 W (5 A, 380 V/480 V)
Equivalent Range in %Pn 2%…157%
Power 1 Time Delay: 0.00…100.0 s
Power 1 DO Timer: 0.00…100.0 s
P1 Poledead Inh: Disabled/Enabled
Power 2 as Power 1
Sensitive/Reverse/Low
Forward/Overpower
Operating mode:
Sen Power1 Func:
Generating
Motoring
Reverse forward
Over
Sen -P>1 Setting (Reverse Power)/Sen <P Setting
(Low Forward Power)/Sen >P Setting (Over Power):
0.3…100.0 W (1 A, 100/120 V)
1.20…400.0 W (1 A, 380/480 V)
1.50…500.0 W (5 A, 100/120 V)
6.0…2000.0 W (5 A, 380/480 V)
Equivalent range in %Pn 0.5%…157%
Sen Power 1 Delay: 0.00…100.0 s
Power 1 DO Timer: 0.00…100.0 s
P1 Poledead Inh: Disabled/Enabled
Comp angle C: -5 …+5.0
Sen Power2 as Sen Power 1
P341/EN TD/G74 Page (TD) 2-23
(TD) 2 Technical Data Protection Functions
Phase Overcurrent (Overcurrent)
Phase O/C: Sub Heading
I>1 Function: Disabled
DT
IEC
V
IEC
Inverse
Rectifier
RI
IEEE
Inverse
IEEE
US
I>1 Direction:
Inverse
Non-Directional
Directional
Directional
I>1 Current Set:
I>1 Time Delay:
I>1 TMS:
0.08…4.00 In
0.00…100.00 s
0.025…1.200
I>1 Time Dial:
I>1 K (RI):
I>1 Reset Char:
I>1 tRESET:
0.01…100.00
0.10…10.00
DT/Inverse
0.00…100.00 s
I>2 as I>1
I>3 Status:
I>3 Direction:
Disabled/Enabled
Non-Directional
Fwd
Directional
I>3 Current Set:
I>3 Time Delay:
I>4 as I>3
0.08…10.00 In
0.00…100.00 s
-95…+95 o
I> Char Angle:
I >Function Link:
Bit 0 = VTS Blocks I>1
Bit 1 = VTS Blocks I>2
Bit 2 = VTS Blocks I>3
Bit 3 = VTS Blocks I>4
Bit 4, 5, 6 & 7 are not used
Binary function link string, selecting which overcurrent elements (stages 1 to 4) will be blocked if VTS detection of fuse failure
occurs.
Inverse Time (IDMT) Characteristic
IDMT characteristics are selectable from a choice of four IEC/UK and five IEEE/US curves as shown in the table below.
The IEC/UK IDMT curves conform to the formula:
K t = T x
( / s)
- 1
+ L
The IEEE/US IDMT curves conform to the formula: t = TD x
K
( / s)
- 1
+ L
Where: t = Operation time
K = Constant
I = Measured current
IS = Current threshold setting
= Constant
L = ANSI/IEEE constant (zero forIEC/UK curves)
T = Time multiplier setting for IEC/UK curves
TD = Time dial setting for IEEE/US curves
IDMT characteristics
IDMT curve Stand.
Standard inverse IEC
Very inverse IEC
Extremely inverse IEC
Long time inverse UK
K
0.14
13.5
80
120
0.02
1
2
1
L
0
0
0
0
Moderately inverse
Very inverse IEEE
Extremely inverse IEEE
19.61
28.2
2
2
0.491
0.1217
Short time inverse US-C02 0.16758 0.02 0.11858
The IEC extremely inverse curve becomes definite time at currents greater than 20 x setting. The IEC standard, very and long time inverse curves become definite time at currents greater than 30 x setting.
For all IEC/UK curves, the reset characteristic is definite time only.
For all IEEE/US curves, the reset characteristic can be selected as either inverse curve or definite time.
The inverse reset characteristics are dependent upon the selected IEEE/US IDMT curve as shown in the table below.
All inverse reset curves conform to the formula:
TD x S tRESET = in seconds
(1 - M2)
Where:
TD = Time dial setting for IEEE curves
S = Constant
M = I/Is
Curve description Standard S
Moderately inverse
Very inverse
Extremely inverse
IEEE
IEEE
IEEE
4.85
21.6
29.1
Short time inverse US 2.261
Page (TD) 2-24 P341/EN TD/G74
Protection Functions
The RI curve (electromechanical) has been included in the first stage characteristic setting options for
Phase Overcurrent and Earth Fault protections. The curve is represented by the equation: t = K x
0.339 -
(
1
0.236/
M
)
in seconds
With K adjustable from 0.1 to 10 in steps of 0.05
M = I/Is
IEC Curves
1000
100
100
10
10
Curve 4
Curve 1
1
0.1
1.0
Curve 1
Curve 2
Curve 3
Curve 4
10.0
Current (Multiples of I s)
Standard inverse
Very inverse
Extremely inverse
UK long time inverse
Curve 2
Curve 3
100.0
P2136ENa
(TD) 2 Technical Data
American Curves
1
0.1
1.0
Curve 5
Curve 6
Curve 7
Curve 8
Curve 9
10.0
Current (Multiples of I s)
IEEE moderately inverse
IEEE very inverse
IEEE extremely inverse
US inverse
US short time inverse
Curve 5
Curve 6
Curve 9
100.0
Curve 7
Curve 8
P2137ENa
P341/EN TD/G74 Page (TD) 2-25
(TD) 2 Technical Data Protection Functions
NPS Overcurrent
I2>1 Status:
I2>1 Direction: Non-Directional
Fwd
Directional
I2> Current Set:
I2> Time Delay:
I2>2/3/4 as for I2>1
I2> VTS Block:
Disabled/Enabled
0.08…4.0 In
0.00…100.00 s
Bit 0 = VTS Blocks I2>1
Bit 1 = VTS Blocks I2>2
Bit 2 = VTS Blocks I2>3
Bit 3 = VTS Blocks I2>4
Bits 4, 5, 6 & 7 are not used
Binary function link string, selecting which NPS overcurrent elements (stages 1 to 4) will be blocked if VTS detection of fuse failure occurs.
I2> V2pol Set: 0.5…25.0 (100 V 120 V)
I2> Char Angle:
2…100 V (380/480 V)
-95 …+95
Thermal Overload
Thermal:
Thermal I>:
Thermal Alarm:
T-heating:
T-cooling:
M Factor:
Disabled/Enabled
0.50…2.50 In
20..100%
1…200 minutes
1…200 minutes
0…10
The thermal time characteristic is given by: t = log t = . log e e
(I eq
2
((K 2
- I
-A 2
P
2
Where:
K = I eq
A = I
P
/Thermal I>
/Thermal I>
)/(I
)/(K 2 eq
2
- (Thermal I>)2)
-1))
I t =Time to trip, following application of the overload current, I
=Heating time constant of the protected plant eq
= Equivalent current
I
Thermal I> = Relay setting current
I
P
= Steady state pre-load current before application of the overload eq
= (I12 + MI22)
I1 = Positive sequence current
I2 = Negative sequence current
M = A user settable constant proportional to the thermal capacity of the machine
Earth Fault
IN1>1 Function: Disabled
DT
IEC
IEC
E
UK
RI
IEEE
V
IEEE
Inverse
US
IN1>1 Directional:
IDG
Non-Directional
Fwd
Rev
IN1>1 Current Set: 0.08…4.00 In
IN1>1 IDG Is:
IN1>1 Time Delay: 0.00…200.00 s
IN1>1 TMS:
1.0…4.0 In
0.025…1.200
IN1>1 Time Dial:
IN1>1 K(RI):
0.01…100.00
0.10….10.00
IN1>1 IDG Time: 1.00...2.00
IN1>1 Reset Char.: DT/Inverse
IN1>1 tRESET:
IN1>2 as IN>1
0.00…100.00 s
IN1>3 Status: Disabled
Enabled
IN1>3 Directional: Non-Directional
Directional
Rev
IN1>3 Current Set: 0.08…32.00 In
IN1>3 Time Delay: 0.00…200.00 s
IN1>4 as IN>3
IN1> Blocking:
Binary function link string, selecting which ground overcurrent elements (stages 1 to 4) will be blocked if VTS detection of fuse failure occurs.
-95… +95
IN1> Char Angle:
IN1> Polarization:
Neg.
IN1> VNpol Set:
Zero Sequence
Sequence
0.5…80.0 V (100/110 V)
2…320 V (380/480 V)
IN1> V2pol Set:
IN1> I2pol Set:
0.5…25.0 V (100/110 V)
2…100 V (380/480 V)
0.08…1.00 In
Page (TD) 2-26 P341/EN TD/G74
Protection Functions (TD) 2 Technical Data
The IDG curve is commonly used for time delayed earth fault protection in the Swedish market. This curve is available in stage 1 of the Earth Fault protection.
The IDG curve is represented by the following equation:
t = 5.8 - 1.35 loge
N > Setting in seconds
Where:
I = Measured current
IN>Setting = An adjustable setting which defines the start point of the characteristic
Although the start point of the characteristic is defined by the “IN>” setting, the actual relay current threshold is a different setting called “IDG Is”. The “IDG Is” setting is set as a multiple of “IN>”.
An additional setting “IDG Time” is also used to set the minimum operating time at high levels of fault current.
IDG Characteristic
SEF/REF Prot’n
SEF/REF Options: SEF
Cos
SEF
Wattmetric
ISEF>1 Function: Disabled
DT
Inverse
IEC
E
UK
RI
IEEE
V
IEEE
US Inverse
US
ISEF>1 Directional:
IDG
Non-Directional
Fwd
Rev.
ISEF>1 Current Set:
ISEF>1 IDG Is:
0.005...0.10 In
1.0...4.0 In
ISEF>1 Time Delay: 0.00...200.00 s
ISEF>1 TMS: 0.025...1.200
ISEF>1 Time Dial: 0.01...100.0
ISEF>1 IDG Time: 1.00...2.00
ISEF>1 Reset Char: DT/Inverse
ISEF>1 tRESET:
ISEF>2 as ISEF>2
0.00...100.00 s
ISEF>3 Status: Disabled
Enabled
ISEF>3 Directional: Non-Directional
Directional
Rev
ISEF>3 Current Set: 0.005...0.80 In
ISEF>3 Time Delay: 0.00...200.00 s
ISEF>4 as ISEF>3
ISEF> Blocking:
Binary function link string, selecting which ground overcurrent elements (stages 1 to 4) will be blocked if VTS detection of fuse failure occurs.
ISEF> Char. Angle: -95...+95
ISEF> VNpol Set:
WATTMETRIC SEF:
0.5...80.0 V (100/120 V)
2...320 V (380/480 V)
PN> Setting: 0....20 In W (100/120 V)
PN> Setting: 0 ....80 In W (380/480 V)
Restricted Earth Fault (High Impedance)
IREF> Is: 0.05.1.00 In
Residual O/V NVD
VN>1 Status:
VN>1 Input:
VN> 1 Function:
Disabled/Enabled
Derived
Disabled
DT
IDMT
VN> 1 Voltage Set: 1…80 V (100/120 V)
4…320 V (380/480 V)
VN> 1 Time Delay: 0.00…100.00 s
VN>1 TMS:
VN> 1 tRESET:
VN>2 as VN>1
VN>3/4 as VN>1 except
0.5…100.0
0.00…100.00
VN>3/4 Input: VN1
P341/EN TD/G74 Page (TD) 2-27
(TD) 2 Technical Data Voltage Protection
DF/DT
Operating Mode: df/dt Avg Cycles: df/dt Iterations: df/dt>1 Status: df/dt>1 Setting: df/dt>1 Dir'n: df/dt>1 Time: df/dt>1 f L/H: df/dt>2/3/4 Dir'n: df/dt>2/3/4 Time:
Fixed Window/Rolling Window
2…12
1…4
Disabled/Enabled
0.10…10.00 Hz
Negative/Positive/Both
0.00…100.00 s
Disabled/Enabled df/dt>1 f Low: df/dt>1 f High:
45.00…65.00 Hz
45.00…65.00 Hz df/dt>2/3/4 Status: Disabled/Enabled df/dt>2/3/4 Setting: 0.10…10.00 Hz
Negative/Positive/Both
0.00…100.00 s
V Vector Shift
V Shift Status:
V Shift Angle:
Disabled/Enabled
2…30
Reconnect Delay
Reconnect Status: Disabled/Enabled
Reconnect Delay: 0…300.0 s
Reconnect tPULSE: 0…10.0 s
VOLTAGE PROTECTION
Undervoltage
V< Measur’t Mode: Phase-Phase
Phase-Neutral
V< Operate Mode: Any Phase
Three
V< 1 Function: Disabled
DT
IDMT
V<1 Voltage Set:
V<1 Time Delay:
V<1 TMS:
10…120 V (100/120 V)
40…480 V (380/480 V)
0.00…100.00 s
0.05…100.0
V<1 Poledead Inh: Disabled/Enabled
V<2 Function:
V<2 Status:
Disabled
DT
Disabled/Enabled
V<2 Voltage Set: 10…120 V (100/120 V)
40…480 V (380/480 V)
V<2 Time Delay: 0.00…100.00 s
V<2 Poledead Inh: Disabled/Enabled
The inverse characteristic is given by the formula:
K t =
(1 - M)
Where:
K = Time multiplier setting
T = Operating time in seconds
M = Applied input voltage/relay setting voltage
Overvoltage
V> Measur’t Mode: Phase-Phase
Phase-Neutral
V> Operate Mode: Any Phase
V> 1 Function:
V>1 Voltage Set:
Disabled
DT
IDMT
60…185 V (100/120 V)
240…740 V (380/480 V)
V>1 Time Delay:
V>1 TMS:
0.00…100.00 s
0.05…100.0
V>2 Status:
V>2 Voltage Set:
60…185 V
Disabled/Enabled
(100/120 V)
240…740 V (380/480 V)
V>2 Time Delay: 0.00…100.00 s
The inverse characteristic is given by the formula:
K t =
(M - 1)
Where:
K = Time multiplier setting t = Operating time in seconds
M = Applied input voltage/relay setting voltage
NPS Overvoltage
V2>1 status:
V2>1 Voltage Set:
V2>1 Time Delay:
Enabled/Disabled
1…150 V (100/120 V)
4…600 V (380/480 V)
0.00…100.00 s
Page (TD) 2-28 P341/EN TD/G74
Frequency Protection
FREQUENCY PROTECTION
Underfrequency
F<1 Status:
F<1 Setting:
F<1 Time Delay:
F<2/3/4 as F<1
Disabled/Enabled
45.00…65.00 Hz
0.1…100.0 s
F< Function Link:
Bit 0 - Enable Block F<1 during poledead
Bit 1 - Enable Block F<2 during poledead
Bit 2 - Enable Block F<3 during poledead
Bit 3 - Enable Block F<4 during poledead
Overfrequency
F>1 Status:
F>1 Setting:
F>1 Time Delay:
F>2 as F>1
Disabled/Enabled
45.00…68.00 Hz
0.1…100.0 s
CB Fail
CB Fail 1 Status:
CB Fail 1 Timer:
CB Fail 2 Status:
CB Fail 2 Timer:
CBF Non I Reset:
CBF Ext Reset:
Disabled/Enabled
0.00…10.00 s
Disabled/Enabled
0.00…10.00 s
I< Only,
CB Open & I<,
Prot Reset & I<
I< Only,
CB Open & I <,
I< Current Set:
IN< Current Set:
ISEF< Current:
Prot Reset & I<
0.02…3.200 In
0.02…3.200 In
0.0010…0.8000 In
Remove I> Start: Disabled/Enabled
Remove IN< Start: Disabled/Enabled
(TD) 2 Technical Data
SUPERVISORY FUNCTIONS
Voltage Transformer Supervison
VTS Status: Blocking/Indication
VTS Reset Mode:
VTS Time Delay:
VTS I> Inhibit:
Manual/Auto
1.0…10.0 s
0.08 In…32.0 In
VTS I2> Inhibit: 0.05 In…0.50 In
Negative phase sequence voltage (V2):
10 V (100/120 V)
40 V (380/480 V)
Phase overvoltage:
Pick-up
Drop-off
Pick-up
30 V,
10 V (100/120 V)
120 V,
Drop-off 40 V (380/480 V)
Superimposed Current: 0.1 In
Current Transformer Supervision
CTS 1 Status:
CTS 1 VN Input:
CTS 1 VN< Inhibit:
Disabled/Enabled
Measured/Derived
0.5…22 V (100/120 V)
2…88
CTS 1 IN> Set: 0.08…4 In
System Checks Voltage Monitors
Live/Dead Voltage: 1.0…132.0 V (100/110 V)
22…528 V (380/440 V)
Gen Undervoltage: 1.0…132.0 V (100/110 V)
Gen Overvoltage:
CS Undervoltage:
CS Overvoltage:
CS Diff Voltage:
22…528 V (380/440 V)
1.0…185.0 V (100/110 V)
22…740 V (380/440 V)
10.0…132.0 V (100/110 V)
22…528 V (380/440 V)
60.0…185.0 V (100/110 V)
240…740 V (380/440 V)
1.0…132.0 V (100/110 V)
CS Voltage Block:
4…528 V (380/440 V)
None
Undervoltage
Overvoltage
Differential
UV & O V
UV & Diff V
OV & Diff V
Gen Underfreq:
Gen Overfreq:
UV, OV & Diff V
45.00...65.00 Hz
45.00...65.00 Hz
P341/EN TD/G74 Page (TD) 2-29
(TD) 2 Technical Data
Check Sync
CS1 Status: Disabled/Enabled
CS1 Phase Angle: 5…90 o
CS1 Slip Control: None
Timer
Frequency
CS1 Slip Freq.:
CS1 Slip Timer:
Both
0.01…1.00 Hz
0.00…99.00 s
CS2 Status:
CS1 Slip Control:
Disabled/Enabled
None
Timer
Frequency
CS2 Slip Freq.:
CS2 Slip Timer:
+
Freq
0.01…1.00 Hz
0.00…99.00 s
System Split
SS Status:
SS Phase Angle:
Disabled/Enabled
90…175 o
SS Under V Block: Disabled/Enabled
SS Undervoltage:
SS Timer:
10.0…132.0 V (100/110 V)
40…528 V (380/440 V)
0.00…99.00 s
CB Close Time: 0.000…0.500 s
Plant Supervision
PLANT SUPERVISION
CB State Monitoring Control and
Condition Monitoring
Broken I^: 1…2.0
I^ Maintenance:
I^ Maintenance:
I^ Lockout:
Alarm disabled
Alarm
1 In^…25000 In^
Alarm disabled
Alarm
I^ Lockout:
No CB Ops. Maint:
1…25000
Alarm disabled
Alarm
No CB Ops: Maint: 1…10000
No CB Ops Lock:
Alarm
No CB Ops Lock:
Alarm disabled enabled
1…10000
CB Time Maint:
CB Time Maint:
CB Time Lockout:
Alarm disabled
Alarm
0.005…0.500 s
Alarm disabled
Alarm
CB Time Lockout:
Fault Freq Lock:
0.005…0.500 s
Alarm disabled
Alarm
Fault Freq Count:
Fault Freq Time:
1…9999
0…9999 s
Page (TD) 2-30 P341/EN TD/G74
Dynamic Rating (TD) 2 Technical Data
DYNAMIC RATING
Dyn Line Rating: Disabled/CIGRE Std 207/
IEEE
DLR Line Setting
Conductor Type:
Gopher, Weasel, Ferret, Rabbit, Horse, Dog,
Wolf, Dingo, Lynx, Caracal, Panther, Jaguar,
Zebra, Fox, Mink, Skunk, Beaver, Raccoon,
Otter, Cat, Hare, Hyena, Leopard, Tiger,
Coyote, Lion, Bear, Batang, Goat, Antelope,
Sheep, Bison, Deer, Camel, Elk, Moose,
Custom
NonFerrous Layer: 1…3
DC Resist per km: 0.001…2.0000 Ω
Overall Diameter: 0.001…0.10000 m
Outer Layer Diam: 0.001…0.0100 m
TotalArea(mm sq): 10.00…1000.00 mm
TempCoefR x0.001: 1.00…10.00 K
1.0…5000.0 J/(m K)
2 mc:
Solar Absopt:
Line Emissivity:
Line Elevation:
Line Azimuth Min:
0.23…0.95
0.23...0.95
-1000...6000 m
0.0…360.0
Line Azimuth Max: 0.0…360.0
T Conductor Max: 0.0 …300.0
C
Ampacity Min:
Ampacity Max:
Drop-off Ratio:
Line Direction:
0.100…4.000 In
0.100…4.000 In
70.0...99.0%
0.0…360.0
DLR Channel Set
Ambient Temp: Disabled, CLI1, CLI2,
Default Ambient T:
CLI4
-100.0 …100.0
C
Ambient T Corr:
Ambient T Min:
Ambient T Max:
Ambient T AvgSet:
-50.0 …50.0
C
-100.0 …100.0
C
-100.0 …100.0
C
Disabled/Enabled
Ambient T Avg Dly: 60…3600 s
Amb T Input Type : 0-1 mA, 0-10 mA,
Amb T I/P Min:
Amb T I/P Max:
Amb T I< Alarm:
Amb T I< Alm Set:
0-20 mA, 4-20 mA
-100.0…100.0
C
-100.0 …100.0
C
Disabled/Enabled
0…4 mA
Wind Velocity:
CLI3,
Default Wind Vel:
Disabled, CLI1, CLI2,
CLI4
0.00…60.00 m/s
Wind Vel Corr:
Wind Vel Min:
Wind Vel Max:
Wind Vel AvgSet:
Wind Vel Avg Dly:
WV Input Type :
0...150%
0.00…60.00 m/s
0.00…60.00 m/s
Disabled/Enabled
60…3600 s
0-1 mA, 0-10 mA,
0-20 mA, 4-20 mA
WV I/P Minimum:
WV I/P Maximum:
WV I< Alarm:
WV I< Alarm Set:
0.00…60.00 m/s
0.00…60.00 m/s
Disabled/Enabled
0…4 mA
Wind Direction:
Default Wind Dir:
Disabled, CLI1, CLI2,
CLI3,
0.0…360.0
Wind Dir Corr:
Wind Dir Min:
Wind Dir Max:
-180.0…180.0
0.0…360.0
0.0…360.0
Wind Dirl AvgSet:
Wind Dir Avg Dly:
WD Input Type :
WD I/P Minimum:
WD I/P Maximum:
Disabled/Enabled
60…3600 s
0-1 mA, 0-10 mA,
0-20 mA, 4-20 mA
0.0…360.0
0.0…360.0
WD I< Alarm:
WD I< Alarm Set:
Solar Radiation:
CLI3,
Default Solar R:
Disabled/Enabled
0…4 mA
Disabled, CLI1, CLI2,
CLI4
0…3000 W
Solar Rad Corr:
Solar Rad Min:
Solar Rad Max:
-1000...1000 W
0…3000 W
0…3000 W
Solar Rad AvgSet: Disabled/Enabled
Solar Rad Avg Dly: 60…3600 s
SR Input Type :
SR I/P Minimum:
0-1 mA, 0-10 mA,
0-20 mA, 4-20 mA
0…3000 W
SR I/P Maximum:
SR I< Alarm:
SR I< Alarm Set:
0…3000 W
Disabled/Enabled
0…4 ma
DLR Prot
DLR I>1 Trip:
DLT I>1 Set:
Disabled/Enabled
20.0%...200.0%
DLR I>1 Delay: 0…30000 s
DLR I>2/3/4/5/6 as DLR I>1
P341/EN TD/G74 Page (TD) 2-31
(TD) 2 Technical Data Dynamic Rating
Input Labels
Opto Input 1…32:
Output Labels
Relay 1…32:
Input L1…Input L32
Output R1…Output R32
Current Loop Input
CLIO1 Input 1: Disabled/Enabled
CLI1 Input Type:
CLI1 Input Label:
CLI1 Minimum:
CLI1 Maximum:
CLI1 Alarm:
CLI1 Alarm Fn:
CLI1 Alarm Set:
CLI1 Alarm Delay:
0 - 1 mA
0 - 10 mA
0 - 20 mA
4 - 20 mA
16 characters (CLIO input 1)
-9999…+9999
-9999…+9999
Disabled/Enabled
Over/Under
CLI1 min…CLI1 max
0.0…100.0 s
CLI1 Trip:
CLI1 Trip Fn:
CLI1 Trip Set:
CLI1 Trip Delay:
Disabled/Enabled
Over/Under
CLI1 min…CLI1 max
0.0…100.0 s
CLI1 I< Alarm (4…20 mA input only):
Disabled/Enabled
CLI1 I< Alm Set (4…20 mA input only):
CLI2/3/4 as CLI1
Current Loop Output
CLO1 Output 1: Disabled/Enabled
CLO1 Output Type: 0 - 1 mA
0 - 10 mA
0 - 20 mA
4 - 20 mA
CLO1 Set Values:
CLO1 Parameter:
CLO1 Min:
Primary/Secondary
As shown below*
Range, step size and unit corresponds to the
selected
CLO1 Max: Same as CLO1 Min
CLO2/3/4 as CLO1
Current Loop Output Parameters
Current Magnitude: IA Magnitude
IB
IC
IN Derived Mag:
Magnitude
0.00…16.0 A
I Sen Mag: 0.00… 2.0 A
Phase Sequence Components:
Magnitude
Magnitude
I0 Magnitude:
Phase Currents:
0.00…16.0 A
IA RMS*
IB
IC RMS*
P-P Voltage Magnitude: VAB Magnitude
Magnitude
VCA
V
P-N Voltage Magnitude: VAN
Magnitude
VCN
V
Neutral Voltage Magnitude: VN1 Measured Mag
Derived
V
Phase Sequence Voltage Components:
Magnitude*
V2
Magnitude
0.0…200.0
RMS Phase Voltages: VAN RMS*
V
RMS*
RMS*
Frequency: 0.00…70.0
3 Phase Watts*:
V
Hz
-6000 W…6000 W
3 Phase Vars*:
3 Phase VA*:
-6000 Var…6000 Var
0…6000 VA
3Ph Power Factor*: -1…1
Single Phase Active Power:
A Watts*:
B Watts*:
C Phase Watts*:
-2000
Single Phase Reactive Power:
A
B
C
Vars*:
Vars*
-2000
Single Phase Apparent Power:
Var…2000
A VA*:
B VA*:
C VA*
0…2000
Single Phase Power Factor:
Aph Factor*
BPh Factor*
CPh Factor*
-1…1
3 Phase Current Demands:
Fixed/Roll/Peak
IB
Fixed/Roll/Peak
0.00…16.0
3ph Active Power Demands:
3Ph W Fix/Roll/Peak Demand*
-6000W…6000W
3ph Reactive Power Demands:
3Ph Vars Fix/Roll/Peak Dem*
-6000
Page (TD) 2-32 P341/EN TD/G74
Measurements List (TD) 2 Technical Data
Thermal Overload: 0.00…200.0%
CL Input 1-4:
DLR Ampacity:
-9999…9999.0
0.00…4.0 A
Maximum ac current: df/dt:
0.00…16.0 A
-10.00…10.00 Hz/s
Check Synch Voltages: 0.0…200.0
Slip Frequency:
V
0.00…70.00 Hz
Note 1:
Note 2:
Note 3:
Measurements marked with an asterisk, the internal refresh rate is nominally 1 s, others are 0.5 power system cycles or less.
The polarity of Watts, Var and power factor is affected by the measurements Mode setting.
These settings are for nominal 1 A and 100/120 V versions only. For other versions they need to be multiplied accordingly.
MEASUREMENTS LIST
Measurements 1
I Magnitude
I Phase Angle
Per phase ( = A/A-1, B/B-1, C/C-1) current measurements
IN Derived Mag
IN Derived Angle
ISen Mag
ISen Angle
I1 Magnitude
I2 Magnitude
I0 Magnitude
I RMS
Per phase ( = A, B, C) RMS current measurements
IN -2 Derived
V Magnitude
V Phase Angle
V Magnitude
V Phase Angle
All phase-phase and phase-neutral voltages (
= A, B, C).
VN Measured Mag
VN Measured Ang
VN Derived Mag
V1 Magnitude
V2 Magnitude
V0 Magnitude
V RMS
All phase-neutral voltages ( = A, B, C).
Frequency
I1 Magnitude
I1 Angle
I2 Magnitude
I2 Angle
I0 Magnitude
I0 Angle
V1 Magnitude
V1 Angle
V2 Magnitude
V2 Angle
V0 Magnitude
V0 Angle
C/S Voltage Mag
C/S Voltage Ang
Gen-Bus Volt
Gen-Bus Angle
Slip Frequency
C/S Frequency
P341/EN TD/G74 Page (TD) 2-33
(TD) 2 Technical Data Measurements List
Measurements 2
Phase Watts
Phase VArs
Phase VA
All phase segregated power measurements, real, reactive and apparent (
3 Phase Watts
3 Phase VArs
= A, B, C).
3 Phase VA
NPS Power S2
3Ph Power Factor
Ph Power Factor
Independent power factor measurements for all three phases ( = A, B, C).
3Ph WHours Fwd
3Ph WHours Rev
3Ph VArHours Fwd
3Ph VArHours Rev
3Ph W Fix Demand
3Ph VArs Fix Dem
I Fixed Demand
Maximum demand currents measured on a per phase basis (
3Ph W Roll Dem
= A, B, C).
3Ph VArs Roll Dem
I Roll Demand
Maximum demand currents measured on a per phase basis ( = A, B, C).
3Ph W Peak Dem
3Ph VAr Peak Dem
I Peak Demand
Maximum demand currents measured on a per phase basis (
Reset Demand: No/Yes
= A, B, C).
Measurements 3
IREF Diff
A Ph Sen Watts
A Ph Sen VArs
A Phase Power Angle
Thermal Overload
Reset Thermal O/L: No/Yes
CLIO Input 1/2/3/4 df/dt
Measurements 4
Max Iac
DLR Ambient Temp
Wind Velocity
Wind Direction
Solar Radiation
Effct wind angle
Pc
Pc, natural
Pc1, forced
Pc2, forced
DLR Ampacity
DLR CurrentRatio
Dyn Conduct Temp
Steady Conduct T
Time Constant
Circuit Breaker Monitoring Statistics
CB Operations
Total I Broken
Cumulative breaker interruption duty on a per phase basis ( = A, B, C)
CB Operate Time
Reset CB Data: No/Yes.
Page (TD) 2-34 P341/EN TD/G74
MiCOM P34x (P342, P343, P344, P345, P346 & P391) & P341 (GS) 3 Getting Started
P34x_P341/EN GS/J96
GETTING STARTED
CHAPTER 3
Page (GS) 3-1
(GS) 3 Getting Started MiCOM P34x (P342, P343, P344, P345, P346 & P391) & P341
Hardware Suffix:
Software Version:
Connection Diagrams:
J (P341/P342) K (P343/P344/P345/P346) A (P391)
36/71 (P341 with DLR) and 36 (P343/P344/P345/P346)
10P341xx (xx = 01 to 12)
10P342xx (xx = 01 to 17)
10P343xx (xx = 01 to 19)
10P344xx (xx = 01 to 12)
10P345xx (xx = 01 to 07)
10P345xx (xx = 01 to 07)
10P346xx (xx = 01 to 19)
10P391xx (xx =01 to 02)
Page (GS) 3-2 P34x_P341/EN GS/J96
Contents (GS) 3 Getting Started
CONTENTS
User Interfaces and Menu Structure
2 RELAY CONNECTION AND POWER-UP
3 USER INTERFACES AND SETTINGS OPTIONS
7 FRONT PANEL USER INTERFACE (KEYPAD AND LCD)
Default Display and Menu Time-Out
Navigating Menus and Browsing the Settings
Navigating the Hotkey Menu 7.3
Control Inputs - User Assignable Functions
Reading and Clearing of Alarm Messages and Fault Records
8 FRONT COMMUNICATION PORT USER INTERFACE
9 MICOM S1 STUDIO RELAY COMMUNICATIONS BASICS
Connecting to the Relay using MiCOM S1 Studio
Off-Line Use of MiCOM S1 Studio
Page (GS) 3-
P34x_P341/EN GS/J96 Page (GS) 3-3
(GS) 3 Getting Started Figures
FIGURES
Figure 1 - Relay front view (P341/P342)
Figure 2 - Relay front view (P343/P344/P345/P346)
Figure 5 - Front panel user interface
Figure 6 - Hotkey menu navigation
Figure 7 - Front port connection
Figure 8 - PC relay signal connection
Page (GS) 3-
TABLES
Table 1 - Default LED mappings for P341/P342/P343/P344/P345/P346
Table 2 - Nominal dc and ac ranges
Table 3 - Accessible measurement information and relay settings
Table 5 - Front port DCE pin connections
Table 6 - DTE devices serial port pin connections
Table 7 - Relay front port settings
Page (GS) 3-
Page (GS) 3-4 P34x_P341/EN GS/J96
Introduction to the Relay
1
1.1
1.2
(GS) 3 Getting Started
INTRODUCTION TO THE RELAY
User Interfaces and Menu Structure
The settings and functions of the protection relay are available from the front panel keypad and LCD, and through the front and rear communication ports.
Front Panel
Figure 1 shows the front panel of the relay; the hinged covers at the top and bottom of the
front panel are shown open. An optional transparent front cover physically protects the front panel. With the cover in place, access to the user interface is read-only. Removing the cover allows access to the relay settings and does not compromise the protection of the product from the environment.
When editing relay settings, full access to the relay keypad is needed. To remove the front panel:
1. Open the top and bottom covers, then unclip and remove the transparent cover. If the lower cover is secured with a wire seal, remove the seal.
2. Using the side flanges of the transparent cover, pull the bottom edge away from the relay front panel until it is clear of the seal tab.
3. Move the cover vertically down to release the two fixing lugs from their recesses in the front panel.
P34x_P341/EN GS/J96
Figure 1 - Relay front view (P341/P342)
Page (GS) 3-5
(GS) 3 Getting Started Introduction to the Relay
Page (GS) 3-6
Figure 2 - Relay front view (P343/P344/P345/P346)
The front panel of the relay includes the following, as indicated in Figure 1 and Figure 2:
A 16-character by 3-line alphanumeric Liquid Crystal Display (LCD)
A keypad (19 keys for P343/P344/P345/P346 and 9 keys for P341/P342), comprising:
four arrow keys ( and key ( ) and two hot keys ( )
), an enter key ( ), a clear key ( ), a read
10 ) programmable function keys (P343/P344/P345/P346).
Function key functionality for the P343/P344/P345/P346. The relay front panel has control keys with programmable LEDs for local control. Factory default settings associate specific relay functions with these 10 direct-action keys and LEDs, such as Enable or Disable the auto-recloser function.
Using programmable scheme logic, the user can change the default functions of the keys and LEDs to fit specific needs.
Hotkey
SCROLL starts scrolling through the various default displays.
STOP stops scrolling the default display.
LED
Control inputs and circuit breaker operation to control setting groups.
4 fixed function LEDs
Eight user programmable function LEDs on the front panel (red for the
P341/P342 and tri-color for the P343/P344/P345/P346)
10 tri-color user programmable function LEDs on the right hand side associated with the function keys (P343/P344/P345/P346).
Under the top hinged cover:
The relay’s serial number.
The relay’s current and voltage rating information
Under the bottom hinged cover:
Compartment for a ½ AA-size backup battery used for the real time clock and event, fault, and disturbance records.
P34x_P341/EN GS/J96
Introduction to the Relay
1.2.1
1.2.1.1
1.2.1.2
(GS) 3 Getting Started
A 9-pin female D-type front port for a connection of up to 15 m between a
PC and the relay using an EIA(RS)232 serial data connection.
A 25-pin female D-type parallel port for monitoring internal signals and downloading high-speed local software and language text.
LED Indications
Fixed Function
The four fixed function LEDs on the left-hand side of the front panel indicate the following conditions:
Trip (Red) switches ON when the relay issues a trip signal. It is reset when the associated fault record is cleared from the front display. Also the trip LED can be configured as self-resetting.
Alarm (Yellow) flashes when the relay registers an alarm. This may be triggered by a fault, event or maintenance record. The LED flashes until the alarms have been accepted (read), then changes to constantly ON. When the alarms are cleared, the LED switches OFF.
Out of service (Yellow) is ON when the relay’s protection is unavailable.
Healthy (Green) is ON when the relay is in correct working order, and should be
ON at all times. It goes OFF if the relay’s self-tests show there is an error in the relay’s hardware or software. The state of the healthy LED is reflected by the watchdog contacts at the back of the relay.
To adjust the LCD contrast, from the CONFIGURATION column, select LCD Contrast .
This is only needed in very hot or cold ambient temperatures.
Programmable LEDs
P341/P342 : all the programmable LEDs are RED.
P343/P344/P345/P346 : all the programmable LEDs are tri-color and can be programmed to indicate RED, YELLOW or GREEN depending on the requirements.
The eight programmable LEDs are suitable for programming alarm indications and the
default indications and functions are indicated in Table 1.
P343/P344/P345/P346 : the 10 programmable LEDs associated with the function keys, show the status of the associated pushbutton’s function. The default indications are
P34x_P341/EN GS/J96 Page (GS) 3-7
(GS) 3 Getting Started Introduction to the Relay
LED
No
Default
Color
P341 P342 P343/P344/P345/P346
1 Red
Earth Fault Trip
-IN>1/2/3/4 Trip, ISEF>1/2/3/4 Trip,
/IREF>Trip, VN>1/2/3/4 Trip
Earth Fault Trip
-IN>1/2/ISEF>1/IREF>/VN>1/2/3/4/64R
R<2 Trip
Earth Fault Trip
-IN>1/2/ISEF>1/IREF>/VN>1/2/3/4/5/6/100%
ST EF 3H/64S I>1/64S R<2 Trip/64R R<2
Trip
2 Red
Overcurrent Trip
- >1/2 Trip (3x software), I>1/2/3/4 Trip
(7x software)
3 Red
Overcurrent Trip
- >3/4 Trip (3x software), DLR
I>1/2/3/4/5/6 Trip (7x software)
4 Red df/dt>1/2/3/4 Trip and V Shift Trip
Overcurrent Trip
- >1/2/3/4/V Dep OC Trip
Field Failure Trip - Field Fail 1/2 Trip
Overcurrent Trip
- >1/2/3/4/V Dep OC Trip
Field Failure Trip - Field Fail 1/2 Trip
I2> Trip - I2>1/2/3/4/NPS Thermal Trip I2> Trip - I2>1/2/3/4/NPS Thermal Trip
5 Red
Voltage Trip - V>1/2 trip, V<1/2 Trip, V2>1
Trip
Voltage Trip - V>2/V<2/V2>1 Trip
6 Red
Frequency Trip - F>1/2 Trip, F<1/2/3/4
Trip
Frequency Trip - F>2/F<4/Freq Band
1/2/3/4/5/6 Trip
Power Trip - Power 1/SPower 1 Trip
Voltage Trip - V>2/V<2/V2>1 Trip
Frequency Trip - F>2/F<4/Freq Band
1/2/3/4/5/6 Trip
Power Trip - Power 1/SPower 1 Trip
Not used Not used
8 Red Any Start
F1 Red Not used
F2 Yellow Not used
F3 Yellow Not used
F4 Red Not used
F5 Red Not used
F6 Red Not used
F7 Red Not used
F8 Red Not used
F9 Yellow Not used
F10 Yellow Not used
Any Start
Not used
Not used
Not used
Inhibit Turbine Abnormal Frequency
Protection
Any Start
Not used
Not used
Not used
Inhibit Turbine Abnormal Frequency
Protection
Setting Group 2 Enabled
Not used
Reset NPS Thermal State to 0
Reset Thermal Overload State to 0
Setting Group 2 Enabled
Not used
Reset NPS Thermal State to 0
Reset Thermal Overload State to 0
Reset Latched LEDs and Relay Contacts Reset Latched LEDs and Relay Contacts
Manual Trigger Disturbance Recorder Manual Trigger Disturbance Recorder
Table 1 - Default LED mappings for P341/P342/P343/P344/P345/P346
Page (GS) 3-8 P34x_P341/EN GS/J96
Introduction to the Relay
1.3
(GS) 3 Getting Started
Relay Rear Panel
Figure 3 shows the rear panel of the relay. All current and voltage signals, digital logic
input signals and output contacts are connected at the rear of the relay. Also connected at the rear is the twisted pair wiring for the rear EIA(RS)485 communication port, the
IRIG-B time synchronizing input and the optical fiber rear communication port which are both optional.
P34x_P341/EN GS/J96
Figure 3 - Relay rear view
See the wiring diagrams in the Installation chapter for complete connection details.
Page (GS) 3-9
(GS) 3 Getting Started Relay Connection and Power-up
2 RELAY CONNECTION AND POWER-UP
Before powering-up the relay, confirm that the relay power supply voltage and nominal ac signal magnitudes are appropriate for your application. The relay serial number, and its current, voltage and power rating are under the top hinged cover. The relay is available
in the auxiliary voltage versions which are specified in Table 2.
Product(s)
All
All
Nominal ranges
24 - 48 V dc
48 - 110 V dc (40 - 100 V ac rms) **
All
P391 only
110 - 250 V dc (100 - 240 V ac rms) **
48 - 250 V dc, (100 - 230 V ac rms) **
** rated for ac or dc operation
Operative dc range
19 to 65 V
37 to 150 V
87 to 300 V
48 to 300 V
Operative ac range
-
32 to 110 V
80 to 265 V
85 to 253 V
Note The label does not specify the logic input ratings.
Table 2 - Nominal dc and ac ranges
The relay has universal opto isolated logic inputs. These can be programmed for the nominal battery voltage of the circuit where they are used. See the Universal opto isolated logic inputs in the Firmware chapter for more information on logic input specifications.
Note The opto inputs have a maximum input voltage rating of 300 V dc at any setting.
Once the ratings have been verified for the application, connect external power according to the power requirements specified on the label. See the external connection diagrams in the Installation chapter for complete installation details, ensuring the correct polarities are observed for the dc supply.
Page (GS) 3-10 P34x_P341/EN GS/J96
User Interfaces and Settings Options (GS) 3 Getting Started
The relay has the following user interfaces:
The front panel using the LCD and keypad
The front port which supports Courier communication
The rear port which supports one protocol of either Courier, MODBUS, IEC 60870-
5-103, DNP3.0 or IEC 61850. The protocol for the rear port must be specified when the relay is ordered
A second rear port (option) which supports Courier communication
Table 3 shows the measurement information and relay settings which are accessible from
the interfaces:
Keypad/
LCD
Courier MODBUS
IEC 870-
5-103
IEC
61850-8-1
DNP3.0
Display & modification of all settings
Digital I/O signal status
Display/extraction of measurements
Display/extraction of fault records
Extraction of disturbance records
Programmable scheme logic settings
Reset of fault & alarm records
Clear event & fault records
Time synchronization
Control commands
• • •
•
•
•
•
•
•
•
•
•
•
•
•
•
•
Table 3 - Accessible measurement information and relay settings
• •
• • • • • •
• • • • •
• • • •
•
• • • • • •
•
•
•
•
•
P34x_P341/EN GS/J96 Page (GS) 3-11
(GS) 3 Getting Started Menu Structure
The menu is arranged in a table. Each setting in the menu is known as a cell, and each cell in the menu can be accessed using a row and column address. The settings are arranged so that each column contains related settings, for example all of the disturbance
recorder settings are contained within the same column. As shown in Figure 4, the top
row of each column contains the heading that describes the settings in that column. You can only move between the columns of the menu at the column heading level. For a complete list of all of the menu settings, see the Settings chapter and the Relay Menu
Database document.
4.1
Page (GS) 3-12
Figure 4 - Menu structure
The settings in the menu are in these categories:
protection
Disturbance Recorder settings
Control and Support (C&S) settings
New C&S settings are stored and used by the relay immediately after they are entered.
New Protection settings or disturbance recorder settings are stored in a temporary
‘scratchpad’. Once the new settings have been confirmed, the relay activates all the new settings together. This provides extra security so that several setting changes, made in a group of protection settings, all take effect at the same time.
Protection Settings
The protection settings include the following items:
Protection element settings
Scheme logic settings
P34x_P341/EN GS/J96
Menu Structure
4.2
4.3
(GS) 3 Getting Started
There are four groups of protection settings, with each group containing the same setting cells. One group of protection settings is selected as the active group, and is used by the protection elements.
Disturbance Recorder Settings
The disturbance recorder settings include the record duration and trigger position, selection of analog and digital signals to record, and the signal sources that trigger the recording.
Control and Support Settings
The control and support settings include:
Relay configuration settings
Open/close circuit breaker (may vary according to relay type/model)
CT & VT ratio settings
Reset
Active protection setting group
Password & language settings
Circuit breaker control & monitoring settings (may vary according to relay type/model)
Communications
Measurement
Event & fault record settings
User interface settings
Commissioning
P34x_P341/EN GS/J96 Page (GS) 3-13
(GS) 3 Getting Started Password Protection
The menu structure contains three access levels. The access level that is enabled determines which of the relay’s settings can be changed and is controlled by two different
passwords. The access levels are summarized in Table 4.
Set "Password
Control" Cell
To
"Access
Level" Cell
Displays
Operations
0 0 Read - Access to all settings, alarms, event records and fault records
Execute - Control Commands, e.g. circuit breaker open/close. Reset of fault and alarm conditions. Reset LEDs. Clearing of event and fault records
Edit - All other settings
1 1 Read - Access to all settings, alarms, event records and fault records
Execute - Control Commands, e.g. circuit breaker open/close. Reset of fault and alarm conditions. Reset LEDs. Clearing of event and fault records
Edit - All other settings
2 (Default) 2 (Default) Read - Access to all settings, alarms, event records and fault records
Execute - Control Commands, e.g. circuit breaker open/close. Reset of fault and alarm conditions. Reset LEDs. Clearing of event and fault records
Edit All other settings
Password type required
None
Level 1
Level 2
None
None
Level 2
None
None
None
Table 4 - Access levels
Each of the two passwords are four characters of upper-case text. The factory default for both passwords is AAAA. Each password is user-changeable once it has been correctly entered. To enter a password, either use the prompt when a setting change is attempted, or select System data > Password from the menu. The access level is independently enabled for each interface, therefore if level 2 access is enabled for the rear communication port, the front panel access remains at level 0 unless the relevant password is entered at the front panel.
The access level, enabled by the password, times out independently for each interface after a period of inactivity and reverts to the default level. If the passwords are lost, contact Schneider Electric with the relay’s serial number and an emergency password can be supplied. To find the current level of access enabled for an interface, select
System data > Access level . The access level for the front panel User Interface (UI) is one of the default display options.
The relay is supplied with a default access level of 2, so that no password is needed to change any of the relay settings. It is also possible to set the default menu access level to either level 0 or level 1, preventing write access to the relay settings without the correct password. The default menu access level is set in System data > Password control .
Page (GS) 3-14 P34x_P341/EN GS/J96
Relay Configuration (GS) 3 Getting Started
The relay is a multi-function device that supports numerous different protection, control and communication features. To simplify the setting of the relay, there is a configuration settings column which can be used to enable or disable many of the functions of the relay. The settings associated with any function that is disabled are not shown in the menu. To disable a function change the relevant cell in the Configuration column from
Enabled to Disabled .
The configuration column controls which of the four protection settings groups is selected as active through the Active settings cell. A protection setting group can also be disabled in the configuration column, provided it is not the present active group.
Similarly, a disabled setting group cannot be set as the active group.
P34x_P341/EN GS/J96 Page (GS) 3-15
(GS) 3 Getting Started
7
Front Panel User Interface (Keypad and LCD)
FRONT PANEL USER INTERFACE (KEYPAD AND LCD)
When the keypad is exposed it provides full access to the menu options of the relay, with the information displayed on the LCD. The and keys are used for menu navigation and setting value changes. These keys have an auto-repeat function if they are held continually. This can speed up both setting value changes and menu navigation: the longer the key is held pressed, the faster the rate of change or movement.
7.1
Page (GS) 3-16
Figure 5 - Front panel user interface
Default Display and Menu Time-Out
The front panel menu has a default display. To change it, select Measure’t. setup > default display and the following items can be selected:
Date and time
Relay description (user defined)
Plant reference (user defined)
System
3-phase
3-phase and neutral current
Power
Access
P34x_P341/EN GS/J96
Front Panel User Interface (Keypad and LCD)
7.2
7.3
7.3.1
(GS) 3 Getting Started
From the default display you can view the other default display options using the and keys. If there is no keypad activity for 15 minutes, the default display reverts to the previous setting and the LCD backlight switches off. Any setting changes that have not been confirmed are lost and the original setting values are maintained.
Whenever there is an uncleared alarm present in the relay (e.g. fault record, protection alarm, control alarm etc.) the default display will be replaced by:
Alarms/Faults
Present
Enter the menu structure of the relay from the default display, even if the display shows the Alarms/Faults present message.
Navigating Menus and Browsing the Settings
Use the four arrow keys to browse the menu, following the structure shown in Figure 5.
1. Starting at the default display, press the key to show the first column heading.
2. Use and keys to select the required column heading.
3. Use and keys to view the setting data in the column.
4. To return to the column header, either hold the key down or press the clear key
once. It is only possible to move across columns at the column heading level.
5. To return to the default display, press the key or the clear key from any of the column headings. If you use the auto-repeat function of the key, you cannot go straight to the default display from one of the column cells because the autorepeat stops at the column heading.
6. Press key again to go to the default display.
Navigating the Hotkey Menu
1. To access the hotkey menu from the default display, press the key directly below the HOTKEY text on the LCD.
2. Once in the hotkey menu, use the and keys to scroll between the available options, then use the hotkeys to control the function currently displayed.
If neither the or keys are pressed within 20 seconds of entering a hotkey submenu, the relay reverts to the default display.
3. Press the clear key to return to the default menu from any page of the hotkey menu.
The layout of a typical page of the hotkey menu is as follows:
The top line shows the contents of the previous and next cells for easy menu navigation
The center line shows the function
The bottom line shows the options assigned to the direct access keys
The functions available in the hotkey menu are listed below:
Setting Group Selection
To select the setting group, scroll through the available setting groups using NXT GRP , or press SELECT to select the setting group that is currently displayed.
P34x_P341/EN GS/J96 Page (GS) 3-17
(GS) 3 Getting Started
7.3.2
7.3.3
Front Panel User Interface (Keypad and LCD)
When you press SELECT , the current setting group appears for 2 seconds, then the
NXT GRP or SELECT options appear again.
To exit the sub menu, use the left and right arrow keys. For more information see
Changing setting groups in the Operation chapter.
Control Inputs - User Assignable Functions
The control inputs are user-assignable functions or USR ASS .
Use the CTRL I/P CONFIG column to configure the number of USR ASS shown in the hotkey menu. To SET/RESET the chosen inputs, use the HOTKEY menu.
For more information see the Control Inputs section in the Operation chapter.
CB Control
The CB control functionality varies from one relay to another (CB control is included in the
P341/P342/P343/P344/P345/P346). For a detailed description of the CB control via the hotkey menu refer to the “Circuit breaker control” section of the Operation chapter.
Page (GS) 3-18
Figure 6 - Hotkey menu navigation
P34x_P341/EN GS/J96
Front Panel User Interface (Keypad and LCD)
7.4
7.5
(GS) 3 Getting Started
Password Entry
1. When a password is required to edit a setting, an Enter password prompt appears.
Enter password
**** Level 1
2. A flashing cursor shows which character field of the password can be changed.
Press the and keys to change each character between A and Z.
3. Use and keys to move between the character fields of the password.
Press the enter key to confirm the password.
If an incorrect password is entered, the display reverts to Enter password . A message then appears indicating that the password is correct and if so what level of access has been unlocked. If this level is sufficient to edit the selected setting, the display returns to the setting page to allow the edit to continue. If the correct level of password has not been entered, the password prompt page appears again.
4. To escape from this prompt press the clear key . Alternatively, enter the password using System data > Password .
If the keypad is inactive for 15 minutes, the password protection of the front panel user interface reverts to the default access level.
5. To manually reset the password protection to the default level, select
System data > Password , then press the clear key instead of entering a password.
Reading and Clearing of Alarm Messages and Fault Records
One or more alarm messages appear on the default display and the yellow alarm LED flashes. The alarm messages can either be self-resetting or latched, in which case they must be cleared manually.
1. To view the alarm messages, press the read key . When all alarms have been viewed but not cleared, the alarm LED change from flashing to constantly ON and the latest fault record appears (if there is one).
2. Scroll through the pages of the latest fault record, using the key. When all pages of the fault record have been viewed, the following prompt appears.
Press clear to reset alarms
3. To clear all alarm messages, press . To return to the display showing alarms or faults present, and leave the alarms uncleared, press .
4. Depending on the password configuration settings, you may need to enter a
password before the alarm messages can be cleared. See section 5.
5. When all alarms are cleared, the yellow alarm LED switches OFF; also the red trip
LED switches OFF if it was switched ON after a trip.
6. To speed up the procedure, enter the alarm viewer using the key, then press the key. This goes straight to the fault record display. Press again to move straight to the alarm reset prompt, then press again to clear all alarms.
P34x_P341/EN GS/J96 Page (GS) 3-19
(GS) 3 Getting Started
7.6
Front Panel User Interface (Keypad and LCD)
Setting Changes
1. To change the value of a setting, go to the relevant cell in the menu, then press the enter key to change the cell value. A flashing cursor on the LCD shows the value can be changed. If a password is required to edit the cell value, a password prompt appears.
2. To change the setting value, press the or keys. If the setting to be changed is a binary value or a text string, select the required bit or character to be changed using the and keys.
3. Press to discard it. The new setting is automatically discarded if it is not confirmed in 15 seconds.
4. For protection group settings and disturbance recorder settings, the changes must be confirmed before they are used by the relay.
To do this, when all required changes have been entered, return to the column heading level and press the key. Before returning to the default display, the following prompt appears.
Update settings
Enter or clear
5. Press to discard the new settings.
Note If the menu time-out occurs before the setting changes have been confirmed, the setting values are also discarded.
Control and support settings are updated immediately after they are entered, without the Update settings prompt.
Page (GS) 3-20 P34x_P341/EN GS/J96
Front Communication Port User Interface (GS) 3 Getting Started
The front communication port is a 9-pin female D-type connector under the bottom hinged cover. It provides EIA(RS)232 serial data communication up to 15 m with a PC, see
Figure 7. This port supports the Courier communication protocol only. Courier is the
communication language developed by Schneider Electric to allow communication with its range of protection relays. The front port is intended for use with the relay settings program S1 Studio which runs on Windows TM 2000 or XP.
P34x_P341/EN GS/J96
Figure 7 - Front port connection
The relay is a Data Communication Equipment (DCE) device with the following pin connections on the 9-pin front port.
Pin number Description
3
5
Rx Receive data
0 V Zero volts common
Table 5 - Front port DCE pin connections
None of the other pins are connected in the relay. The relay should be connected to the
COM1 or COM2 serial port of a PC. PCs are normally Data Terminal Equipment (DTE) devices which have the following serial port pin connections (if in doubt check your PC manual):
2
Pin number
3
25-way
2
9-way Description x Receive data
5 7 5
Table 6 - DTE devices serial port pin connections
0 V Zero volts common
For successful data communication, connect the Tx pin on the relay to the Rx pin on the
PC, and the Rx pin on the relay to the Tx pin on the PC. Normally a straight-through serial cable is required, connecting pin 2 to pin 2, pin 3 to pin 3, and pin 5 to pin 5.
Note A common cause of difficulty with serial data communication is connecting
Tx to Tx and Rx to Rx. This could happen if a cross-over serial cable is used, connecting pin 2 to pin 3, and pin 3 to pin 2, or if the PC has the same pin configuration as the relay.
Page (GS) 3-21
(GS) 3 Getting Started Front Communication Port User Interface
Figure 8 - PC relay signal connection
Once the physical connection from the relay to the PC is made, the PC’s communication settings must be set to match those of the relay. The following table shows the relay’s communication settings for the front port.
Protocol
Baud rate
Courier address
Message format
Courier
19,200 bits/s
1
11 bit - 1 start bit, 8 data bits, 1 parity bit (even parity), 1 stop bit
Table 7 - Relay front port settings
If there is no communication using the front port for 15 minutes, any password access level that has been enabled is cancelled.
Page (GS) 3-22 P34x_P341/EN GS/J96
Front Communication Port User Interface
8.1
(GS) 3 Getting Started
Front Courier Port
The front EIA(RS)232 9-pin port supports the Courier protocol for one-to-one communication.
Note The front port is actually compliant to EIA(RS)574; the 9-pin version of
EIA(RS)232, see www.tiaonline.org
.
The front port is designed for use during installation and commissioning or maintenance, and is not suitable for permanent connection. Since this interface is not used to link the relay to a substation communication system, the following features of Courier are not used.
Automatic Extraction of Event Records:
Courier Status byte does not support the Event flag
Send Event or Accept Event commands are not implemented
Automatic Extraction of Disturbance Records:
Courier Status byte does not support the Disturbance flag
Busy Response Layer:
Courier Status byte does not support the Busy flag, the only response to a request will be the final data
Fixed
The address of the front courier port is always 1, the Change Device address command is not supported.
Fixed Baud Rate:
19200
Note Although automatic extraction of event and disturbance records is not supported, this data can be manually accessed using the front port.
P34x_P341/EN GS/J96 Page (GS) 3-23
(GS) 3 Getting Started
9
9.1
MiCOM S1 Studio Relay Communications Basics
MICOM S1 STUDIO RELAY COMMUNICATIONS BASICS
The EIA(RS)232 front communication port is intended for use with the relay settings program MiCOM S1 Studio. This program runs on Windows TM 2000, XP or Vista, and is the universal MiCOM IED Support Software used for direct access to all stored data in any MiCOM IED.
MiCOM S1 Studio provides full access to:
MiCOM Px10, Px20, Px30, Px40, Modulex series, K series, L series relays
MiCOM Mx20 measurements units
PC Requirements
To run MiCOM S1 Studio on a PC, the following requirements are advised:
Minimum
1 GHz processor
256 MB RAM
Windows TM 2000
Resolution 800 x 600 x 256 colors
1 GB free hard disk space
Recommended
2 GHz processor
1 GB RAM
Windows
TM
XP
Resolution 1024 x 768
5 GB free hard disk space
Microsoft TM Vista
2 GHz processor
1 GB RAM
5 GB free hard disk space
MiCOM S1 Studio must be started with Administrator rights
Page (GS) 3-24 P34x_P341/EN GS/J96
MiCOM S1 Studio Relay Communications Basics
9.2
9.3
(GS) 3 Getting Started
Connecting to the Relay using MiCOM S1 Studio
This section is intended as a quick start guide to using MiCOM S1 Studio and assumes you have a copy installed on your PC. See the MiCOM S1 Studio program online help for more detailed information.
1. Make sure the EIA(RS)232 serial cable is properly connected between the port on the front panel of the relay and the PC. start S1 Studio, select Programs > and navigate to > MiCOM S1
Studio > MiCOM S1 Studio .
3. Click Quick Connect tab and select Create a New System .
4. Check Path to System file is correct, then enter the name of the system in the
Name field. If you need to add a brief description of the system, use the Comment field.
5. Click .
6. Select the device type.
7. Select the communications port.
8. Once connected, select the language for the settings file, the device name, then click Finish . The configuration is updated.
9. In Studio Explorer window, select Device > Supervise Device … to control the relay directly.
Off-Line Use of MiCOM S1 Studio
MiCOM S1 Studio can also be used as an off-line tool to prepare settings, without access to the relay.
1. If creating a new system, in the Studio Explorer, select create new system. Then right-click the new system and select New substation .
2. Right-click the new substation and select New voltage level .
3. Then right-click the new voltage level and select New bay .
4. Then right-click the new bay and select New device .
You can add a device at any level, whether it is a system, substation, voltage or bay.
5. Select a device type from the list, then enter the relay type, such as P445. Click
Next .
6. Enter the full model number and click Next .
7. Select Language and Model , then click Next .
8. Enter a unique device name, then click Finish .
9. Right-click Settings folder and select New File . A default file 000 is added. file and select click Open . You can then edit the settings. See the
MiCOM S1 Studio program online help for more information.
P34x_P341/EN GS/J96 Page (GS) 3-25
(GS) 3 Getting Started
Notes:
MiCOM S1 Studio Relay Communications Basics
Page (GS) 3-26 P34x_P341/EN GS/J96
MiCOM P341 (ST) 4 Settings
P341/EN ST/G74
SETTINGS
CHAPTER 4
Page (ST) 4-1
(ST) 4 Settings
Hardware Suffix:
Software Version:
Connection Diagrams:
J (P341)
36 and 71 (with DLR)
10P341xx (xx = 01 to 12)
MiCOM P341 contents
Page (ST) 4-2 P341/EN ST/G74
MiCOM P341 contents (ST) 4 Settings
CONTENTS
Page (ST) 4-
1 Introduction
2 Relay Settings Configuration
3 Protection Settings
Power Protection (32R/32)/32L)
Phase Overcurrent Protection (50/51/46OC)
Sensitive Earth Fault / Restricted Earth Fault (50N/51N/67N/67W/64)
Residual Overvoltage (Neutral Voltage Displacement) (59N)
Rate of Change of Frequency Protection
Voltage Vector Shift Protection (
Δ
θ
Frequency Protection (81U/81O)
Circuit Breaker Fail and Undercurrent Function (50BF)
Sensitive Power Protection (32R/32O/32L)
Current Loop Inputs and Outputs (CLIO)
System Checks (Check Sync. Function)
4 Control And Support Settings
7
8
12
51
P341/EN ST/G74 Page (ST) 4-3
(ST) 4 Settings
Communication Settings for Courier Protocol
Communication Settings for MODBUS Protocol
Communication Settings for IEC 60870-5-103 Protocol
Communication Settings for DNP3.0 Protocol
Communication Settings for Ethernet Port
Rear Port 2 Connection Settings
Circuit Breaker Condition Monitor Setup
IED Configurator (for IEC 61850 Configuration)
FIGURES
Figure 1 - Illustration of Non Ferrous Layers for ACSR
TABLES
Table 1 - General configuration settings
Table 2 - System configuration settings
Table 3 - Power protection settings
Table 4 - Phase overcurrent protection settings
Table 5 - Thermal overload protection settings
Table 6 - Earth fault protection settings
Table 7 - Sensitive earth fault protection settings
Table 8 - Restricted earth fault protection settings
Table 9 - Residual overvoltage protection settings
Table 10 - df/dt Protection settings
Table 11 - Voltage vector shift protection settings
Table 12 - Reconnect delay settings
Table 13 - Under/Overvoltage protection settings
Table 14 - Frequency protection settings
Table 15 - CBF protection settings
Table 16 - VTS and CTS protection settings
Page (ST) 4-4
MiCOM P341 Figures
Page (ST) 4-
Page (ST) 4-
P341/EN ST/G74
MiCOM P341 Tables
Table 17 - Sensitive power protection settings
Table 18 - Dynamic rating protection settings
Table 19 - Input labels settings
Table 20 - Output labels settings
Table 21 - Current loop inputs and outputs settings
Table 22 - Current loop outputs units and setting range
Table 23 - System checks settings
Table 25 - View records settings
Table 30 - Circuit breaker condition menu
Table 31 - Circuit breaker control settings
Table 33 - CT and VT ratio settings
Table 34 - Record control menu
Table 35 - Disturbance record settings
Table 36 - Measurement setup settings
Table 37 - Communication settings for courier protocol
Table 38 - Communication settings for MODBUS protocol
Table 39 - Communication settings for IEC-103 protocol
Table 40 - Communication settings for DNP3.0 protocol
Table 41 - Ethernet port communication settings
Table 42 - Rear port connection settings
Table 43 - Commissioning tests menu cells
Table 44 - Circuit breaker condition monitoring menu
Table 45 - Opto inputs configuration settings
Table 46 - Control inputs settings
Table 47 - Control inputs configuration settings
Table 48 - Control input label settings
Table 49 - IEC-61850 IED configurator
(ST) 4 Settings
P341/EN ST/G74 Page (ST) 4-5
(ST) 4 Settings
Notes:
MiCOM P341 TablesIntroduction
Page (ST) 4-6 P341/EN ST/G74
MiCOM P341 TablesIntroduction (ST) 4 Settings
1 INTRODUCTION
The P341 must be configured to the system and application using appropriate settings.
In this chapter settings are described in sequence: protection settings, control and configuration settings and the disturbance recorder settings. The relay is supplied with a factory-set configuration of default settings.
P341/EN ST/G74 Page (ST) 4-7
(ST) 4 Settings MiCOM P341 TablesRelay Settings Configuration
2 RELAY SETTINGS CONFIGURATION
The relay is a multi-function device that supports numerous different protection, control and communication features. To simplify the setting of the relay, there is a configuration settings column which can be used to enable or disable many of the functions of the relay. The settings associated with any function that is disabled are made invisible; i.e. they are not shown in the menu. To disable a function change the relevant cell in the
Configuration
column from
Enabled
to
Disabled
.
The configuration column controls which of the four protection settings groups is selected as active through the
Active settings
cell. A protection setting group can also be disabled in the configuration column, provided it is not the present active group. Similarly, a disabled setting group cannot be set as the active group.
The configuration column also allows all of the setting values in one group of protection settings to be copied to another group.
To do this first set the
Copy from
cell to the protection setting group to be copied, then set the
Copy to
cell to the protection group where the copy is to be placed. The copied settings are initially placed in a temporary scratchpad and will only be used by the relay following confirmation.
To restore the default values to the settings in any protection settings group, set the
Restore Defaults
cell to the relevant group number. Alternatively it is possible to set the
Restore Defaults
cell to
All Settings
to restore the default values to all of the relay’s settings, not just the protection groups’ settings. The default settings are initially placed in the scratchpad and are only used by the relay after they have been confirmed.
Note That restoring defaults to all settings includes the rear communication port settings may result in communication via the rear port being disrupted if the new (default) settings do not match those of the master station.
Menu text
Restore Defaults
Default setting
No Operation
Available settings
No Operation
All Settings
Setting Group 1
Setting Group 2
Setting Group 3
Setting Group 4
Setting to restore a setting group to factory default settings.
Setting Group Select via Menu
Select via Menu
Select via PSL
Allows setting group changes to be initiated via 2 DDB signals in the programmable scheme logic or via the Menu settings.
Active Settings
Selects the active setting group.
Save Changes
Saves all relay settings.
Group 1
No Operation
Group 1, Group 2, Group 3, Group 4
No Operation, Save, Abort
Copy from Group 1
Allows displayed settings to be copied from a selected setting group.
Group 1, 2, 3, 4
Copy to No Operation
No Operation
Group 1, 2, 3, 4
Allows displayed settings to be copied to a selected setting group. (ready to paste).
Setting Group 1 Enabled Disabled, Enabled
To enable or disable Group 1 settings. If the setting group is disabled from the configuration, then all associated settings and signals are hidden, with the exception of this setting. (paste).
Setting Group 2 (as above) Disabled Disabled, Enabled
Page (ST) 4-8 P341/EN ST/G74
MiCOM P341 TablesRelay Settings Configuration (ST) 4 Settings
System Config
Menu text
Setting Group 3 (as above)
Setting Group 4 (as above)
Disabled
Disabled
Visible
Default setting Available settings
Disabled, Enabled
Disabled, Enabled
Invisible, Visible
Sets the System Config menu visible or invisible in the relay settings menu.
Power Enabled Disabled, Enabled
Enables (activates) or disables (turns off) the 3 phase Power Protection function, reverse power / low forward power / over power.
ANSI 32R/32LFP/32O.
Overcurrent Enabled Disabled, Enabled
Enables (activates) or disables (turns off) the Phase Overcurrent and NPS Overcurrent Protection function.
ANSI 50/51/67P, 46OC.
Thermal Overload Disabled
Enables (activates) or disables (turns off) the Thermal Overload Protection function.
ANSI 49.
Disabled, Enabled
Earth Fault Enabled
Enables (activates) or disables (turns off) the Earth Fault Protection function.
Disabled, Enabled
ANSI 50N/51N.
SEF/REF/SPower SEF/REF Disabled, SEF/REF, Sensitive Power
Enables (activates) or disables (turns off) the Sensitive Earth Fault or Restricted Earth Fault or Sensitive Power (1 Phase)
Protection (reverse power / low forward power / over power) function.
ANSI 50/51/67N, 64, 32R/32LFP/32O.
Residual O/V NVD Enabled Disabled, Enabled
Enables (activates) or disables (turns off) the Residual Overvoltage (Neutral Voltage Displacement) Protection function.
ANSI 59N. df/dt Enabled Disabled, Enabled
Enables (activates) or disables (turns off) the rate of change of frequency df/dt) Protection function.
ANSI 81R.
V Vector Shift Disabled Disabled, Enabled
Enables (activates) or disables (turns off) the Voltage Vector Shift Protection function.
Reconnect Delay Disabled
Enables (activates) or disables (turns off) the Reconnect Delay Protection function.
Disabled, Enabled
Volt Protection Enabled Disabled, Enabled
Enables (activates) or disables (turns off) the Voltage Protection (Under/Overvoltage and NPS Overvoltage) protection function.
ANSI 27/59/47.
Freq Protection Enabled Disabled, Enabled
Enables (activates) or disables (turns off) the Frequency Protection (Under/Overfrequency) protection function.
ANSI 81O/U.
CB Fail Disabled
Enables (activates) or disables (turns off) the Circuit Breaker Fail Protection function.
Disabled, Enabled
ANSI 50BF.
Supervision Disabled
Enables (activates) or disables (turns off) the Supervision (VTS&CTS) functions.
Disabled, Enabled
ANSI VTS/CTS.
Dynamic Rating Enabled
Enables (activates) or disables (turns off) the Dynamic Rating protection function.
Disabled, Enabled
P341/EN ST/G74 Page (ST) 4-9
(ST) 4 Settings MiCOM P341 TablesRelay Settings Configuration
Menu text Default setting
Input Labels Visible
Sets the Input Labels menu visible or invisible in the relay settings menu.
Output Labels Visible
Available settings
Invisible, Visible
Invisible, Visible
Sets the Output Labels menu visible or invisible in the relay settings menu.
CT & VT Ratios Visible Invisible, Visible
Sets the Current & Voltage Transformer Ratios menu visible in the relay settings menu.
Invisible, Visible Record Control Visible
Sets the Record Control menu visible or invisible in the relay settings menu
Disturb Recorder Visible
Sets the Disturbance Recorder menu visible or invisible in the relay settings menu
Invisible, Visible
Measure’t Setup Visible
Sets the Measurement Setup menu visible or invisible in the relay settings menu
Invisible, Visible
Comms Settings Visible Invisible, Visible
Sets the Communications Settings menu visible or invisible in the relay settings menu. These are the settings associated with the 1st and 2nd rear communications ports.
Commission Tests Visible Invisible, Visible
Sets the Commissioning Tests menu visible or invisible in the relay settings menu
Setting Values Primary
This affects all protection settings that are dependent upon CT and VT ratio’s.
Control Inputs Visible
Primary, Secondary
Invisible, Visible
Sets the Control Inputs menu visible or invisible in the relay settings menu
CLIO Inputs Enabled Disabled, Enabled
Enables (activates) or disables (turns off) the CLIO (Current Loop Input Output) Inputs function.
CLIO Outputs Enabled Disabled, Enabled
Enables (activates) or disables (turns off) the CLIO (Current Loop Input Output) Outputs function.
System Checks Disabled Disabled, Enabled
To enable (activate) or disable (turn off) the System Checks (Check Sync and Voltage Monitor) function.
ANSI 25.
Ctrl I/P Config Visible Invisible, Visible
Sets the Control Input Configuration menu visible or invisible in the relay settings menu
Ctrl I/P Labels Visible
Sets the Control Input Labels visible or invisible in the relay settings menu
Invisible, Visible
Direct Access Enabled
Enabled/Disabled/Hotkey Only/CB Cntrl
Only
Defines what controls are available via the direct access keys - Enabled (Hotkey and CB Control functions) / Hotkey Only
(Control Inputs and Setting group selection) / CB Cntrl Only (CB open/close).
IEC GOOSE Visible
Sets the IEC GOOSE menu visible or invisible in the relay settings menu
RP1 Read Only Disabled
Invisible, Visible
Disabled, Enabled
Enables (activates) or disables (turns off) the rear communications port 1 (RP1) Read Only function.
RP2 Read Only Disabled Disabled, Enabled
Enables (activates) or disables (turns off) the rear communications port 2(RP2) Read Only function.
NIC Read Only Disabled Disabled, Enabled
Enables (activates) or disables (turns off) the rear Ethernet communications port (NIC) Read Only function.
LCD Contrast 11 0-31
Page (ST) 4-10 P341/EN ST/G74
MiCOM P341 TablesRelay Settings Configuration (ST) 4 Settings
Menu text Default setting Available settings
Sets the LCD contrast. To confirm acceptance of the contrast setting the relay prompts the user to press the right and left arrow keys together instead of the enter key as an added precaution to someone accidentally selecting a contrast which leaves the display black or blank.
Note the LCD contrast can be set via the front port communications port with the S1 setting software if the contrast is set incorrectly such that the display is black or blank.
Table 1 - General configuration settings
P341/EN ST/G74 Page (ST) 4-11
(ST) 4 Settings MiCOM P341 TablesProtection Settings
The protection settings include all the following items that become active once enabled in the configuration column of the relay menu database:
Protection element settings.
Scheme logic settings.
There are four groups of protection settings, with each group containing the same setting cells. One group of protection settings is selected as the active group, and is used by the protection elements. The settings for group 1 only are shown below. The settings are discussed in the same order in which they are displayed in the menu.
3.1 System Config
A facility is provided in the P341 to maintain correct operation of all the protection functions even when the generator is running in a reverse phase sequence. This is achieved through user configurable settings available for the four setting groups.
Menu text Default setting
Min
Setting range
Max
Step size
GROUP 1: SYSTEM CONFIG
Phase Sequence
The Phase Sequence setting applies to a power system that has a permanent phase sequence of either ABC or ACB. It is also applicable for temporary phase reversal which affects all the 3 phase VTs and CTs.
VT Reversal
Standard ABC
No Swap
Standard ABC, Reverse ACB
No Swap, A-B Swapped, B-C Swapped, C-
A Swapped
N/A
N/A
The VT Reversal and CT Reversal settings apply to applications where some or all of the 3 phase voltage or current inputs are temporarily reversed, as in pump storage applications. The settings affect the order of the analogue channels in the relay and are set to emulate the order of the channels on the power system.
CT Reversal No Swap
No Swap, A-B Swapped, B-C Swapped, C-
A Swapped
N/A
As described above.
C/S Input A-N A-N, B-N, C-N, A-B, B-C, C-A
Selects the check synchronizing input voltage measurement.
C/S V Ratio Corr 1 0.5 2 0.001
Check synchronizing voltage ratio correction. This is used by the System Check function to provide the magnitude correction for the difference between main VT and C/S VT.
1 Main VT Vect Grp 0 0 11
This is used to provide vector correction for the phase shift between main VT and C/S VT.
Main VT Location Gen Gen, Bus
Selects the main voltage transformer location, Generator or Busbar.
Table 2 - System configuration settings
Page (ST) 4-12 P341/EN ST/G74
MiCOM P341 TablesProtection Settings (ST) 4 Settings
3.2 Power Protection (32R/32)/32L)
The 3-phase power protection included in the P341 relay provides two stages of power protection. Each stage can be independently selected as either reverse power, over power, low forward power or disabled. The direction of operation of the power protection, forward or reverse, can also be defined with the operating mode setting.
Menu text
GROUP1: POWER
Operating Mode
Power1 Function
Generating
Reverse
First stage power function operating mode.
Generating, Motoring
Operating mode of the power protection defining forward/reverse direction – Generating = forward power towards the busbar,
Motoring = forward power towards the machine. Assumes CT connections as per standard connection diagrams.
Disabled, Reverse, Low Forward, Over
–P>1 Setting
20 In W (Vn=100/120 V)
80 In W (Vn=380/480 V)
4 In W
(Vn=100/120 V)
16 In W
(Vn=380/480 V)
Pick-up setting for the first stage reverse power protection element.
300 In W (Vn=100/120
V)1200 In W
(Vn=380/480 V)
1 In W
(Vn=100/120 V)
4 In W
(Vn=380/480 V)
P<1 Setting
Pick-up setting for the first stage low forward power protection element.
P>1 Setting
Default setting
20 In W (Vn=100/120V)
80 In W (Vn=380/480 V)
120 In W
(Vn=100/120 V)
480 In W
(Vn=380/480 V)
Min
4 In W
(Vn=100/120 V)
16 In W
(Vn=380/480 V)
4 In W
(Vn=100/120 V)
16 In W
(Vn=380/480 V)
Setting range
300 In W
(Vn=100/120 V)
1200 In W
(Vn=380/480 V)
300 In W
Max
(Vn=100/120 V)
1200 In W
(Vn=380/480 V)
Step size
1 In W
(Vn=100/120 V)
4 In W
(Vn=380/480 V)
1 In W
(Vn=100/120 V)
4 In W
(Vn=380/480 V)
Pick-up setting for the first stage over power protection element.
Power1 Time Delay 5 s 0 s
Operating time-delay setting of the first stage power protection.
Power1 DO Timer 0 s 0 s
–P>2 Setting
20 In W (Vn=100/120 V)
80 In W (Vn=380/480 V)
4 In W
(Vn=100/120 V)
16 In W
(Vn=380/480 V)
Pick-up setting for the second stage reverse power protection element.
100 s
10 s
0 s
0.1 s
Drop-off time-delay setting of the first stage power protection.
P1 Poledead Inh Enabled Disabled, Enabled
If the setting is enabled, the relevant stage will become inhibited by the pole dead logic. This logic produces an output when it detects either an open circuit breaker via auxiliary contacts feeding the relay opto inputs or it detects a combination of both undercurrent and undervoltage on any one phase. It allows the power protection to reset when the circuit breaker opens to cater for line or bus side VT applications.
Power2 Function Low Forward
Second stage power function operating mode.
Disabled, Reverse, Low Forward, Over
300 In W
(Vn=100/120 V)
1200 In W
(Vn=380/480 V)
1 In W
(Vn=100/120 V)
4 In W
(Vn=380/480 V)
P<2 Setting
20 In W (Vn=100/120 V)
80 In W (Vn=380/480 V)
4 In W
(Vn=100/120 V)
16 In W
(Vn=380/480 V)
Pick-up setting for the second stage low forward power protection element.
300 In W
(Vn=100/120 V) 1200
In W (Vn=380/480 V)
1 In W
(Vn=100/120 V)
4 In W
(Vn=380/480 V)
P341/EN ST/G74 Page (ST) 4-13
(ST) 4 Settings MiCOM P341 TablesProtection Settings
Menu text
P>2 Setting
Default setting
120 In W
(Vn=100/120 V)
480 In W
(Vn=380/480 V)
Min
4 In W
(Vn=100/120 V)
16 In W
(Vn=380/480 V)
Setting range Step size
Max
300 In W
(Vn=100/120 V) 1200 In
W (Vn=380/480 V)
1 In W
(Vn=100/120 V)
4 In W
(Vn=380/480 V)
Pick-up setting for the second stage low forward power protection element.
Power2 Time Delay 5 s 0 s 100 s 0.1 s
Operating time-delay setting of the second stage power protection.
Power2 DO Timer 0 s 0 s
Drop-off time-delay setting of the second stage power protection.
P2 Poledead Inh Enabled Disabled, Enabled
10 s 0.1 s
If the setting is enabled, the relevant stage will become inhibited by the pole dead logic. This logic produces an output when it detects either an open circuit breaker via auxiliary contacts feeding the relay opto inputs or it detects a combination of both undercurrent and undervoltage on any one phase. It allows the power protection to reset when the circuit breaker opens to cater for line or bus side VT applications.
Table 3 - Power protection settings
3.3 Phase Overcurrent Protection (50/51/46OC)
The overcurrent protection included in the P341 relay provides four stage non-directional
/ directional three-phase overcurrent protection with independent time delay characteristics. All overcurrent and directional settings apply to all three phases but are independent for each of the four stages.
The first two stages of overcurrent protection have time-delayed characteristics which are selectable between Inverse Definite Minimum Time (IDMT), or Definite Time (DT). The third and fourth stages have definite time characteristics only.
The overcurrent protection menu also includes settings for four stages of non-directional / directional Negative Phase Sequence (NPS) overcurrent protection with independent definite time delay characteristics.
Menu text
GROUP 1: OVERCURRENT
PHASE O/C
Default setting
Sub Heading
Min.
Setting range
Max.
Step size
I>1 Function IEC S Inverse
Disabled, DT, IEC S Inverse, IEC V Inverse, IEC E Inverse,
UK LT Inverse, UK Rectifier, RI, IEEE M Inverse, IEEE V
Inverse, IEEE E Inverse, US Inverse, US ST Inverse
Tripping characteristic for the first stage overcurrent protection.
I>1 Direction Non-directional
Non-directional
Directional Fwd
Directional Rev
Direction of the first stage overcurrent protection.
I>1 Current Set 1 In
Pick-up setting for first stage overcurrent protection.
0.08 In 4.0 In
I>1 Time Delay 1 0 100
Operating time-delay setting for the definite time setting if selected for first stage element.
I>1 TMS 1 0.025
Time multiplier setting to adjust the operating time of the IEC IDMT characteristic.
1.2
0.01 In
0.01
0.025
Page (ST) 4-14 P341/EN ST/G74
MiCOM P341 TablesProtection Settings (ST) 4 Settings
Menu text Default setting
Min.
Setting range
I>1 Time Dial 1 0.01
Time multiplier setting to adjust the operating time of the IEEE/US IDMT curves.
100
Max.
10 I>1 K (RI) 1 0.1
Time multiplier setting to adjust the operating time for the RI curve.
I>1 Reset Char DT DT, Inverse
Type of reset/release characteristic of the IEEE/US curves.
I>1 tRESET 0 s
Reset/release time setting for definite time reset characteristic.
0 s 100 s
I>2 Function Disabled
Disabled, DT, IEC S Inverse,
IEC V Inverse, IEC E Inverse,
UK LT Inverse, UK Rectifier, RI,
IEEE M Inverse,
IEEE V Inverse, IEEE E Inverse,
US Inverse, US ST Inverse
Tripping characteristic for the second stage overcurrent protection.
I>2 Cells as for I>1 above
Setting the same as for the first stage overcurrent protection.
I>3 Status Disabled
Enable or disables the third stage overcurrent protection.
Disabled, Enabled
0.01
0.05
N/A
N/A
Step size
0.01 s
I>3 Direction Non-directional
Non-directional Directional Fwd
Directional Rev
Direction of the third stage overcurrent protection.
I>3 Current Set 20 In
Pick-up setting for third stage overcurrent protection.
I>3 Time Delay 0 s
0.08 In 32 In
0 s 100 s
Operating time-delay setting for third stage overcurrent protection.
I>4 Cells as for I>3 Above
Settings the same as the third stage overcurrent protection.
I> Char. Angle 45 –95° +95°
Relay characteristic angle setting used for the directional decision.
I> Function Link 1111
Bit 0 = VTS Blocks I>1
Bit 1 = VTS Blocks I>2
Bit 2 = VTS Blocks I>3
Bit 3 = VTS Blocks I>4.
N/A
0.01 In
0.01 s
1°
Logic Settings that determine whether blocking signals from VT supervision affect certain overcurrent stages.
VTS Block – only affects directional overcurrent protection. With the relevant bit set to 1, operation of the Voltage Transformer
Supervision (VTS), will block the stage. When set to 0, the stage will revert to Non-directional upon operation of the VTS.
NPS OVERCURRENT
I2>1 Status
Sub Heading
Disabled Disabled, Enabled N/A
Enables or disables the first stage negative phase sequence overcurrent protection.
I2>1Direction Non-directional
Non-directional
Directional Fwd
Directional Rev
Direction of the negative phase sequence overcurrent element.
I2>1 Current Set 0.2 In 0.08 In
Pick-up setting for the first stage negative phase sequence overcurrent protection.
I2>1 Time Delay 10 s 0 s
4 In
100 s
N/A
0.01 In
0.01 s
P341/EN ST/G74 Page (ST) 4-15
(ST) 4 Settings MiCOM P341 TablesProtection Settings
Menu text Default setting
Min.
Setting range
Max.
Operating time-delay setting for the first stage negative phase sequence overcurrent protection.
I2>2 Cells as for I>3 Above
I2> Char Angle –60° –95°
Relay characteristic angle setting used for the directional decision.
Step size
I2>3 Cells as for I>3 Above
I2>4 Cells as for I>3 Above
I2> V2pol Set
5 V (Vn=100/120 V)
20 V (Vn=380/480 V)
0.5 V
(Vn=100/120 V)
2 V
(Vn=380/480 V)
Minimum negative phase sequence voltage polarizing quantity for directional decision.
25 V
(Vn=100/120 V)
100 V
(Vn=380/480 V)
I2> VTS Block 1111
Bit 0 = VTS blocks I2>1
Bit 1 = VTS blocks I2>2
Bit 2 = VTS blocks I2>3
Bit 3 = VTS blocks I2>4
Logic settings that determine whether VT supervision blocks selected negative phase sequence overcurrent stages. With the relevant bit set to 1, operation of the Voltage Transformer Supervision (VTS), will block the stage. When set to 0, the stage will revert to Non-directional on operation of the VTS.
0.5 V
(Vn=100/120 V)
2 V
(Vn=380/480 V)
+95° 1°
Table 4 - Phase overcurrent protection settings
3.4 Thermal Overload (49)
The thermal overload function within the P341 relay is a single time constant thermal trip characteristic, dependent on the type of plant to be protected. It also includes a definite time alarm stage.
Menu text Default setting
GROUP 1: THERMAL OVERLOAD
IThermal Enabled
Enables or disables the Thermal Overload trip function.
Thermal I> 1.2 In
Min.
Setting range
Disabled, Enabled
Max.
Step size
0.5 In 2.5 In 0.01 In
Pick-up setting for thermal overload trip.
Thermal Alarm 90% 20% 100% 1%
Thermal state pick-up setting corresponding to a percentage of the trip threshold at which an alarm will be generated.
T-heating 60 mins 1 min 200 mins 1 min
Heating thermal time constant setting for the thermal overload characteristic.
T-cooling 60 mins 1 min
Cooling thermal time constant setting for the thermal overload characteristic.
200 mins 1 min
M Factor 0 0 10 1
I
The M factor setting is a constant that relates negative phase sequence current heating to positive sequence current heating, eq
= (I12 + M I22)0.5
Table 5 - Thermal overload protection settings
Page (ST) 4-16 P341/EN ST/G74
MiCOM P341 TablesProtection Settings (ST) 4 Settings
3.5 Earth Fault (50N/51N)
The earth fault protection included in the P341 relay provides four stage of non-directional
/ directional earth fault protection. The first and second stages have selectable IDMT or
DT characteristics, while the third and fourth stages are DT only. Each stage is selectable to be either non-directional, directional forward or directional reverse.
Menu text
GROUP 1: EARTH FAULT
IN> Input
Default setting
Derived
Min.
Setting range
Max.
Step size
IN>1 Function IEC S Inverse
Disabled, DT, IEC S Inverse, IEC V Inverse, IEC E Inverse,
UK LT Inverse, RI, IEEE M Inverse, IEEE V Inverse, IEEE E
Inverse, US Inverse, US ST Inverse, IDG
Tripping characteristic for the first stage earth fault protection.
IN>1 Direction Non-directional
Non-directional
Directional Fwd
Directional Rev
Direction of measurement for the first stage earth fault element.
IN>1 Current 0.2 In 0.08 In 4.0 In 0.01 In
Pick-up setting for the first stage earth fault protection.
IN>1 IDG Is
IN>1 Time Delay
1.5
1 s
1
0 s
Operating time-delay setting for the first stage definite time element.
4 0.1
Multiple of “IN>” setting for the IDG curve (Scandinavian) and determines the actual relay current threshold at which the element starts.
200 s 0.01 s
1.2 0.025 IN>1 TMS 1 0.025
Time multiplier setting to adjust the operating time of the IEC IDMT characteristic.
IN>1 Time Dial 1 0.01
Time multiplier setting to adjust the operating time of the IEEE/US IDMT curves.
100
N/A
0.1
IN>1 K (RI) 1
Time multiplier to adjust the operating time for the RI curve.
0.1 10 0.05
1 2 0.01
Minimum operating time at high levels of fault current for IDG curve.
DT, Inverse N/A IN>1 Reset Char. DT
Type of reset/release characteristic of the IEEE/US curves.
IN>1 tRESET 0 s 0 s 100 s 0.01 s
Reset/release time for definite time reset characteristic.
IN>2 Function Disabled
Tripping characteristic for the second stage earth fault element.
IN>2 Cells as for IN>1 Above
Disabled, DT, IEC S Inverse, IEC V Inverse, IEC E Inverse,
UK LT Inverse, RI, IEEE M Inverse, IEEE V Inverse, IEEE E
Inverse, US Inverse, US ST Inverse, IDG
IN>3 Status Disabled Disabled, Enabled N/A
Enables or disables the third stage definite time element. If the function is disabled, then all associated settings with the exception of this setting, are hidden.
IN>3 Direction Non-directional
Non-directional
Directional Fwd
Directional Rev
N/A
Direction of measurement for the third stage earth fault element.
P341/EN ST/G74 Page (ST) 4-17
(ST) 4 Settings MiCOM P341 TablesProtection Settings
Menu text Default setting
IN>3 Current 0. 5 In
Pick-up setting for third stage earth fault element.
0.08 In
Min.
Setting range
32 In
Max.
Step size
0.01 In
IN>3 Time Delay 0 s 0 s
Operating time delay setting for the third stage earth fault element.
200 s 0.01 s
IN>4 Cells as for IN>3 Above
IN> Func Link 1111
Bit 0 = IN>1 VTS Block
Bit 1 = IN>2 VTS Block
Bit 2 = IN>3 VTS Block
Bit 3 = IN>4 VTS Block.
Setting that determines whether VT supervision logic signals blocks the earth fault stage. With the relevant bit set to 1, operation of the Voltage Transformer Supervision (VTS), will block the stage. When set to 0, the stage will revert to Nondirectional upon operation of the VTS.
IN> DIRECTIONAL
IN> Char. Angle –60°
Relay characteristic angle used for the directional decision.
–95° +95°
IN>Pol Zero Sequence
Zero Sequence or
Neg. Sequence
Selection of zero sequence or negative sequence voltage polarizing for directional earth fault protection.
1°
N/A
IN> VNpol Input Measured
Residual/neutral voltage (Zero sequence) polarization source.
Measured, Derived
IN>VNpol Set
5 V
(Vn=100/120 V)
20 V
(Vn=380/480 V)
0.5 V
(Vn=100/120 V)
2 V
(Vn=380/480 V)
Minimum zero sequence voltage polarizing quantity for the directional decision
IN>V2pol Set
0.5 V
(Vn=100/120 V)
2 V
(Vn=380/480 V)
0.5 V
(Vn=100/120 V)
2 V
(Vn=380/480 V)
Minimum negative sequence voltage polarizing quantity for the directional decision.
IN>I2pol Set 0.08 In 0.08 In
80 V
(Vn=100/120 V)
320 V
(Vn=380/480 V)
25 V
(Vn=100/120 V)
100 V
(Vn=380/480 V)
1 In
Minimum negative sequence current polarizing quantity for the directional decision.
0.5 V
(Vn=100/120 V)
2 V
(Vn=380/480 V)
0.5 V
(Vn=100/120 V)
2 V
(Vn=380/480 V)
0.01 In
Table 6 - Earth fault protection settings
Page (ST) 4-18 P341/EN ST/G74
MiCOM P341 TablesProtection Settings (ST) 4 Settings
3.6 Sensitive Earth Fault / Restricted Earth Fault (50N/51N/67N/67W/64)
If a system is earthed through a high impedance, or is subject to high ground fault resistance, the earth fault level will be severely limited. Consequently, the applied earth fault protection requires both an appropriate characteristic and a suitably sensitive setting range in order to be effective. A separate single stage sensitive earth fault element is provided within the P341 relay for this purpose, which has a dedicated input. This input may be configured to be used as a REF input. The REF protection in the relay may be configured to operate as either a high impedance or biased element.
Note The high impedance REF element of the relay shares the same sensitive current input as the SEF protection and sensitive power protection.
Therefore only one of these elements may be selected. However, the low impedance REF element does not use the SEF input and so may be selected at the same time.
Menu Text Default setting
Min.
Direction of measurement for the first stage sensitive earth fault element.
ISEF>1 Current 0.05 In 0.005 In
Pick-up setting for the first stage sensitive earth fault element.
Setting range
Max.
GROUP 1: SEF/REF PROT'N
SEF/REF Options SEF SEF, SEF cos (PHI), SEF sin (PHI), Wattmetric, Hi Z REF
Setting to select the type of sensitive earth fault protection function and the type of high-impedance function to be used. If the function is not selected, then all associated settings and signals are hidden, with the exception of this setting.
ISEF>1 Function DT
Disabled, DT, IEC S Inverse, IEC V Inverse, IEC E inverse, UK
LT Inverse IEEE M Inverse, IEEE V Inverse, IEEE E Inverse, US
Inverse, US ST Inverse, IDG,
Tripping characteristic for the first stage sensitive earth fault element.
ISEF>1 Direction Non-directional
Non-directional
Direction Fwd
Direction Rev
N/A
0.1 In
Step size
0.00025 In
ISEF>1 IDG Is 1.5 1 4 0.1
Multiple of “ISEF>” setting for the IDG curve (Scandinavian) and determines the actual relay current threshold at which the element starts.
200 s 0.01 s ISEF>1 Delay 1 s 0 s
Operating time delay setting for the first stage definite time element.
ISEF>1 TMS 1 0.025
Time multiplier to adjust the operating time of the IEC IDMT characteristic.
1.2 0.005
ISEF>1 Time Dial 1 0.1
Time multiplier to adjust the operating time of the IEEE/US IDMT curves.
ISEF>1 IDG Time 1.2 1
100
2
Setting for the IDG curve used to set the minimum operating time at high levels of fault current.
ISEF>1 Reset Char. DT DT, Inverse
Setting to determine the type of reset/release characteristic of the IEEE/US curves.
ISEF>1 tRESET 0 s 0 s 100 s
0.1
0.01
N/A
0.01 s
Reset/release time for definite time reset characteristic.
ISEF>2 Function Disabled
Disabled, DT, IEC S Inverse, IEC V Inverse, IEC E inverse, UK
LT Inverse IEEE M Inverse, IEEE V Inverse, IEEE E Inverse, US
Inverse, US ST Inverse, IDG,
Tripping characteristic for the first stage sensitive earth fault element.
P341/EN ST/G74 Page (ST) 4-19
(ST) 4 Settings MiCOM P341 TablesProtection Settings
Menu Text
ISEF>2 Cells as for ISEF>1
Above
Default setting
Min.
ISEF>3 Status Disabled Disabled, Enabled
Enables or disables the third stage definite time sensitive earth fault element.
ISEF>3 Direction Non-directional
Non-directional
Directional Fwd
Directional Rev
Direction of measurement for the third stage element.
ISEF>3 Current 0.4 In 0.005 In
Pick-up setting for the third stage sensitive earth fault element.
Setting range
Max.
0.8 In
ISEF DIRECTIONAL
ISEF> Char. Angle
Sub-heading in menu
90°
Relay characteristic angle used for the directional decision.
ISEF>VNpol Input Measured
–95° +95°
ISEF>VNpol Set
5 V (Vn=100/120 V)
20 V
(Vn=380/480 V)
Measured, Derived
0.5 V
(Vn=100/120 V)
2 V
(Vn=380/480 V)
80 V
(Vn=100/120 V)
320 V
(Vn=380/480 V)
Minimum zero sequence voltage polarizing quantity required for the directional decision.
WATTMETRIC SEF Sub-heading in menu
PN> Setting
9 In W
(Vn=100/120 V)
36 In W
(Vn=380/480 V)
0 W
20 In W
(Vn=100/120 V)
80 In W
(Vn=380/480 V)
N/A
N/A
1°
Step size
0.001 In
ISEF>3 Time Delay 0.5 s 0 s
Operating time delay setting for third stage sensitive earth fault element.
ISEF>4 Status Disabled Disabled, Enabled
Enables or disables the third stage definite time sensitive earth fault element.
ISEF>4 Direction Non-directional
Non-directional
Directional Fwd
Directional Rev
Direction of measurement for the third stage element.
ISEF>4 Current 0.6 In 0.005 In
200 s 0.01 s
N/A
N/A
0.8 In 0.001 In
Pick-up setting for the third stage sensitive earth fault element.
ISEF>3 Time Delay 0.25 s 0 s 200 s
Operating time delay for third stage sensitive earth fault element.
ISEF> Func. Link 0001
Bit 0 = ISEF>1 VTS Block
Bit 1 = ISEF>2 VTS Block
Bit 2 = ISEF>3 VTS Block
Bit 3 = ISEF>4 VTS Block.
0.01 s
Setting that determines whether VT supervision logic signals blocks the sensitive earth fault stage. With the relevant bit set to 1, operation of the Voltage Transformer Supervision (VTS), will block the stage. When set to 0, the stage will revert to Nondirectional upon operation of the VTS.
0.5 V
(Vn=100/120 V)
2 V
(Vn=380/480 V)
0.05 In W
(Vn=100/120 V)
0.2 In W
(Vn=380/480 V)
Page (ST) 4-20 P341/EN ST/G74
MiCOM P341 TablesProtection Settings (ST) 4 Settings
Menu Text Default setting
Min.
Setting range
Max.
Step size
Setting for the threshold for the wattmetric component of zero sequence power. The power calculation is as follows:
The PN> setting corresponds to:
Vres x Ires x Cos ( - c) = 9 x Vo x Io x Cos ( - c)
Where:
= Angle between the Polarizing Voltage (-Vres) and the Residual Current
c = Relay Characteristic Angle (RCA) Setting (ISEF> Char Angle)
Vres = Residual Voltage
Ires = Residual Current
Vo = Zero Sequence Voltage
Io = Zero Sequence Current
Table 7 - Sensitive earth fault protection settings
For the Hi Z REF option, the following settings are available:
Min.
Setting range
Max.
Step size Menu text Default setting
RESTRICTED E/F
IREF> Is
Sub-heading in menu
0.2 In
Pick-up setting for the high impedance REF protection.
Table 8 - Restricted earth fault protection settings
0.05 In 1.0 In 0.01 In
3.7 Residual Overvoltage (Neutral Voltage Displacement) (59N)
The Neutral Voltage Displacement (NVD) element within the P341 relay is of two-stage design, each stage having separate voltage and time delay settings. Stage 1 may be set to operate on either an IDMT or DT characteristic, while stage 2 may be set to DT only.
Menu text
GROUP 1: RESIDUAL O/V NVD
VN>1 Status Enabled
Default setting
Min.
Setting range
Disabled, Enabled
Enables or disables the VN>1 trip stage.
VN>1 Input Derived N/A
VN>1 uses derived neutral voltage from the 3 phase voltage input (VN = VA+VB+VC).
VN>1 Function DT Disabled, DT, IDMT
Max.
Tripping characteristic setting of the first stage residual overvoltage element.
VN>1 Voltage Set
5 V
(Vn=100/120 V)
20 V
(Vn=380/480 V)
1 V
(Vn=100/120 V)
4 V
(Vn=380/480 V)
80 V
(Vn=100/120 V)
320 V
(Vn=380/480 V)
Pick-up setting for the first stage residual overvoltage characteristic.
VN>1 Time Delay 5 s 0 s 100 s
Operating time delay setting for the first stage definite time residual overvoltage element.
VN>1 TMS 1 0.5 100
N/A
N/A
1 V
(Vn=100/120 V)
4 V
(Vn=380/480 V)
0.5
Step size
0.01 s
P341/EN ST/G74 Page (ST) 4-21
(ST) 4 Settings MiCOM P341 TablesProtection Settings
Menu text Default setting
Min.
Setting range
Max.
Setting for the time multiplier setting to adjust the operating time of the IDMT characteristic.
The characteristic is defined as follows: t = K / ( M – 1) where: K t
M
VN>1 tReset
=
=
=
Time multiplier setting
Operating time in seconds
Derived residual voltage/relay setting voltage (VN> Voltage Set)
0 s 0 s
Reset/release definite time setting for the first stage characteristic.
100 s
VN>2 Status Disabled Disabled, Enabled
Enables or disables the second stage residual overvoltage element.
VN>2 Input Derived N/A
VN>2 uses derived neutral voltage from the 3 phase voltage input (VN = VA+VB+VC).
VN>2 Function DT Disabled, DT, IDMT
Tripping characteristic setting of the first stage residual overvoltage element.
VN>2 Voltage Set
10 V
(Vn=100/120 V)
40 V
(Vn=380/480 V)
1 V
(Vn=100/120 V)
4 V
(Vn=380/480 V)
80 V
(Vn=100/120 V)
320 V
(Vn=380/480 V)
Pick-up setting for the first stage residual overvoltage characteristic.
VN>2 Time Delay 10 s 0 s 100 s
Operating time delay setting for the first stage definite time residual overvoltage element.
VN>2 TMS 1 0.5 100
Time multiplier setting to adjust the operating time of the IDMT characteristic.
The characteristic is defined as above
VN>2 tReset 0 s 0 s
Reset/release definite time setting for the first stage characteristic.
100 s
VN>3 Status Disabled
Enables or disables the third stage residual overvoltage element.
Disabled, Enabled
VN>3 Input VN1 N/A
VN>3 uses measured neutral voltage from the Vneutral/VN1 input.
VN>3 cells as for VN>1 above
VN>4 Status Disabled Disabled, Enabled
Enables or disables the fourth stage residual overvoltage element.
VN>4 Input VN1 N/A
VN>4 uses measured neutral voltage from the Vneutral/VN1 input.
VN>4 cells as for VN>2 above
Table 9 - Residual overvoltage protection settings
Step size
0.01 s
N/A
N/A
N/A
1 V
(Vn=100/120 V)
4 V
(Vn=380/480 V)
0.01 s
0.5
0.01 s
N/A
N/A
N/A
N/A
Page (ST) 4-22 P341/EN ST/G74
MiCOM P341 TablesProtection Settings (ST) 4 Settings
3.8 Rate of Change of Frequency Protection
Four stages of df/dt protection are included in P34x. The first stage, df/dt>1 is designed for loss of grid applications but it can also be used for load shedding. For the first stage only, the user can select a deadband around the nominal frequency, within which this element is blocked. The dead band is defined with high and low frequency settings df/dt>1 f Low
and df/dt> f High
. The deadband is eliminated if the high and low frequencies are set the same or the df/dt> f L/H
setting is set to
Disabled
. The deadband provides additional stability for non loss of grid disturbances which do not affect the machine frequency significantly. Each stage has a direction setting df/dt>n Dir’n – Negative, Positive,
Both
. This setting determines whether the element will react to rising or falling frequency conditions respectively, with an incorrect setting being indicated if the threshold is set to zero. For loss of mains applications the df/dt>1 Dir’n
should be set to
Both
to match the previous P341 algorithm.
Some global df/dt settings affect all protection stages. These can be used to smooth out the frequency measurements and provide stable operation of the protection, df/dt avg cycles
and df/dt iterations
. These settings enable the user to select the number of cycles the frequency is averaged over and the number of iterations of the averaged cycles before a start is given. Two
Operating Mode
settings are provided:
Fixed Window
and
Rolling Window
. The
Fixed Window
setting is provided for compatibility with the previous
P341 df/dt function which used two consecutive calculations of a 3 cycle fixed window to initiate a start.
Menu text Default setting
Min.
Setting range
Max.
GROUP 1 DF/DT
Operating Mode Fixed Window Fixed Window, Rolling Window
Selects the algorithm method, Fixed or Rolling Window, used for df/dt calculation. df/dt Avg. Cycles 3 2 12
Step size
1
Sets the number of power system cycles that are used to average the rate of change of frequency measurement. df/dt Iterations 2 1 4 1
Sets the number of iterations of the df/dt protection element to obtain a start signal. For example if
Operating Mode
is
Fixed
Window and df/dt Avg Cycles = 3 and df/dt Iterations = 2 then df/dt start will be after 2 consecutive 3 cycle windows above setting.
Disabled, Enabled df/dt>1 Status Enabled
Setting to enable or disable the first stage df/dt element. df/dt>1 Setting 0.2 Hz/s
Pick-up setting for the first stage df/dt element.
100.0 mHz/s 10 Hz/s 10 mHz/s df/dt>1 Dir'n. Both Negative, Positive, Both N/A
This setting determines whether the element will react to rising or falling frequency conditions respectively, with an incorrect setting being indicated if the threshold is set to zero. df/dt>1 Time 500.0 ms
Operating time-delay setting for the first stage df/dt element.
0 100 10 ms df/dt>1 f L/H df/dt>1 f Low
Enabled
49.5 Hz
Setting for the df/dt>1 low frequency blocking.
Disabled, Enabled
Enables or disables the low and high frequency block function for the first stage of df/dt protection. The df/dt>1 stage is blocked if the frequency is in the deadband defined by the df/dt>1 F Low and df/dt>1 F High setting. This is typically required for loss of grid applications.
45 Hz 65 Hz 0.01 Hz df/dt>1 f High 50.5 Hz 45 Hz 65 Hz 0.01 Hz
Setting for the df/dt>1 high frequency blocking.
P341/EN ST/G74 Page (ST) 4-23
(ST) 4 Settings MiCOM P341 TablesProtection Settings
Menu text Default setting df/dt>2 Status Enabled
Setting to enable or disable the first stage df/dt element. df/dt>2 Setting 2.000 Hz/s
Pick-up setting for the first stage df/dt element. df/dt>2 Dir'n. Positive
Min.
100.0 mHz/s
Setting range
Disabled, Enabled
Max.
10 Hz/s
Step size
10 mHz/s
Negative, Positive, Both N/A
This setting determines whether the element will react to rising or falling frequency conditions respectively. df/dt>2 Time 500.0 ms 0 100 10 ms
Operating time-delay setting for the second stage df/dt element. df/dt>3 Status
(same as stage2)
Enabled Disabled, Enabled df/dt>4 Status
(same as stage2)
N/A
Table 10 - df/dt Protection settings
3.9 Voltage Vector Shift Protection (
Δ
V
θ
)
The P341 provides one stage of voltage vector protection (df/dt+t). This element detects the fluctuation in voltage angle that will occur as the machine adjusts to the new load conditions following loss of the grid.
Min.
Setting Range
Max.
Step Size Menu Text
GROUP 1: V VECTOR SHIFT
Default Setting
V Shift Status Enabled
Enables or disables the Voltage Vector Shift element.
V Shift Angle 10º
Pick-up angle setting for the Voltage Vector Shift element.
Table 11 - Voltage vector shift protection settings
Disabled, Enabled
2º 30º
N/A
1º
Page (ST) 4-24 P341/EN ST/G74
MiCOM P341 TablesProtection Settings (ST) 4 Settings
3.10 Reconnect Delay (79)
To minimize the disruption caused by a loss of mains trip, the P341 includes a reconnection timer. This timer is initiated following operation of any protection element that could operate due to a loss of mains event, i.e. df/dt, voltage vector shift, under/overfrequency, power and under/overvoltage. The timer is blocked should a short circuit fault protection element operate, i.e. residual overvoltage, overcurrent, and earth fault. Once the timer delay has expired the element provides a pulsed output signal.
This signal can be used to initiate external synchronizing equipment that can resynchronies the machine with the system and reclose the CB.
Menu Text Default Setting
GROUP 1: RECONNECT DELAY
Reconnect Status Enabled
Enables or disables the Reconnect Status element.
Reconnect Delay 60 s
Operating time-delay setting for the Reconnect element.
Reconnect tPULSE 1 s
Reconnect element output pulse duration.
Table 12 - Reconnect delay settings
Min.
Setting Range
Max.
Disabled, Enabled
0 s
0.01 s
300 s
30 s
N/A
Step Size
0.01 s
0.01 s
P341/EN ST/G74 Page (ST) 4-25
(ST) 4 Settings MiCOM P341 TablesProtection Settings
3.11 Voltage Protection (27/59/47)
The undervoltage and overvoltage protection included within the P341 relay consists of two independent stages. Two stages are included to provide both alarm and trip stages, where required. These are configurable as either phase to phase or phase to neutral measuring. The undervoltage stages may be optionally blocked by a pole dead (CB
Open) condition.
The first stage of under/overvoltage protection has a time-delayed characteristics which is selectable between Inverse Definite Minimum Time (IDMT), or Definite Time (DT). The second stage is definite time only.
Negative phase sequence overvoltage protection is also included with a definite time delay.
Menu text Default setting
GROUP 1: VOLT PROTECTION
UNDERVOLTAGE Sub-heading
Min.
Setting range
Max.
Step size
V< Measur't. Mode Phase-Neutral
Phase-Phase
Phase-Neutral
N/A
Sets the measured input voltage, phase-phase or phase-neutral, that will be used for the undervoltage elements.
V< Operate Mode Any Phase
Any Phase
Three Phase
N/A
Setting that determines whether any phase or all three phases has to satisfy the undervoltage criteria before a decision is made.
V<1 Function DT
Disabled,
DT,
IDMT
N/A
Tripping characteristic for the first stage undervoltage function.
The IDMT characteristic available on the first stage is defined by the following formula: t = K / (1 - M)
Where:
K = Time multiplier setting t = Operating time in seconds
M = Measured voltage/relay setting voltage (V< Voltage Set)
V<1 Voltage Set
50 V
(Vn=100/120 V)
200 V
(Vn=380/480 V)
10 V
(Vn=100/120 V)
40 V
(Vn=380/480 V)
120 V
(Vn=100/120 V)
480 V
(Vn=380/480 V)
Pick-up setting for first stage undervoltage element.
V<1 Time Delay 10 s 0 s
Operating time-delay setting for the first stage definite time undervoltage element.
100 s
1 V
(Vn=100/120 V)
4 V
(Vn=380/480 V)
0.01 s
V<1 TMS 1 0.05
Time multiplier setting to adjust the operating time of the IDMT characteristic.
V<1 Poledead Inh Enabled Disabled, Enabled
100 0.05
N/A
If the setting is enabled, the relevant stage will become inhibited by the pole dead logic. This logic produces an output when it detects either an open circuit breaker via auxiliary contacts feeding the relay opto inputs or it detects a combination of both undercurrent and undervoltage on any one phase. It allows the undervoltage protection to reset when the circuit breaker opens to cater for line or bus side VT applications
V<2 Status Disabled Disabled, Enabled N/A
Enables or disables the second stage undervoltage element.
Page (ST) 4-26 P341/EN ST/G74
MiCOM P341 TablesProtection Settings (ST) 4 Settings
Menu text
V<2 Voltage Set
Default setting
38 V
(Vn=100/120 V)
152 V
(Vn=380/480 V)
Pick-up setting for second stage undervoltage element.
V<2 Time Delay 5 s 0 s
Min.
Setting range
10 V
(Vn=100/120 V)
40 V
(Vn=380/480 V)
120 V
Max.
(Vn=100/120 V)
480 V
(Vn=380/480 V)
100 s
1 V
Step size
(Vn=100/120 V)
4 V
(Vn=380/480 V)
0.01 s
Operating time-delay setting for the second stage definite time undervoltage element.
V<2 Poledead Inh Enabled Disabled, Enabled N/A
If the setting is enabled, the relevant stage will become inhibited by the pole dead logic. This logic produces an output when it detects either an open circuit breaker via auxiliary contacts feeding the relay opto inputs or it detects a combination of both undercurrent and undervoltage on any one phase. It allows the undervoltage protection to reset when the circuit breaker opens to cater for line or bus side VT applications.
OVERVOLTAGE Sub-heading
V> Measur't. Mode Phase-Phase
Phase-Phase
Phase-Neutral
N/A
Sets the measured input voltage, phase-phase or phase-neutral that will be used for the overvoltage elements.
V> Operate Mode Any Phase
Any Phase,
Three Phase
N/A
Setting that determines whether any phase or all three phases has to satisfy the overvoltage criteria before a decision is made.
V>1 Function DT
Disabled,
DT,
IDMT
N/A
Tripping characteristic setting for the first stage overvoltage element.
The IDMT characteristic available on the first stage is defined by the following formula: t = K / (M - 1)
Where:
K = Time multiplier setting t = Operating time in seconds
M = Measured voltage/relay setting voltage (V<>Voltage Set)
V>1 Voltage Set
130 V
(Vn=100/120 V)
520 V
(Vn=380/480 V)
60 V
(Vn=100/120 V)
240 V
(Vn=380/480 V)
185 V
(Vn=100/120 V)
740 V
(Vn=380/480 V)
Pick-up setting for first stage overvoltage element.
V>1 Time Delay 10 s 0 s
Operating time-delay setting for the first stage definite time overvoltage element.
100 s
V>1 TMS 1 0.05
Time multiplier setting to adjust the operating time of the IDMT characteristic.
V>2 Status Disabled Disabled, Enabled
100
1 V
(Vn=100/120 V)
4 V
(Vn=380/480 V)
0.01 s
0.05
N/A
Enables or disables the second stage overvoltage element.
V>2 Voltage Set
150 V
(Vn=100/120 V)
600 V
(Vn=380/480 V)
60 V
(Vn=100/120 V)
240 V
(Vn=380/480 V)
Pick-up setting for the second stage overvoltage element.
V>2 Time Delay 0.5 s 0 s
Operating time-delay setting for the second stage definite time overvoltage element.
NPS OVERVOLTAGE
V2> status
Sub-heading
Enabled Disabled, Enabled
185 V
(Vn=100/120 V)
740 V
(Vn=380/480 V)
100 s
1 V
(Vn=100/120 V)
4 V
(Vn=380/480 V)
0.01 s
N/A
P341/EN ST/G74 Page (ST) 4-27
(ST) 4 Settings MiCOM P341 TablesProtection Settings
Menu text Default setting
Min.
Setting range
Max.
Enables or disables the definite time negative sequence overvoltage element.
V2>1 Voltage Set
15 V
(Vn=100/120 V)
60 V
(Vn=380/480 V)
Pick-up setting for the negative sequence overvoltage element.
1 V
(Vn=100/120 V)
4 V
(Vn=380/480 V)
150 V
(Vn=100/120 V)
600 V
(Vn=380/480 V)
V2> Time Delay 1 s 0 s 100 s
Operating time delay setting for the definite time negative sequence overvoltage element.
Table 13 - Under/Overvoltage protection settings
Step size
1 V
(Vn=100/120 V)
4 V
(Vn=380/480 V)
0.01 s
Page (ST) 4-28 P341/EN ST/G74
MiCOM P341 TablesProtection Settings (ST) 4 Settings
3.12 Frequency Protection (81U/81O)
The P341 relay includes 4 stages of underfrequency and 2 stages of overfrequency protection to facilitate load shedding and subsequent restoration. The underfrequency stages may be optionally blocked by a pole dead (CB Open) condition.
Menu text
GROUP 1: FREQ. PROTECTION
Default setting
Min.
Setting range
UNDERFREQUENCY
F<1 Status Enabled
Enables or disables the first stage underfrequency element.
F<1 Setting 49.5 Hz
F<2 Status Disabled
Enables or disables the second stage underfrequency element.
F<2 Setting 49 Hz
Pick-up setting for the second stage underfrequency element.
Disabled, Enabled
45 Hz
Pick-up setting for the first stage underfrequency element.
F<1 Time Delay 4 s 0 s
Operating time-delay setting for the definite time first stage underfrequency element.
Disabled, Enabled
45 Hz
65 Hz
100 s
65 Hz
Max.
N/A
N/A
Step size
0.01 Hz
0.01 s
0.01 Hz
F<2 Time Delay 3 s 0 s 100 s
Operating time-delay setting for the definite time second stage underfrequency element.
F<3 Status Disabled
Enables or disables the third stage underfrequency element.
Disabled, Enabled
45 Hz 65 Hz F<3 Setting 48.5 Hz
Pick-up setting for the third stage underfrequency element.
F<3 Time Delay 2 s 0 s 100 s
0.01 s
N/A
0.01 Hz
0.01 s
Operating time-delay setting for the definite time third stage underfrequency element.
F<4 Status Disabled Disabled, Enabled
Enables or disables the fourth stage underfrequency element.
F<4 Setting 48 Hz 45 Hz 65 Hz
N/A
0.01 Hz
Pick-up setting for the fourth stage underfrequency element.
F<4 Time Delay 1 s 0 s
Operating time-delay setting for the definite time fourth stage underfrequency element.
100 s
F< Function Link 0000
Bit 0 = F<1 Poledead Blk
Bit 1 = F<2 Poledead Blk
Bit 2 = F<3 Poledead Blk
Bit 3 = F<4 Poledead Blk
Settings that determines whether pole dead logic signals blocks the underfrequency elements.
0.01 s
N/A
With the relevant bit set to 1, the relevant underfrequency stage will become inhibited by the pole dead logic. This logic produces an output when it detects either an open circuit breaker via auxiliary contacts feeding the relay opto inputs or it detects a combination of both undercurrent and undervoltage on any one phase. It allows the underfrequency protection to reset when the circuit breaker opens to cater for line or bus side VT applications.
OVERFREQUENCY
F>1 Status Enabled
Enables or disables the first stage overfrequency element.
F>1 Setting 50.5 Hz
Pick-up setting for the first stage overfrequency element.
Disabled, Enabled
45 Hz 68 Hz
N/A
0.01 Hz
P341/EN ST/G74 Page (ST) 4-29
(ST) 4 Settings MiCOM P341 TablesProtection Settings
Menu text Default setting
F>1 Time Delay 2 s 0 s
Operating time-delay setting for the first stage overfrequency element.
Min.
Setting range
F>2 Status Disabled
Enables or disables the second stage overfrequency element.
F>2 Setting 51 Hz
Disabled, Enabled
45 Hz
Pick-up setting for the second stage overfrequency element.
F>2 Time Delay 1 s 0 s
Operating time-delay setting for the second stage overfrequency element.
100 s
68 Hz
100 s
Max.
Table 14 - Frequency protection settings
Step size
0.01 s
N/A
0.01 Hz
0.01 s
Page (ST) 4-30 P341/EN ST/G74
MiCOM P341 TablesProtection Settings (ST) 4 Settings
3.13 Circuit Breaker Fail and Undercurrent Function (50BF)
This function consists of a two-stage circuit breaker fail function that can be initiated by:
Current based protection elements
Non current based protection elements
External protection elements
For current-based protection, the reset condition is based on undercurrent operation to determine that the CB has opened. For the non-current based protection, the reset criteria may be selected by means of a setting for determining a CB Failure condition.
It is common practice to use low set undercurrent elements in protection relays to indicate that circuit breaker poles have interrupted the fault or load current, as required.
Menu text
GROUP 1: CB FAIL & I<
BREAKER FAIL
CB Fail 1 Status
Default setting
Sub-heading
Enabled
Min.
Disabled, Enabled
Enables or disables the first stage of the circuit breaker function.
CB Fail 1 Timer 0.2 s 0 s
Operating time-delay setting for the first stage circuit breaker fail element.
Setting range
10 s
Max.
Step size
0.01 s
CB Fail 2 Status Disabled Disabled, Enabled
Enables or disables the second stage of the circuit breaker function.
CB Fail 2 Timer 0.4 s 0 s
Operating time-delay setting for the first stage circuit breaker fail element.
10 s 0.01 s
CBF Non I Reset CB Open & I< I< Only, CB Open & I<, Prot. Reset & I<
Setting which determines the elements that will reset the circuit breaker fail time for non current based protection functions (e.g. voltage, frequency) initiating circuit breaker fail conditions.
CBF Ext Reset CB Open & I< I< Only, CB Open & I<, Prot. Reset & I<
Setting which determines the elements that will reset the circuit breaker fail time for external protection functions initiating circuit breaker fail conditions.
UNDERCURRENT Sub-heading
I< Current Set 0.1 In 0.02 In 3.2 In 0.01 In
Circuit breaker fail phase fault undercurrent setting. This undercurrent element is used to reset the CB failure function initiated from the internal or external protection (Any Trip and Ext Trip 3Ph signals).
ISEF< Current 0.02 In 0.001 In 0.8 In 0.0005 In
Circuit breaker fail sensitive earth fault undercurrent setting. This undercurrent element is used to reset the CB failure function initiated from the sensitive earth fault protection.
BLOCKED O/C
Remove I> Start
Sub-heading
Enabled Disabled, Enabled
The ‘Remove I> Start’ setting if enabled sets DDB ‘I> Block Start’ to OFF for a breaker fail condition. The ‘I> Block Start’ DDB is the start signal from all stages of I> protection and is used in blocking schemes. When the block DDB is removed upstream protection is allowed to trip to clear the CB Fail fault condition.
Remove IN> Start Enabled Disabled, Enabled
The ‘Remove IN> Start’ setting if enabled sets DDB ‘IN/ISEF> Bl Start’ to OFF for a breaker fail condition. The ‘IN/ISEF> Bl
Start’ DDB is the start signal from all stages of IN> and ISEF> protection and is used in blocking schemes. When the block
DDB is removed upstream protection is allowed to trip to clear the CB Fail fault condition.
Table 15 - CBF protection settings
P341/EN ST/G74 Page (ST) 4-31
(ST) 4 Settings MiCOM P341 TablesProtection Settings
3.14 Supervision (VTS and CTS)
The VTS feature in the relay operates when it detects a Negative Phase Sequence (NPS) voltage when there is no negative phase sequence current. This gives operation, for the loss of one or two-phase voltages. Stability of the VTS function is assured during system fault conditions, by the presence of NPS current. The use of negative sequence quantities ensures correct operation even where three-limb or ‘V’ connected VTs are used.
If all three-phase voltages to the relay are lost, there are no negative phase sequence quantities to operate the VTS function, and the three-phase voltages collapse. If this is detected without a corresponding change in any of the phase current signals (which would be indicative of a fault), a VTS condition will be raised. In practice, the relay detects superimposed current signals, which are changes in the current applied to the relay.
If a VT is inadvertently left isolated before line energization, voltage dependent elements may operate incorrectly. The previous VTS element detected 3-phase VT failure due to the absence of all 3-phase voltages with no corresponding change in current. However, on line energization there is a change in current, for example, due to load or line charging current. An alternative method of detecting 3-phase VT failure is therefore required on line energization.
The absence of measured voltage on all three-phases on line energization can be as a result of two conditions. The first is a 3-phase VT failure and the second is a close up 3phase fault. The first condition would require blocking of the voltage dependent function and the second would require tripping. To differentiate between these two conditions an overcurrent level detector (VTS I> Inhibit) is used to prevent a VTS block from being issued if it operates. This element should be set in excess of any non-fault based currents on line energization (load, line charging current, transformer inrush current if applicable) but below the level of current produced by a close up 3-phase fault. If the line is closed where a 3-phase VT failure is present the overcurrent detector will not operate and a VTS block will be applied. Closing onto a 3-phase fault will result in operation of the overcurrent detector and prevent a VTS block being applied.
This logic will only be enabled during a live line condition (as indicated by the relays pole dead logic) to prevent operation under dead system conditions i.e. where no voltage will be present and the VTS I> Inhibit overcurrent element will not be picked up.
The CT supervision feature operates on detection of derived zero sequence current, in the absence of corresponding derived zero sequence voltage that would normally accompany it.
The CT supervision can be set to operate from the residual voltage measured at the
VNEUTRAL input or the residual voltage derived from the three phase-neutral voltage inputs as selected by the ‘CTS Vn Input’ setting.
There is one stage of CT supervision CTS. CTS supervises the CT inputs to IA, IB, IC which are used by all the power and overcurrent based protection functions.
Menu text Default setting
Min.
Setting range
Max.
Step size
SUPERVISION: GROUP 1
VT SUPERVISION
VTS Status
Sub-heading
Blocking Blocking, Indication
This setting determines whether the following operations will occur upon detection of VTS.
-
-
VTS set to provide alarm indication only.
Optional blocking of voltage dependent protection elements.
- Optional conversion of directional overcurrent elements to non-directional protection (available when set to blocking mode only). These settings are found in the function links cell of the relevant protection element columns in the menu.
Page (ST) 4-32 P341/EN ST/G74
MiCOM P341 TablesProtection Settings (ST) 4 Settings
Menu text
VTS Reset Mode Manual
Default setting
Min.
Setting range
Manual, Auto
Max.
Step size
The VTS block will be latched after a user settable time delay ‘VTS Time Delay’. Once the signal has latched then two methods of resetting are available. The first is manually via the front panel interface (or remote communications) and secondly, when in ‘Auto’ mode, provided the VTS condition has been removed and the 3 phase voltages have been restored above the phase level detector settings for more than 240 ms.
VTS Time Delay 5 s 1 s 10 s 0.1 s
Operating time-delay setting of the VTS element upon detection of a voltage supervision condition.
VTS I> Inhibit 10 In 0.08 In 32 In 0.01 In
This overcurrent setting is used to inhibit the voltage transformer supervision in the event of a loss of all 3 phase voltages caused by a close up 3 phase fault occurring on the system following closure of the CB to energize the line.
VTS I2> Inhibit 0.05 In 0.05 In 0.5 In 0.01 In
This NPS overcurrent setting is used to inhibit the voltage transformer supervision in the event of a fault occurring on the system with negative sequence current above this setting.
CT SUPERVISION
CTS Status
Sub-heading
Disabled Disabled, Enabled N/A
Enables or disables the current transformer supervision 1 element.
CTS VN Input Derived Derived, Measured
Residual/neutral voltage source for CTS.
CTS VN< Inhibit
5 V
(Vn=100/120 V)
20 V
(Vn=380/480 V)
Residual/neutral voltage setting to inhibit the CTS1 element.
0.5 V
(Vn=100/120 V)
2 V
(Vn=380/480 V)
22 V
(Vn=100/120 V)
88 V
(Vn=380/480 V)
CTS IN> Set 0.2 In 0.08 In 4 In
Residual/neutral current setting for a valid current transformer supervision condition for CTS.
CTS Time Delay 5 s
Operating time-delay setting of CTS.
0 s 10 s
N/A
0.5 V
(Vn=100/120 V)
2 V
(Vn=380/480 V)
0.01 In
1 s
Table 16 - VTS and CTS protection settings
P341/EN ST/G74 Page (ST) 4-33
(ST) 4 Settings MiCOM P341 TablesProtection Settings
3.15 Sensitive Power Protection (32R/32O/32L)
The single phase power protection included in the P341 relay provides two stages of power protection. Each stage can be independently selected as either reverse power, over power, low forward power or disabled. The direction of operation of the power protection, forward or reverse, can also be defined with the operating mode setting. Note that the high impedance REF element of the relay shares the same sensitive current input as the SEF protection and sensitive power protection. Therefore only one of these elements may be selected.
Menu text
GROUP1: SENSITIVE POWER
Default setting
Min
Setting range
Max
Step size
Comp Angle 0
Setting for the compensation angle.
-5° 5° 0.1
Operating Mode Generating Generating, Motoring
Operating mode of the power protection defining forward/reverse direction – Generating = forward power towards the busbar,
Motoring = forward power towards the machine. Assumes CT connections as per standard connection diagrams.
Sen Power1 Func Reverse Disabled, Reverse, Low Forward, Over
First stage power function operating mode.
Sen –P>1 Setting
0.5 In W (Vn=100/120 V)
2 In W
(Vn=380/480 V)
0.3 In W
(Vn=100/120 V)
1.2 In W
(Vn=380/480 V)
100 In W
(Vn=100/120 V)
400 In W
(Vn=380/480 V)
0.1 In W (Vn=100/120
V)
0.4 In W (Vn=380/480
V)
Pick-up setting for the first stage reverse power protection element.
Sen P<1 Setting
0.5 In W (Vn=100/120 V)
2 In W
(Vn=380/480 V)
0.3 In W
(Vn=100/120 V)
1.2 In W
(Vn=380/480 V)
Pick-up setting for the first stage low forward power protection element.
Sen P>1 Setting
50 In W (Vn=100/120 V)
200 In W (Vn=380/480 V)
0.3 In W
(Vn=100/120 V)
1.2 In W
(Vn=380/480 V)
Pick-up setting for the first stage over power protection element.
Sen Power1 Delay 5 s 0 s
Operating time-delay setting of the first stage power protection.
100 In W
(Vn=100/120 V)
400 In W
(Vn=380/480 V)
100 In W
(Vn=100/120 V)
400 In W
(Vn=380/480 V)
100 s
0.1 In W (Vn=100/120
V)
0.4 In W (Vn=380/480
V)
0.1 In W (Vn=100/120
V)
0.4 In W (Vn=380/480
V)
0.01 s
Power1 DO Timer 0 s 0 s
Drop-off time-delay setting of the first stage power protection.
100 s 0.01 s
P1 Poledead Inh Enabled Disabled, Enabled
If the setting is enabled, the relevant stage will become inhibited by the pole dead logic. This logic produces an output when it detects either an open circuit breaker via auxiliary contacts feeding the relay opto inputs or it detects a combination of both undercurrent and undervoltage on any one phase. It allows the power protection to reset when the circuit breaker opens to cater for line or bus side VT applications.
Sen Power2 Func Low Forward Disabled, Reverse, Low Forward, Over
Second stage power function operating mode.
Sen –P>2 Setting
0.5 In W (Vn=100/120 V)
2 In W
(Vn=380/480 V)
0.3 In W
(Vn=100/120 V)
1.2 In W
(Vn=380/480 V)
Pick-up setting for the second stage reverse power protection element.
100 In W
(Vn=100/120 V)
400 In W
(Vn=380/480 V)
0.1 In W (Vn=100/120
V)
0.4 In W (Vn=380/480
V)
Page (ST) 4-34 P341/EN ST/G74
MiCOM P341 TablesProtection Settings (ST) 4 Settings
Menu text Default setting Setting range
Sen P<2 Setting
0.5 In W (Vn=100/120 V)
2 In W
(Vn=380/480 V)
Min
0.3 In W
(Vn=100/120 V)
1.2 In W
(Vn=380/480 V)
Pick-up setting for the second stage low forward power protection element.
Max
100 In W
(Vn=100/120 V)
400 In W
(Vn=380/480 V)
Sen P>2 Setting
50 In W (Vn=100/120 V)
200 In W (Vn=380/480 V)
0.3 In W
(Vn=100/120 V)
1.2 In W
(Vn=380/480 V)
Pick-up setting for the second stage low forward power protection element.
Sen Power2 Delay 5 s 0 s
100 In W
(Vn=100/120 V)
400 In W
(Vn=380/480 V)
100 s
0.1 In W (Vn=100/120
V)
0.4 In W (Vn=380/480
V)
Step size
0.1 In W (Vn=100/120
V)
0.4 In W (Vn=380/480
V)
0.01 s
Operating time-delay setting of the second stage power protection.
Power2 DO Timer 0 s 0 s
Drop-off time-delay setting of the second stage power protection.
100 s 0.01 s
P2 Poledead Inh Enabled Disabled, Enabled
If the setting is enabled, the relevant stage will become inhibited by the pole dead logic. This logic produces an output when it detects either an open circuit breaker via auxiliary contacts feeding the relay opto inputs or it detects a combination of both undercurrent and undervoltage on any one phase. It allows the power protection to reset when the circuit breaker opens to cater for line or bus side VT applications.
Table 17 - Sensitive power protection settings
P341/EN ST/G74 Page (ST) 4-35
(ST) 4 Settings
3.16
Page (ST) 4-36
MiCOM P341 TablesProtection Settings
DLR Protection (49DLR)
The P341 provides Dynamic Line Rating (DLR) protection which can be applied for load management and protection of overhead lines. DLR can enable more Distributed
Generation (DG) such as windfarms to be connected to the grid by taking into account the cooling effect of the wind compared to using the fixed summer/winter line ratings. The
CIGRE 207 or IEEE 738 standard can be selected for the DLR protection.
In configuring the relay it is necessary to enter a range of conductor data parameters, which are required for the heating and cooling calculations (PJ, PC, Pr and PS). To assist the user, the relay stores the relevant parameters of 36 types of British conductors which can be selected using the ‘Conductor Type’ setting. Other conductor types can be defined if ‘Custom’ is selected for the conductor type and additional settings become visible to define the conductor - ‘NonFerrous Layer’, ‘DC Resist per km’, ‘Overall Diameter’, ‘Outer
Layer Diam’, ‘TotalArea(mm sq)’, and ‘TempCoefR x0.001’.
Other conductor configuration settings are also required to define the conductor toplogy and characteristics – ‘Solar Absorp’, ‘Line Emissivity’, ‘Line Elevation’, ‘Line Azimuth Min’,
‘Line Azimuth Max’ and ‘T Conductor Max’.
The ‘Ampacity Min’ and ‘Ampacity Max’ settings are used for the calculated ampacity.
This setting is used to avoid over calculating of the line ampacity for the protection stages. In practice the rating of other components e.g. cables, joints and switchgear may limit the maximum ampacity. There is a drop-off ratio setting which should be set to prevent chattering of the outputs for a small variations of the ampacity around the setting.
If there are measurement sensors to measure the weather conditions - Ambient
Temperature, Wind Velocity, Wind Direction or Solar Radiation then these can be assigned to one of the 4 the current loop (transducer) inputs in the Channel Settings or can be disabled. If no measurement device is available and the current loop inputs for the weather station inputs are disabled or if the current loop input fails then a default value can be set in the Channel Settings for the Ambient Temperature, Wind Velocity, Wind
Direction and Solar Radiation. The Ambient Temperature, Wind Velocity, Wind Direction and Solar Radiation correction factor settings can be used to allow for shielding or shading affects. The Maximum and Minimum settings under the Channel Settings allows the user to set low and high cut-off limits for the weather measurements that will be used by the DLR algorithm. If no limits are required then these settings can be set the same as the Minimum and Maximum values for the current loop (transducer) inputs for the
Ambient Temperature, Wind Velocity, Wind Direction and Solar Radiation.
If the Ambient Temperature, Wind Velocity, Wind Direction or Solar Radiation is changing quickly then the averaging time settings will help to smooth out the ampacity calculations.
The averaging setting will impact the rate at which the ampacity is updated so this will affect the operating time of the protection. If very responsive protection is required then the averaging time should have a lower value.
For the Ambient Temperature, Wind Velocity, Wind Direction and Solar Radiation the transducer type can be selected from four types with ranges 0-1 mA, 0-10 mA, 0-20 mA or 4-20 mA. The Input Maximum and Minimum settings allow the user to enter the range of the physical quantity measured by the transducer. For the 4-20 mA inputs a current level below 4 mA indicates that there is a fault with the transducer or the wiring. An instantaneous under current alarm element is available with a setting range 0-4 mA.
There are a total of 6 alarm/trip elements which have a threshold level setting as a percentage of the line ampacity and definite time delay settings. The thresholds can be used to provide alarms and commands to the generation to HOLD or REDUCE or STOP at specific levels of ampacity below the trip level. If the ampacity reaches a critical level for example 100% then the line can be tripped. The time delay settings are used to avoid spurious tripping during transient network faults and allow discrimination with other protection functions and are also used to provide co-ordination with the load management system to allow time for the wind farm to take action before another DLR stage operates.
P341/EN ST/G74
MiCOM P341 TablesProtection Settings (ST) 4 Settings
Menu Text
GROUP1: DYNAMIC RATING
Default Setting
Min
Setting Range
Max
Step Size
Dyn Line Rating CIGRE Std 207
Selection of the Dynamic Line Rating standard to be used.
Disabled/CIGRE Std 207/ IEEE Std 738
DLR LINE SETTING
Conductor Type Lynx
Gopher, Weasel, Ferret, Rabbit, Horse,
Dog, Wolf, Dingo, Lynx, Caracal, Panther,
Jaguar, Zebra, Fox, Mink, Skunk, Beaver,
Raccoon, Otter, Cat, Hare, Hyena, Leopard,
Tiger, Coyote, Lion, Bear, Batang, Goat,
Antelope, Sheep, Bison, Deer, Camel, Elk,
Moose, Custom
Conductor Type. 36 British conductor types are listed. Other conductor types can be defined in Custom is selected with the settings - ‘NonFerrous Layer’, ‘DC Resist per km’, ‘Overall Diameter’, ‘Outer Layer Diam’, ‘TotalArea(mm sq)’, ‘TempCoefR x0.001’, and ‘mc’.
NonFerrous 2 1 3 1
Number of layers of non ferrous (e.g. aluminum) wires. See figure 1 for ACSR (Aluminum Conductor Steel Reinforced) conductor layers.
DC Resist per km 1 Ω 0.001
Conductor DC resistance at 20oC per kilometer.
Overall Diameter 0.005 m
Conductor overall diameter.
Outer Layer Diam 0.002 m
0.001 m 0.1 m 0.00001 m
0.001 m 0.01 m 0.00001 m
The diameter of a single wire in one of the outer layers. For example the diameter of one of the 30 aluminium wires for 30Al/7St conductor shown in Figure 1.
TotalArea(mm sq) 100 mm2
Conductor total cross section area.
TempCoefR x0.001 4 K
Conductor temperature coefficient of resistance x 10-3
10 mm2
1 K
1000 mm2
10 K
0.01 mm2
0.01 K mc 500 J/(m K) 1 J/(m K) 0.1
Total conductor heat capacity, is defined as the product of specific heat and mass per unit length. If the conductor consists of more than one material (e.g., ACSR), then the heat capacities of the core and the outer strands need to be summated, mc = maca + mscs, where ‘a’ and ‘s’ refer to the non-ferrous and ferrous sections.
‘m’ is the mass per unit length in kg/m, and ‘c’ is the specific heat capacity in J/(kg K). ‘mc’ is used for calculating the dynamic and steady state conductor temperatures – ‘Dyn Conduct Temp’ and ‘Steady Conduct T’ in the Measurements 4 menu.
0.23 0.95 0.01
Conductor solar absorptivity, used to calculate PS.
0.23 0.95 0.01
Conductor emissivity, used to calculate PR.
Line Elevation 0 m
Conductor elevation, used to calculate PS and PC.
Line Azimuth Min 0
-1000 m
0
6000 m
360
1 m
0.1
P341/EN ST/G74 Page (ST) 4-37
(ST) 4 Settings MiCOM P341 TablesProtection Settings
Menu Text
Line Azimuth Max
Default Setting
Min
Setting Range
Max
Step Size
The Line Azimuth Min and Max settings indicates the direction of the line and is used to calculate PS and PC. If the line is in one direction then the Line Azimuth Min and Max settings are the same angle. If for example the mounting direction of the anemometer 0, 360 = North and if the Line Azimuth Min and Max settings are set identical to 0 or 180 or 360 for example this indicates a line running in the same direction in the North-South direction. With a multi-direction span of a transmission line, it may be unnecessary to specify the line’s azimuth because all possible angles could be evaluated for the entire line. In this situation, the ‘Line Azimuth Min’ should be set to 0 and ‘Line Azimuth Max’ should be set to 180 to indicate all ranges of the effective angles between the wind direction and the conductor. In this case the effective wind angle to the line is taken as the worst case = 0 .
The line azimuth significantly influences the effective angle between the wind and conductor line, which is an important variable to calculate convective cooling PC.
180 0 360 0.1
Line Azimuth maximum setting. See above.
T Conductor Max 50 C 0 C 300 C 0.1
C
Maximum allowable conductor temperature, used for calculating the line ampacity. This is based on the maximum conductor sag and annealing onset limits of the conductor.
Ampacity Min 0.2 In 0.1 In 4 In 0.001 In
Minimum setting for the calculated ampacity. This setting is used to avoid over calculating of the line ampacity for the protection stages.
Ampacity Max 2 In 0.1 In 4 In 0.001 In
Maximum setting for the calculated ampacity. This setting is used to avoid over calculating of the line ampacity for the protection stages. The rating of other components e.g. cables, joints and switchgear may limit the maximum ampacity.
Drop-off Ratio 98%
Reset ratio of the DLR protection settings.
70% 99% 0.1%
Line Direction 0 0 360 0.1
The Line Direction is used for calculating the dynamic and steady state conductor temperatures – ‘Dyn Conduct Temp’ and
‘Steady Conduct T’ in the Measurements 4 menu. 0, 360 = North. If the line direction is not constant then an average value could be used or the line angle of the most critical span could be used.
DLR CHANNEL SET
Ambient Temp CLI1 Disabled, CLI1, CLI2, CLI3, CLI4
Selection of current loop (transducer) input 1 or 2 or 3 or 4 for the ambient temperature measurement.
Default Ambient T 20 C -100 C 100 C
Default ambient temperature setting. This is used if the current loop input is disabled or faulty.
0.1
C
Ambient T Corr
Ambient T Min
0 C
-40 C
-50 C
-100 C
Minimum ambient temperature value that will be used by the DLR algorithm.
50 C 0.1
C
The ambient temperature correction factor adds a temperature (+/-) to the measured temperature, ambient temperature = measured ambient temperature + Amb T Corr. This setting can be used to allow for shielding or altitude affects where the ambient temperature could be higher/lower at particular point on the line compared to where the ambient temperature sensor is positioned.
100 C 0.1
C
Ambient T Max 50 C -100 C
Maximum ambient temperature value that will be used by the DLR algorithm.
Amb T Input Type 4-20 mA
100 C 0.1
C
Ambient T AvgSet
Ambient T AvgDly
Enabled
100 s
Disabled, Enabled
60 s
Averaging time delay setting for the ambient temperature input.
Enables or disables the averaging function for the ambient temperature input only. The averaging function is used to average the ambient temperature input over the averaging time delay.
3600 s 10 s
0-1 mA, 0-10 mA, 0-20 mA,
4-20 mA
Page (ST) 4-38 P341/EN ST/G74
MiCOM P341 TablesProtection Settings (ST) 4 Settings
Menu Text Default Setting Setting Range
Min
Current loop (transducer) input type for the ambient temperature measurement.
Max
Step Size
Amb T I/P Min
Amb T I/P Max
-40 C -100 C 100 C 0.1
C
Ambient temperature current loop input minimum setting. Defines the lower range of the physical quantity measured by the transducer.
50 C -100 C 100 C 0.1
C
Ambient temperature current loop input maximum setting. Defines the upper range of the physical quantity measured by the transducer.
Amb T I< Alarm Disabled Disabled, Enabled
Enables or disables the ambient temperature current loop input alarm element.
Amb T I< Alm Set 0.0035 A 0 A 0.004 A 0.0001 A
Pick-up setting for the ambient temperature current loop input undercurrent element used to supervise the 4-20mA input only.
Wind Velocity CLI2 Disabled, CLI1, CLI2, CLI3, CLI4
Selection of current loop (transducer) input 1 or 2 or 3 or 4 for the wind velocity measurement.
Default Wind Vel 0.5 m/s 0 m/s 60 m/s 0.01 m/s
Default wind velocity setting. This is used if the current loop input is disabled or faulty.
Wind Vel Corr 100% 0% 150% 0.1%
The wind velocity correction factor is a multiplier for the wind velocity, wind velocity = measured wind velocity x (Wind Vel
Corr/100). This setting can be used to allow for shielding or altitude affects where the wind velocity could be higher/lower at particular point on the line compared to where the wind velocity sensor is positioned.
Wind Vel Min 0 m/s 0 m/s 60 m/s 0.01 m/s
Minimum wind velocity value that will be used by the DLR algorithm.
Wind Vel Max 60 m/s 0 m/s
Maximum wind velocity value that will be used by the DLR algorithm.
60 m/s 0.01 m/s
Wind Vel AvgSet Enabled Disabled, Enabled
Enables or disables the averaging function for the wind velocity input only. The averaging function is used to average the wind velocity input over the averaging time delay.
10 s Wind Vel AvgDly 100 s
Averaging time delay setting for the wind velocity input.
60 s 3600 s
WV Input Type 4-20 mA
0-1 mA, 0-10 mA, 0-20 mA,
4-20 mA
Current loop (transducer) input type for the wind velocity measurement.
WV I/P Minimum 0 m/s 0 m/s 60 m/s 0.01 m/s
Wind velocity current loop input minimum setting. Defines the lower range of the physical quantity measured by the transducer.
WV I/P Maximum 60 m/s 0 m/s 60 m/s 0.01 m.s
Wind velocity current loop input maximum setting. Defines the upper range of the physical quantity measured by the transducer.
WV I< Alarm Disabled Disabled, Enabled
Enables or disables the wind velocity current loop input alarm element.
WV I< Alarm Set 0.0035 A 0 A 0.004 A 0.0001 A
Pick-up setting for the wind velocity current loop input undercurrent element used to supervise the 4-20mA input only.
Wind Direction CLI3 Disabled, CLI1, CLI2, CLI3, CLI4
Selection of current loop (transducer) input 1 or 2 or 3 or 4 for the wind direction measurement.
Default Wind Dir 0 0 360 0.1
Default wind direction setting. This is used if the current loop input is disabled or faulty.
Wind Dir Corr 0 -180 180 0.1
P341/EN ST/G74 Page (ST) 4-39
(ST) 4 Settings MiCOM P341 TablesProtection Settings
Menu Text Default Setting
Min
Setting Range
Max
Step Size
The wind direction correction factor adds an angle (+/-) to the measured wind direction, wind direction = measured wind direction + Wind Dir Corr. The wind direction correction factor setting could be used to correct for errors in the measurement sensor. Typically, this setting is set to the default value of 0 .
Wind Dir Min 0 0 360 0.1
Minimum wind direction value that will be used by the DLR algorithm.
Wind Dir Max 0 360
Maximum wind direction value that will be used by the DLR algorithm.
360 0.1
Wind Dir AvgSet Enabled Disabled, Enabled
Enables or disables the averaging function for the wind direction input only. The averaging function is used to average the wind direction input over the averaging time delay.
Wind Dir AvgDly 100 s
Averaging time delay setting for the wind direction input.
60 s 3600 s 10 s
WD Input Type 4-20 mA
0-1 mA, 0-10 mA, 0-20 mA,
4-20 mA
Current loop (transducer) input type for the wind direction measurement.
WD I/P Minimum
WD I/P Maximum
0 0 360 0.1
Wind direction current loop input minimum setting. Defines the lower range of the physical quantity measured by the transducer.
360 0 360 0.1
Wind direction current loop input maximum setting. Defines the upper range of the physical quantity measured by the transducer.
WD I< Alarm Disabled Disabled, Enabled
Enables or disables the wind direction current loop input alarm element.
WD I< Alarm Set 0.0035 A 0 A 0.004 A 0.0001 A
Pick-up setting for the wind direction current loop input undercurrent element used to supervise the 4-20mA input only.
Solar Radiation CLI4 Disabled, CLI1, CLI2, CLI3, CLI4
Selection of current loop (transducer) input 1 or 2 or 3 or 4 for the solar radiation measurement.
Default Solar R 0 W 0 W 3000 W
Default solar radiation setting. This is used if the current loop input is disabled or faulty.
1 W
Solar Rad Corr 0 W -1000 W 1000 W 1 W
The solar radiation correction factor adds a solar radiation value (+/-) to the measured solar radiation, solar radiation = measured solar radiation + Solar Rad Corr. This setting can be used to allow for shielding or altitude affects where the solar radiation could be higher/lower at particular point on the line compared to where the solar radiation sensor is positioned.
Solar Rad Min 1000 W 0 W 3000 W 1 W
Minimum solar radiation value that will be used by the DLR algorithm.
Solar Rad Max 1000 W 0 W
Maximum solar radiation value that will be used by the DLR algorithm.
Solar Rad AvgSet Enabled Disabled, Enabled
3000 W 1 W
Enables or disables the averaging function for the wind direction input only. The averaging function is used to average the wind direction input over the averaging time delay.
Solar Rad AvgDly 100 s 60 s 3600 s 10 s
Averaging time delay setting for the wind direction input.
SR Input Type 4-20 mA
0-1 mA, 0-10 mA, 0-20 mA,
4-20 mA
Current loop (transducer) input type for the solar radiation measurement.
SR I/P Minimum 0 W 0 W 3000 W 1 W
Page (ST) 4-40 P341/EN ST/G74
MiCOM P341 TablesProtection Settings (ST) 4 Settings
Menu Text Default Setting
Min
Setting Range
Max
Step Size
Solar radiation current loop input minimum setting. Defines the lower range of the physical quantity measured by the transducer.
SR I/P Maximum 1000 W 0 W 3000 W 1 W
Solar radiation current loop input maximum setting. Defines the upper range of the physical quantity measured by the transducer.
SR I< Alarm Disabled Disabled, Enabled
Enables or disables the solar radiation current loop input alarm element.
0.0001 A SR I< Alarm Set 0.0035 A 0 A 0.004 A
Pick-up setting for the solar radiation current loop input undercurrent element used to supervise the
4-20 mA input only.
DLR PROT SETTING
DLR I>1 Trip Enabled
Enables or disables the DLR 1st stage element
Disabled, Enabled
0.1% DLR I>1 Set 80% 20%
Pick-up setting for DLR 1st stage element as a percentage of the line ampacity.
DLR I>1 Delay 100 s
Operating time delay of the DLR 1st stage element.
0 s
200%
30000 s
DLR I>2 Trip Enabled
Enables or disables the DLR 2nd stage element
Disabled, Enabled
DLR I>2 Set 90% 20%
Pick-up setting for DLR 2nd stage element as a percentage of the line ampacity.
200%
0 s 30000 s DLR I>2 Delay 100 s
Operating time delay of the DLR 2nd stage element.
DLR I>3 Trip Enabled Disabled, Enabled
Enables or disables the DLR 3rd stage element
DLR I>3 Set 95% 20%
Pick-up setting for DLR 3rd stage element as a percentage of the line ampacity.
DLR I>3 Delay 100 s 0 s
200%
30000 s
Operating time delay of the DLR 3rd stage element.
DLR I>4 Trip Enabled
Enables or disables the DLR 4th stage element
DLR I>4 Set 97%
Disabled, Enabled
20% 200%
1 s
0.1%
1s
0.1%
1s
0.1%
Pick-up setting for DLR 4th stage element as a percentage of the line ampacity.
DLR I>4 Delay 100 s 0 s
Operating time delay of the DLR 4th stage element.
DLR I>5 Trip Enabled Disabled, Enabled
30000 s
Enables or disables the DLR 5th stage element
DLR I>5 Set 99% 20%
Pick-up setting for DLR 5th stage element as a percentage of the line ampacity.
0 s
200%
30000 s DLR I>5 Delay 100 s
Operating time delay of the DLR 5th stage element.
DLR I>6 Trip Enabled
Enables or disables the DLR 6th stage element
Disabled, Enabled
DLR I>6 Set 100% 20% 200%
1s
0.1%
1s
0.1%
P341/EN ST/G74 Page (ST) 4-41
(ST) 4 Settings MiCOM P341 TablesProtection Settings
Menu Text Default Setting Setting Range
Min
Pick-up setting for DLR 6th stage element as a percentage of the line ampacity.
Max
DLR I>6 Delay 100 s 0 s 30000 s
Operating time delay of the DLR 6th stage element.
Table 18 - Dynamic rating protection settings
1 Layer
Non Ferrous wires
6 AI / 1 St 12 AI / 7 St
1 s
Step Size
2 Layers
Non Ferrous wires
18 AI / 1 St 30 AI / 7 St
3 Layers
Non Ferrous wires
36 AI / 1 St 54 AI / 7 St
Figure 1 - Illustration of Non Ferrous Layers for ACSR
P4329ENa
Page (ST) 4-42 P341/EN ST/G74
MiCOM P341 TablesProtection Settings (ST) 4 Settings
3.17 Input Labels
Menu text Default setting
GROUP 1: INPUT LABELS
Setting range Step size
Opto Input 1 Input L1 16 Character Text
Text label to describe each individual opto input. This text will be displayed in the programmable scheme logic and event record description of the opto input.
Opto Input 2 to 24 Input L2 to L24 16 Character Text
Text label to describe each individual opto input. This text will be displayed in the programmable scheme logic and event record description of the opto input.
Table 19 - Input labels settings
3.18 Output labels
Menu text Default setting Setting range
GROUP 1: OUTPUT LABELS
Step size
Relay 1 Output R1 16 Character Text
Text label to describe each individual relay output contact. This text will be displayed in the programmable scheme logic and event record description of the relay output contact.
Relay 2 to 24 Output R2 to R24 16 Character Text
Text label to describe each individual relay output contact. This text will be displayed in the programmable scheme logic and event record description of the relay output contact.
Table 20 - Output labels settings
P341/EN ST/G74 Page (ST) 4-43
(ST) 4 Settings MiCOM P341 TablesProtection Settings
3.19 Current Loop Inputs and Outputs (CLIO)
Four analog or current loop inputs are provided for transducers with ranges of 0 - 1 mA,
0 - 10, 0 - 20 mA or 4 - 20 mA. The analog inputs can be used for various transducers such as vibration monitors, tachometers and pressure transducers. Associated with each input there are two protection stages, one for alarm and one for trip. Each stage can be individually enabled or disabled and each stage has a definite time delay setting. The
Alarm and Trip stages can be set for operation when the input value falls below the
Alarm/Trip threshold ‘Under’ or when the input current is above the input value ‘Over’.
The 4-20 mA input has an undercurrent alarm element which can be used to indicate a fault with the transducer or wiring.
There are four analog current outputs with ranges of 0 - 1 mA, 0 - 10 mA, 0 - 20 mA or
4 - 20 mA which can reduce the need for separate transducers. These outputs can be fed to standard moving coil ammeters for analog measurements or to a SCADA system using an existing analog RTU.
Menu text Default setting
Min.
GROUP 1: CLIO Protection
Setting range
Max.
CLIO Input 1 Disabled Disabled, Enabled
Enables or disables the current loop (transducer) input 1 element.
N/A
Step size
CLI1 Input Type 4 - 20 mA
0 - 1 mA, 0 - 10 mA, 0 - 20 mA, 4 - 20 mA
N/A
Current loop 1 input type.
CLI1 Input Label CLIO Input 1 16 characters
Current loop 1 input description. The minimum and maximum settings define the range but they have no units. The user can use the label to enter the transducer function and unit of measurement, e.g. Power MW, which is used in the Measurements 3 menu to describe the CLI1 measurement.
CLI1 Minimum 0 -9999 9999 0.1
Current loop input 1 minimum setting. Defines the lower range of the physical or electrical quantity measured by the transducer.
CLI1 Maximum 100 -9999 9999 0.1
Current loop input 1 maximum setting. Defines the upper range of the physical or electrical quantity measured by the transducer.
CLI1 Alarm Disabled
Enables or disables the current loop input 1 alarm element.
Disabled, Enabled N/A
N/A CLI1 Alarm Fn Over
Operating mode of the current loop input 1 alarm element.
Over, Under
CLI1 Alarm Set 50
Min. (CLI1 Min.,
Max.)
Pick-up setting for the current loop input 1 alarm element.
CLI1 Alarm Delay 1 s 0 s
Operating time-delay setting of current loop input 1 alarm element.
Max. (CLI1 Min.,
Max.)
100 s
0.1
0.1s
CLI1 Trip Disabled
Pick-up setting for the current loop input 1 trip element.
CLI1 Trip Fn Over
Operating mode of the current loop input 1 alarm element.
Disabled, Enabled
Over, Under
N/A
N/A
CLI1 Trip Set 50
Min. (CLI1 Min.,
Max.)
Max. (CLI1 Min.,
Max.)
0.1
Pick-up setting for the current loop input 1 trip element.
CLI1 Trip Delay 1 s 0 s 100 s 0.1 s
Page (ST) 4-44 P341/EN ST/G74
MiCOM P341 TablesProtection Settings (ST) 4 Settings
Menu text Default setting
Min.
Setting range
Max.
GROUP 1: CLIO Protection
Operating mode of the current loop input 1 trip element.
Step size
CLI1 I< Alarm Disabled Disabled, Enabled N/A
Enables or disables the current loop input 1 undercurrent element used to supervise the 4-20 mA input only.
CLI1 I< Alm Set 3.5 0 4 mA 0.1 mA
Pick-up setting for the current loop input 1 undercurrent element. (4 - 20 mA input only).
CLI2/3/4 settings are the same as CLI1
CLIO Output 1 Disabled Disabled, Enabled
Enable or disables the current loop (transducer) output 1 element.
CLO1 Output Type 4 - 20 mA
0 - 1 mA, 0 - 10 mA, 0 - 20 mA, 4- 20 mA
Current loop 1 output type
N/A
CLO1 Set Values Primary Primary, Secondary
This setting controls if the measured values via current loop output 1 are Primary or Secondary values.
CLO1 Parameter IA Magnitude
A list of parameters are shown in the table below
This setting defines the measured quantity assigned to current loop output 1.
CLO1 Minimum 0
Range, step size and unit corresponds to the selected parameter in the table below
Current loop output 1 minimum setting. Defines the lower range of the measurement.
CLO1 Maximum 1.2 In
Range, step size and unit corresponds to the selected parameter in the table below
Current loop output 1 maximum setting. Defines the upper range of the measurement.
CLO2/3/4 settings are the same as CLO1
N/A
N/A
N/A
N/A
Table 21 - Current loop inputs and outputs settings
The CLIO output conversion task runs every 50 ms and the refresh interval for the output measurements is nominally 50 ms. The exceptions are marked with an asterisk in the table of current loop output parameters below. Those exceptional measurements are updated once every second.
Current loop output parameters are shown in the following table:
Current loop output parameter
Abbreviation
Current Magnitude
IA Magnitude
IB Magnitude
IC Magnitude
IN Derived Mag
Sensitive Current Input
Magnitude
RMS Phase Currents
I Sen Magnitude
Phase Sequence Current
Components
I1 Magnitude
I2 Magnitude
I0 Magnitude
IA RMS*
IB RMS*
IC RMS*
A
A
A
A
Units Range
0 to 16 A
0 to 2 A
0 to 16 A
0 to 16 A
Step
0.01 A
0.01 A
0.01 A
0.01 A
Default min.
0 A
0 A
0 A
0 A
Default max.
1.2 A
1.2 A
1.2 A
1.2 A
P341/EN ST/G74 Page (ST) 4-45
(ST) 4 Settings MiCOM P341 TablesProtection Settings
Current loop output parameter
Abbreviation
P-P Voltage Magnitude
VAB Magnitude
VBC Magnitude
VCA Magnitude
P-N voltage Magnitude
Neutral Voltage
Magnitude
VAN Magnitude
VBN Magnitude
VCN Magnitude
VN Measured Mag.
VN Derived Mag.
Phase Sequence Voltage
Components
V1 Magnitude*
V2 Magnitude
V0 Magnitude
RMS Phase Voltages
VAN RMS*
VBN RMS*
VCN RMS*
Frequency Frequency
3 Ph Active Power Three-Phase Watts*
3 Ph Reactive Power Three-Phase Vars*
3 Ph Apparent Power Three-Phase VA*
3 Ph Power Factor
Single-Phase Active
Power
Single-Phase Reactive
Power
Single-Phase Apparent
Power
Single-Phase Power
Factor
Three-Phase Current
Demands
3Ph Active Power
Demands
3Ph Reactive Power
Demands
3Ph Power Factor*
A Phase Watts*
B Phase Watts*
C Phase Watts*
A Phase Vars*
B Phase Vars*
C Phase Vars*
A Phase VA*
B Phase VA*
C Phase VA*
APh Power Factor*
BPh Power Factor*
CPh Power Factor*
IA Fixed Demand*
IB Fixed Demand*
IC Fixed Demand*
IA Roll Demand*
IB Roll Demand*
IC Roll Demand*
IA Peak Demand*
IB Peak Demand*
IC Peak Demand*
3Ph W Fix Demand*
3Ph W Roll Dem*
3Ph W Peak Dem*
3Ph Vars Fix Dem*
3Ph Var Roll Dem*
3Ph Var Peak Dem*
A
Var
VA
Var
VA
-
W
V
Hz
W
V
V
V
V
Units Range
0 to 200 V
Step
0.1 V
Default min.
0 V
Default max.
140 V
0 to 200 V
0 to 200 V
0 to 200 V
0.1 V
0.1V
0.1 V
0 V
0V
0 V
80 V
80 V
80 V
0 to 200 V
0 to 70 Hz
-6000 W to
6000 W
-6000 Var to
6000 Var
0 to
6000 VA
-1 to 1
-2000 W to
2000 W
-2000 Var to
2000 Var
0 to
2000 VA
-1 to 1
0.1 V
0.01 Hz
1 W
1 Var
1 VA
0.01
1 W
1 Var
1 VA
0.01
0 V
45 Hz
0 W
0 Var
0 VA
0
0 W
0 Var
0 VA
0
80 V
65 Hz
300 W
300 Var
300 VA
1
100 W
100 Var
100 VA
1
0 to 16 A 0.01 A
W
Var
-6000 W to
6000 W
-6000 Var to
6000 Var
1 W
1 Var
0 A
0 W
0 Var
1.2 A
300 W
300 Var
Page (ST) 4-46 P341/EN ST/G74
MiCOM P341 TablesProtection Settings (ST) 4 Settings
Current loop output parameter
Current Loop Inputs
DLR Ampacity
Maximum ac current
Abbreviation
CL Input 1
CL Input 2
CL Input 3
CL input 4
DLR Ampacity
Max Iac
-
A
A
Units Range
-9999 to
9999
0 to 4 In
0 to 16 In
Check Synch Voltages
Slip Frequency
C/S Voltage Mag
C/S Bus Gen-Mag
Slip frequency
V
Hz
Table 22 - Current loop outputs units and setting range
0 to 200 V
0 to 70 Hz
Note 1:
Note 2:
Note 3:
0.1
Step
0
Default min.
0.001 In
0.01 In
0
0
0.01 Hz/s -1 Hz/s
0.1 V
0.01 Hz
0 V
-0.5 Hz
Default max.
9999
4 In
1.2 In
1 Hz/s
80 V
0.5 Hz
For measurements marked with an asterisk, the internal refresh rate is nominally 1 s, others are 0.5 power system cycle or less.
The polarity of Watts, Vars and power factor is affected by the
Measurements Mode setting.
These settings are for nominal 1A and 100/120 V versions only. For other nominal versions they need to be multiplied accordingly.
P341/EN ST/G74 Page (ST) 4-47
(ST) 4 Settings MiCOM P341 TablesProtection Settings
3.20 System Checks (Check Sync. Function)
The P34x has a two stage Check Synchronization function that can be set independently.
Menu text Default setting Setting range Step size
Min.
SYSTEM CHECKS GROUP 1
Max.
VOLTAGE MONITORS Sub-heading
Live Voltage 32 V
1 V
(Vn=100/120 V)
4 V
(Vn=380/480 V)
132 V
(Vn=100/120 V)
528V
(Vn=380/480 V)
Minimum voltage setting above which a generator or busbar is recognized as being ‘Live’.
0.5 V
(Vn=100/120 V)
2 V
(Vn=380/480 V)
Dead Voltage 13 V
1 V
(Vn=100/120 V)
4 V
(Vn=380/480 V)
132 V
(Vn=100/120 V)
528 V
(Vn=380/480 V)
0.5 V
(Vn=100/120 V)
2 V
(Vn=380/480 V)
Overvoltage setting below which the generator voltage must be satisfied for the Check Sync. condition if V> is selected in the
CS Voltage Block cell.
Gen Undervoltage 54 V
1 V
(Vn=100/120 V)
22 V
(Vn=380/480 V)
132 V
(Vn=100/120 V)
528 V
(Vn=380/480 V)
0.5 V
(Vn=100/120 V)
2 V
(Vn=380/480 V)
Undervoltage setting above which the generator voltage must be satisfied for the Check Sync. condition if V< is selected in the
CS Voltage Block cell.
Gen Overvoltage 130
1 V
(Vn=100/120 V)
22 V
(Vn=380/480 V)
182 V
(Vn=100/120 V)
740 V
(Vn=380/480 V)
0.5 V
(Vn=100/120 V)
2 V
(Vn=380/480 V)
Overvoltage setting which the generator voltage must be satisfied for the Check Sync. condition if V> is selected in the CS
Voltage Block cell.
Bus Undervoltage
54 V
(Vn=100/120 V)
216 V
(Vn=380/480 V)
10 V
(Vn=100/120 V)
40 V
(Vn=380/480 V)
132 V
(Vn=100/120 V)
528 V
(Vn=380/480 V)
0.5 V
(Vn=100/120 V)
2 V
(Vn=380/480 V)
Undervoltage setting above which the busbar voltage must be satisfied for the Check Sync. condition if V< is selected in the CS
Voltage Block cell..
Bus Overvoltage
130 V
(Vn=100/120 V)
520 V
(Vn=380/480 V)
60 V
(Vn=100/120 V)
240 V
(Vn=380/480 V)
185 V
(Vn=100/120 V)
740 V
(Vn=380/480 V)
0.5 V
(Vn=100/120 V)
2 V
(Vn=380/480 V)
Overvoltage setting below which the busbar voltage must be satisfied for the Check Sync. condition if V> is selected in the CS
Voltage Block cell.
CS Diff Voltage
6.5 V
(Vn=100/120 V)
26 V
(Vn=380/480 V)
1 V
(Vn=100/120 V)
4 V
(Vn=380/480 V)
132 V
(Vn=100/120 V)
528 V
(Vn=380/480 V)
0.5 V
(Vn=100/120 V)
2 V
(Vn=380/480 V)
Voltage magnitude difference setting between the generator and busbar volts below which the generator and bus voltage difference must be satisfied for the Check Sync. condition if selected in the CS Voltage Block cell.
CS Voltage Block V<
None, V<, V>, Vdiff>, V< and V>, V< and Vdiff>, V> and
Vdiff>, V< V> Vdiff>
Selects the undervoltage(V<), overvoltage (V>) and voltage difference (Vdiff>) voltage blocking options for the generator and bus voltages that must be satisfied in order for the Check Sync. conditions to be satisfied.
Page (ST) 4-48 P341/EN ST/G74
MiCOM P341 TablesProtection Settings (ST) 4 Settings
Menu text Default setting Setting range
Min.
SYSTEM CHECKS GROUP 1
Max.
49.5 Hz 45 Hz 65 Hz
Step size
Gen Under Freq 0.01 Hz
Underfrequency setting for the generator. This setting only affects DDB 1347 Freq Low which indicates the generator frequency is less than the Gen Under Freq setting.
Gen Over Freq 50.5 Hz 45 Hz 65 Hz 0.01 Hz
Overfrequency setting for the generator. This setting only affects DDB 1348 Freq High which indicates the generator frequency is less than the Gen Under Freq setting
CHECK SYNC.
CS1 Status
Sub-heading
Enabled
Enables or disables the first stage check sync. element.
CS1 Phase Angle 20.00°
Disabled, Enabled
5° 90° 1°
Maximum phase angle difference setting between the line and bus voltage for the first stage check sync. element phase angle criteria to be satisfied.
CS1 Slip Control Frequency None, Timer Only, Frequency Only, Frequency + Timer
Slip control method - slip frequency only, frequency + timer or timer only criteria to satisfy the first stage check sync. conditions.
If slip control by timer or frequency + timer is selected, the combination of phase angle and timer settings determines an effective maximum slip frequency, calculated as:
2 x A
T x 360
Hz. for Check Sync. 1, or where
A
T
=
=
Phase angle setting ( )
Slip timer setting (seconds)
For example, with Check Sync. 1 Phase Angle setting 30 and Timer setting 3.3 sec, the “slipping” vector has to remain within
30 of the reference vector for at least 3.3 seconds. Therefore a synch check output will not be given if the slip is greater than
2 x 30 in 3.3 seconds. Using the formula: 2 x 30 (3.3 x 360) = 0.0505 Hz (50.5 mHz).
If Slip Control by Frequency + Timer is selected, for an output to be given, the slip frequency must be less than BOTH the set
Slip Freq. value and the value determined by the Phase Angle and Timer settings.
If Slip Control by Frequency, for an output to be given, the slip frequency must be less than the set Slip Freq. value setting only.
CS1 Slip Freq. 50 mHz 10 mHz 1 Hz 10 mHz
Maximum frequency difference setting between the generator and bus voltage for the first stage check sync. element slip frequency to be satisfied.
99 s 0.01 s CS1 Slip Timer 1 s 0 s
Minimum operating time-delay setting for the first stage check sync. element.
CS2 Status Enabled
Enable or disables the second stage check sync. element.
Disabled, Enabled
CS2 Phase Angle 20.00° 5° 90° 1°
Maximum phase angle difference setting between the line and bus voltage for the second stage check sync. element phase angle criteria to be satisfied.
CS2 Slip Control Frequency
None, Timer Only, Frequency Only, Frequency + Timer,
Frequency + CB
P341/EN ST/G74 Page (ST) 4-49
(ST) 4 Settings MiCOM P341 TablesProtection Settings
Menu text Default setting
Min.
Setting range
Max.
SYSTEM CHECKS GROUP 1
Slip control method - slip frequency only, frequency + timer or timer only criteria to satisfy the CS1 conditions.
Step size
If Slip Control by Timer or Frequency + Timer is selected, the combination of Phase Angle and Timer settings determines an effective maximum slip frequency, calculated as:
A
T x 360
Hz. for Check Sync. 2, or where
A
T
=
=
Phase angle setting ( )
Slip timer setting (seconds)
For Check Sync. 2, with Phase Angle setting 10 and Timer setting 0.1 sec, the slipping vector has to remain within 10 of the reference vector, with the angle decreasing, for 0.1 sec. When the angle passes through zero and starts to increase, the synch check output is blocked. Therefore an output will not be given if slip is greater than 10 in 0.1 second. Using the formula: 10
(0.1 x 360) = 0.278 Hz (278 mHz).
If Slip Control by Frequency + Timer is selected, for an output to be given, the slip frequency must be less than BOTH the set
Slip Freq. value and the value determined by the Phase Angle and Timer settings.
If Slip Control by Frequency, for an output to be given, the slip frequency must be less than the set Slip Freq. value setting only.
The Freq. + Comp. (Frequency + CB Time Compensation) setting modifies the Check Sync. 2 function to take account of the circuit breaker closing time. By measuring the slip frequency, and using the CB Close Time setting as a reference, the relay will issue the close command so that the circuit breaker closes at the instant the slip angle is equal to the CS2 phase angle setting. Unlike Check Sync. 1, Check Sync. 2 only permits closure for decreasing angles of slip, therefore the circuit breaker should always close within the limits defined by Check Sync. 2.
CS2 Slip Freq. 50 mHz
Slip frequency setting for the second stage check sync. element.
10 mHz 1 Hz 10 mHz
CS2 Slip Timer 1 s
Second stage Check Sync. slip timer setting.
SYSTEM SPLIT Sub-heading
SS Undervoltage
0 s 99 s 0.01 s
SS Status Enabled
Enables or disables the system split function.
Disabled, Enabled
SS Phase Angle
SS Under V Block
120°
Enabled
Activates the system split undervoltage block criteria
90° 175° 1°
Maximum phase angle difference setting between the generator and bus voltage, which must be exceeded, for the System Split condition to be satisfied.
Disabled, Enabled
54 V
(Vn=100/120 V)
216 V
(Vn=380/480 V)
10 V
(Vn=100/120 V)
40 V
(Vn=380/480 V)
132 V
(Vn=100/120 V)
528 V
(Vn=380/480 V)
0.5 V
(Vn=100/120 V)
2 V
(Vn=380/480 V)
Undervoltage setting above which the generator and bus voltage must be satisfied for the System Split condition.
SS Timer 1 s 0 s 99 s 0.01 s
The System Split output remains set for as long as the System Split criteria are true, or for a minimum period equal to the
System Split Timer setting, whichever is longer.
CB Close Time 50 ms 0 s 0.5 s 1 ms
Circuit breaker closing time setting used in the second stage Check Sync. criteria to compensate for the breaker closing time if selected.
Table 23 - System checks settings
Page (ST) 4-50 P341/EN ST/G74
MiCOM P341 TablesControl And Support Settings (ST) 4 Settings
4 CONTROL AND SUPPORT SETTINGS
The control and support settings are part of the main menu and are used to configure the relays global configuration. It includes the following submenu settings.
Relay function configuration settings
Open/close circuit breaker
CT & VT ratio settings
Reset
Active protection setting group
Password & language settings
Circuit breaker control & monitoring settings
Communications
Measurement
Event & fault record settings
User interface settings
Commissioning
4.1 System Data
This menu provides information for the device and general status of the relay.
Menu text Default setting Setting range
SYSTEM DATA
Min.
Language English
Max.
English, Francais, Deutsch, Espanol or
English, Francais, Deutsch, Русский or
English, Francais, 中文 (Chinese)
The default language used by the device.
Selectable as:
English, French, German, Spanish (language order option 0) or
English, French, German, Russian ( Русский ) (language order option 5) or
English, French, Chinese ( 中文 ) (language order option C)
N/A
Step size
Password
Device password for level 1 or 2. If password level 1 is input then the access level is set as 1 and if password level 2 is input then the access level is set as 2.
Sys. Fn. Links
****
0
Setting to allow the fixed function trip LED to be self resetting, 1= self reset, 0 = latched.
1
Description P341
16 character relay description. Can be edited.
Plant Reference Schneider Electric
Plant description. Can be edited.
Model Number
Relay model number.
P341?11???0360J
P341/EN ST/G74 Page (ST) 4-51
(ST) 4 Settings MiCOM P341 TablesControl And Support Settings
Menu text Default setting
SYSTEM DATA
Min.
Setting range
149188B Serial Number
Relay serial number.
Frequency 50 Hz
Relay set frequency. Settable as 50 or 60 Hz.
50 Hz 60 Hz
Max.
Comms. Level
Displays the conformance of the relay to the Courier Level 2 comms.
Relay Address
Sets the first rear port relay address.
Step size
10 Hz
Plant Status 0000000000000000
Displays the circuit breaker plant status for up to 8 circuit breakers. The P341 relay supports only a single circuit breaker configuration.
0000000000000000 Control Status
Not used.
Active Group 1
Displays the active settings group.
CB Trip/Close No Operation, Trip, Close
Used to control trip or control close a CB.
Software Ref. 1 P341____1__360_A
Software Ref. 2
Displays the relay software version including protocol and relay model.
Software Ref. 2 is displayed for relays with IEC 61850 protocol only and this will display the software version of the Ethernet card.
Opto I/P Status 0000000000000000
This menu cell displays the status of the relay’s opto-isolated inputs as a binary string, a ‘1’ indicating an energized optoisolated input and a ‘0’ a de-energized one.
Relay O/P Status 0000001000000000
This menu cell displays the status of the relay’s output contacts as a binary string, a ‘1’ indicating an operated state and ‘0’ a non-operated state.
Alarm Status 1 00000000000000000000000000000000
This menu cell displays the status of the first 32 alarms as a binary string, a ‘1’ indicating an ON state and ‘0’ an OFF state.
Includes fixed and user settable alarms. See Data Type G96 in the Menu Database document,
P341/EN/MD
for details.
Opto I/P Status 0000000000000000
Duplicate. Displays the status of opto inputs.
Relay O/P Status 0000001000000000
Duplicate. Displays the status of output contacts.
Alarm Status 1 00000000000000000000000000000000
Duplicate of Alarm Status 1 above.
Alarm Status 2 00000000000000000000000000000000
This menu cell displays the status of the second 32 alarms as a binary string, a ‘1’ indicating an ON state and ‘0’ an OFF state.
See Data Type G128 in the Menu Database document, P341/EN/MD for details.
Alarm Status 3 00000000000000000000000000000000
This menu cell displays the status of the third 32 alarms as a binary string, a ‘1’ indicating an ON state and ‘0’ an OFF state.
Assigned specifically for platform alarms. See Data Type G228 in the Menu Database document, P341/EN/MD for details.
Access Level 2
Page (ST) 4-52 P341/EN ST/G74
MiCOM P341 TablesControl And Support Settings (ST) 4 Settings
Menu text Default setting
Min.
Setting range
SYSTEM DATA
Access Level. Read only. The table below describes the password control.
Max.
Set the "Password Control" cell to
The "Access Level" cell displays
Operations
0 0
access to all settings, alarms, event records and fault records
Execute Control Commands, e.g. circuit breaker open/close. Reset of fault and alarm conditions. Reset LEDs. Clearing of event and fault records.
0 0 all other settings
1 1
Read access to all settings, alarms, event records and fault records
Execute Control Commands, e.g. circuit
Step size
Type of Password required
None
Level 1 Password
Level 2 Password
None
None
1
2 (Default)
2 (Default)
1
2(Default)
2(Default) event and fault records.
Edit all other settings
Read access to all settings, alarms, event records and fault records
Execute Control Commands, e.g. circuit breaker open/close. Reset of fault and alarm conditions. Reset LEDs. Clearing of event and fault records.
Edit all other settings
0 2
Level 2 Password
None
None
2 (Default)
Password Control
2(Default)
2
Sets the menu access level for the relay. This setting can only be changed when level 2 access is enabled.
Password Level 1 ****
Password level 1 setting (4 characters).
Password Level 2 ****
Password level 2 setting (4 characters).
None
1
Table 24 - System data
P341/EN ST/G74 Page (ST) 4-53
(ST) 4 Settings MiCOM P341 TablesControl And Support Settings
4.2 View records
This menu provides information on fault and maintenance records. The relay will record the last 5 fault records and the last 10 maintenance records.
Menu text Default setting
VIEW RECORDS
0
Min.
Setting range
512
Max.
Step size
Select Event 0
Setting range from 0 to 249. This selects the required event record from the possible 250 that may be stored. A value of 0 corresponds to the latest event and so on.
Menu Cell Ref (From record)
Latched alarm active, Latched alarm inactive, Self reset alarm active, Self reset alarm inactive, Relay contact event, Optoisolated input event, Protection event, General event, Fault record event, Maintenance record event
Indicates the type of event.
Time and Date Data
Time & Date Stamp for the event given by the internal Real Time Clock.
Event text Data.
Up to 32 Character description of the Event. See event sheet in the Relay Menu Database document,
P341/EN/MD
or
Measurements and Recording chapter, P341/EN MR for details.
Event Value Data.
32 bit binary string indicating ON or OFF (1 or 0) status of relay contact or opto input or alarm or protection event depending on event type. Unsigned integer is used for maintenance records. See event sheet in the Relay Menu Database document,
P341/EN/MD
or the Measurements and Recording chapter,
P341/EN MR
for details.
Select Fault 0 0 4 1
Setting range from 0 to 4. This selects the required fault record from the possible 5 that may be stored. A value of 0 corresponds to the latest fault and so on.
Faulted Phase 00000000
Displays the faulted phase as a binary string, bits 0 – 8 = Start A/B/C/N Trip A/B/C/N.
Start elements 1 00000000000000000000000000000000
32 bit binary string gives status of first 32 start signals. See Data Type G84 in the Relay Menu Database document,
P341/EN/MD
for details.
Start elements 2 00000000000000000000000000000000
32 bit binary string gives status of second 32 start signals. See Data Type G107 in the Relay Menu Database document,
P341/EN/MD
for details.
Start elements 3 00000000000000000000000000000000
32 bit binary string gives status of third 32 start signals. See Data Type G129 in the Relay Menu Database document,
P341/EN/MD
for details.
Trip elements 1 00000000000000000000000000000000
32 bit binary string gives status of first 32 trip signals. See Data Type G85 in the Relay Menu Database document,
P34x/EN/MD
for details.
Trip elements 2 00000000000000000000000000000000
32 bit binary string gives status of second 32 trip signals. See Data Type G86 in the Relay Menu Database document,
P341/EN/MD
for details.
Trip elements 3 00000000000000000000000000000000
32 bit binary string gives status of third 32 trip signals. See Data Type G130 in the Relay Menu Database document,
P341/EN/MD for details.
Trip elements 4 00000000000000000000000000000000
32 bit binary string gives status of third 32 trip signals. See Data Type G132 in the Relay Menu Database document,
P341/EN/MD for details.
Page (ST) 4-54 P341/EN ST/G74
MiCOM P341 TablesControl And Support Settings (ST) 4 Settings
Menu text Default setting
VIEW RECORDS
Min.
Setting range
Max.
0000001000000000
Step size
Fault Alarms
32 bit binary string gives status of fault alarm signals. See Data Type G87 in the Relay Menu Database document,
P341/EN/MD
for details.
Fault Alarms2 0000001000000000
32 bit binary string gives status of fault alarm signals. See Data Type G89 in the Relay Menu Database document, P341EN/MD for details.
Data. Fault Time
Fault time and date.
Active Group
Active setting group 1-4.
Data.
System Frequency
System frequency.
Fault Duration
Data
Fault duration. Time from the start or trip until the undercurrent elements indicate the CB is open.
CB Operate Time Data.
CB operating time. Time from protection trip to undercurrent elements indicating the CB is open.
Relay Trip Time Data.
Relay trip time. Time from protection start to protection trip.
The following cells provide measurement information of the fault : IA, IB, IC, VAB, VBC, VCA, VAN, VBN, VCN,VN Measured,
VN Derived, I Sensitive, I2, V2, 3 Phase Watts, 3 Phase VARs, 3Ph Power Factor, df/dt, V Vector Shift, CLIO Input 1-4, df/dt,
DLR Ambient Temp, Wind Velocity, Wind Direction, Solar Radiation, DLR Ampacity, DLR CurrentRatio
Select Maint 0 0 4 1
Setting range from 0 to 4. This selects the required maintenance report from the possible 10 that may be stored. A value of 0 corresponds to the latest report and so on.
Maint Text Data.
Up to 32 Character description of the occurrence. See the Measurements and Recording chapter, P34x/EN MR for details.
Maint Type Data.
Maintenance record fault type. This will be a number defining the fault type.
Maint Data 0 0 4 1
Error code associated with the failure found by the self monitoring. The Maint Type and Data cells are numbers representative of the occurrence. They form a specific error code which should be quoted in any related correspondence to Report Data.
Reset Indication No No, Yes N/A
Resets latched LEDs and latched relay contacts provided the relevant protection element has reset.
Table 25 - View records settings
P341/EN ST/G74 Page (ST) 4-55
(ST) 4 Settings MiCOM P341 TablesControl And Support Settings
4.3 Measurements 1
This menu provides measurement information.
Menu text
Data.
Data.
Data.
Data.
Data.
Data.
Data. IN = IA+IB+IC, P341
Data.
Data.
Data.
Data. Positive sequence current.
Data. Negative sequence current.
Data. Zero sequence current.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Default setting
Min.
MEASUREMENTS 1
Setting range
Max.
IA Magnitude
IA Phase Angle
IB Magnitude
IB Phase Angle
IC Magnitude
IC Phase Angle
IN Derived Mag
IN Derived Angle
I Sen Magnitude
I Sen Angle
I1 Magnitude
I2 magnitude
I0 Magnitude
IA RMS
IB RMS
IC RMS
VAB Magnitude
VAB Phase Angle
VBC Magnitude
VBC Phase Angle
VCA Magnitude
VCA Phase Angle
VAN Magnitude
VAN Phase Angle
VBN Magnitude
VBN Phase Angle
VCN Magnitude
VCN Phase Angle
VN Measured Mag
VN Measured Ang
VN Derived Mag
VN Derived Ang
V1 Magnitude
V2 Magnitude
V0 Magnitude
Data.
Data.
Data.
Data. VN = VA+VB+VC.
Data.
Data. Positive sequence voltage.
Data. Negative sequence voltage.
Data. Zero sequence voltage.
VAN RMS
VBN RMS
VCN RMS
Data.
Data.
Data.
Frequency Data.
Page (ST) 4-56
Step size
P341/EN ST/G74
MiCOM P341 TablesControl And Support Settings (ST) 4 Settings
Menu text
I1 Magnitude
I1 Phase Angle
I2 Magnitude
I2 Phase Angle
I0 Magnitude
I0 Phase Angle
V1 Magnitude
V1 Phase Angle
V2 Magnitude
V2 Phase Angle
V0 Magnitude
V0 Phase Angle
C/S Voltage Mag
C/S Voltage Ang
CS Gen-Bus Volt
CS Gen-Bus Angle
Slip Frequency
CS Frequency
Default setting
Min.
MEASUREMENTS 1
Setting range
Max.
Data. Positive sequence current.
Data. Negative sequence current
Data.
Data. Zero sequence current.
Data.
Data. Positive sequence voltage.
Data. Negative sequence voltage.
Data. Zero sequence voltage.
Data. Check synchronization voltage.
Data. Check synchronization voltage.
Data. The difference voltage magnitude between generator and busbar.
Data. The difference voltage angle between generator and busbar.
Data. The difference frequency between generator and busbar.
Data. The frequency from the check synch voltage input.
Table 26 - Measurement 1 menu
4.4
Menu text
A Phase Watts
B Phase Watts
C Phase Watts
A Phase VARs
B Phase VARs
C Phase VARs
A Phase VA
B Phase VA
C Phase VA
3 Phase Watts
3 Phase VARs
3 Phase VA
3Ph Power Factor
APh Power Factor
BPh Power Factor
Measurements 2
This menu provides measurement information.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Default setting
Min.
MEASUREMENTS 2
Setting range
Max.
Step size
Step size
P341/EN ST/G74 Page (ST) 4-57
(ST) 4 Settings MiCOM P341 TablesControl And Support Settings
Menu text Default setting
Min.
MEASUREMENTS 2
Setting range
Max.
Step size
CPh Power Factor
3Ph WHours Fwd
3Ph WHours Rev
3Ph VArHours Fwd
3Ph VArHours Rev
3Ph W Fix Demand
3Ph VAr Fix Demand
IA Fixed Demand
IB Fixed Demand
IC Fixed Demand
3Ph W Roll Demand
3Ph VAr Roll Demand
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
IA Roll Demand
IB Roll Demand
IC Roll Demand
3Ph W Peak Demand
3Ph VAr Peak Demand
IA Peak Demand
IB Peak Demand
Data.
Data.
Data.
Data.
Data.
Data.
Data.
IC Peak Demand
Reset Demand
Data.
No No, Yes N/A
Reset demand measurements command. Can be used to reset the fixed, rolling and peak demand value measurements to 0.
Table 27 - Measurement 2 menu
4.5 Measurements 3
This menu provides measurement information.
Menu text Default setting
Min.
MEASUREMENTS 3
Setting range
Max.
APh Sen Watts
APh Sen VArs
APh Power Angle
Data.
Data.
Data.
Thermal Overload
Reset Thermal O/L
Data. Thermal state.
No No, Yes
Reset thermal overload command. Resets thermal state to 0.
CLIO Input 1 Data. Current loop (transducer) input 1.
CLIO Input 2
CLIO Input 3
CLIO Input 4
Data. Current loop (transducer) input 2.
Data. Current loop (transducer) input 3.
Data. Current loop (transducer) input 4.
N/A
Step size
Page (ST) 4-58 P341/EN ST/G74
MiCOM P341 TablesControl And Support Settings (ST) 4 Settings df/dt
Menu text Default setting
Min.
MEASUREMENTS 3
Setting range
Max.
Data. Rate of change of frequency
Table 28 - Measurement 3 menu
Step size
4.6 Measurements 4
This menu provides measurement information for the dynamic line rating protection used in the P341 version 7x software.
Menu text
Max Iac
DLR Ambient Temp
Wind Velocity
Wind Direction
Solar Radiation
Effct wind angle
Pc
Pc, natural
Pc1, forced
Pc2, forced
DLR Ampacity
DLR CurrentRatio
Dyn Conduct Temp
Steady Conduct T
Time Constant
Default setting
Min.
MEASUREMENTS 4
Data. Maximum phase current. (P341 7x)
Setting range
Max.
Step size
Data. Ambient Temperature from current loop input. (P341 7x)
Data. Wind Velocity from current loop input. (P341 7x)
Data. Wind Direction from current loop input. (P341 7x)
Data. Solar Radiation from current loop input. (P341 7x)
Data. Effective Wind Angle. Intermediate parameter calculated when calculating the convective cooling Pc. (P341 7x)
Data..Convective cooling, takes the maximum value of ‘Pc, natural’, ‘Pc1, forced’, and ‘Pc2, forced’. (P341 7x)
Data..Natural convective cooling, an intermediate value changed according to the selected standard (CIGRE or IEEE). (P341 7x)
Data. Forced convective cooling at low wind speed, an intermediate value changed according to the selected standard (CIGRE or IEEE). (P341 7x)
Data. Forced convective cooling at high wind speed, an intermediate value changed according to the selected standard (CIGRE or IEEE). (P341 7x)
Data. Calculated Ampacity (Amps). (P341 7x)
Data. Ratio of the maximum phase current and the calculated ampacity as a percentage.
(P341 7x)
Data. Real Time/Dynamic conductor temperature. (P341 7x)
Data. Steady State conductor temperature. (P341 7x)
Data. Conductor thermal time constant. (P341 7x)
Table 29 - Measurement 4 menu
P341/EN ST/G74 Page (ST) 4-59
(ST) 4 Settings MiCOM P341 TablesControl And Support Settings
4.7 Circuit Breaker Condition
The P341 relays include measurements to monitor the CB condition.
Menu text
CB Operations
Total IA Broken
Default setting
CB CONDITION
Data. Number of CB trip operations.
Min.
Setting range
Max.
Data. Accumulated broken current for A phase protection trip.
Step size
Total IB Broken
Total IC Broken
Data. Accumulated broken current for B phase protection trip.
Data. Accumulated broken current for C phase protection trip.
CB Operate Time
CB Close Time
Reset CB Data
Data. CB operating time = time from protection trip to undercurrent elements indicating the
CB is open.
Data. Circuit breaker close time = time from protection close to undercurrent elements indicating the CB is closed.
No No, Yes
Reset CB Data command. Resets CB Operations and Total IA/IB/IC broken current counters to 0.
N/A
Table 30 - Circuit breaker condition menu
4.8 Circuit Breaker Control
The P341 relays include settings to reset CB condition monitoring lockout alarms and set the type of CB auxiliary contacts that will be used to indicate the CB position.
Menu text
CB Control by
Default setting
Disabled
Min.
Setting range
Max.
CB CONTROL
Disabled, Local, Remote, Local+Remote,
Opto, Opto+local, Opto+Remote,
Opto+Rem+Local
CB control mode setting.
Close Pulse Time
Duration of the CB close pulse.
Trip Pulse Time
Duration of CB trip pulse.
0.5 s
0.5 s
0.1 s
0.1 s
10.00 s
5.00 s
Step size
0.01 s
0.01 s
Man Close Delay 10 s
Time delay setting before the close pulse is executed.
0.01 s 600 s 0.01 s
CB Healthy Time 5 s 0.01 s 9999 s 0.01 s
CB Healthy time delay check for manual CB closing. If the circuit breaker does not indicate a healthy condition in this time period following a close command then the relay will lockout and alarm.
Lockout Reset No No, Yes N/A
Reset Lockout command. Can be used to reset the CB condition monitoring lockout alarms.
Reset Lockout By CB Close User Interface, CB Close N/A
Setting to determines if a lockout condition will be reset by a manual circuit breaker close command or via the user interface.
Man Close RstDly 5 s 0.01 s 600 s 0.01 s
The manual close reset time. A lockout is automatically reset following a manual close after this time delay.
CB Status Input None None, 52A, 52B, Both 52A and 52B N/A
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MiCOM P341 TablesControl And Support Settings (ST) 4 Settings
Menu text Default setting
Min.
Setting range
Max.
CB CONTROL
Setting to define the type of circuit breaker contacts that will be used for the circuit breaker control logic.
Table 31 - Circuit breaker control settings
Step size
4.9 Date and Time
The date, time and battery condition are displayed.
Menu text Default setting
DATE AND TIME
Date/Time Data
Displays the relay’s current date and time.
IRIG-B Sync. Disabled
Enables or disables the IRIG-B time synchronization.
Min.
Setting range
Disabled or Enabled
Max.
IRIG-B Status Data
Card not fitted, Card failed, Signal healthy, No signal
Displays the status of IRIG-B.
Battery Status Dead, Healthy
Displays whether the battery is healthy or not.
N/A
N/A
Step size
Battery Alarm Enabled Disabled, Enabled N/A
Enables or disables battery alarm. The battery alarm needs to be disabled when a battery is removed or not used.
SNTP Status Data
Disabled, Trying Server1, Trying Server
2, Server 1 OK, Server 2 OK, No response, No Valid Clock
N/A
Displays information about the SNTP time synchronization status
LocalTime Enable Fixed Disabled, Fixed, Flexible N/A
Setting to turn on/off local time adjustments.
Disabled - No local time zone will be maintained. Time synchronization from any interface will be used to directly set the master clock and all displayed (or read) times on all interfaces will be based on the master clock with no adjustment.
Fixed - A local time zone adjustment can be defined using the LocalTime offset setting and all interfaces will use local time except SNTP time synchronization and IEC61850 timestamps.
Flexible - A local time zone adjustment can be defined using the LocalTime offset setting and each interface can be assigned to the UTC zone or local time zone with the exception of the local interfaces which will always be in the local time zone and
IEC61850/SNTP which will always be in the UTC zone.
LocalTime Offset
DST Enable
0 min
Enabled
-720 min
Disabled or Enabled
Setting to turn on/off daylight saving time adjustment to local time.
720 min 1 min
Setting to specify an offset of -12 to +12 hrs in 15 minute intervals for local time zone. This adjustment is applied to the time based on the master clock which is UTC/GMT
N/A
DST Offset 60 min 30 min 60 min
Setting to specify daylight saving offset which will be used for the time adjustment to local time.
DST Start Last First, Second, Third, Fourth, Last
Setting to specify the week of the month in which daylight saving time adjustment starts
DST Start Day Sunday
30 min
N/A
Sunday, Monday, Tuesday, Wednesday,
Thursday, Friday, Saturday
N/A
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(ST) 4 Settings MiCOM P341 TablesControl And Support Settings
Menu text Default setting
Min.
Setting range
Max.
DATE AND TIME
Setting to specify the day of the week in which daylight saving time adjustment starts
Step size
DST Start Month March
January, February, March, April, May,
June, July, August, September,
November, December
Setting to specify the month in which daylight saving time adjustment starts
DST Start Mins 60 min 0 min 1425 min
N/A
15 min
Setting to specify the time of day in which daylight saving time adjustment starts. This is set relative to 00:00 hrs on the selected day when time adjustment is to start.
DST End Last First, Second, Third, Fourth, Last N/A
Setting to specify the week of the month in which daylight saving time adjustment ends.
DST End Day Sunday
Sunday, Monday, Tuesday, Wednesday,
Thursday, Friday, Saturday
N/A
Setting to specify the day of the week in which daylight saving time adjustment ends
DST End Month October
January, February, March, April, May,
June, July, August, September,
November, December
Setting to specify the month in which daylight saving time adjustment ends
N/A
DST End Mins 60 min 0 min 1425 min 15 min
Setting to specify the time of day in which daylight saving time adjustment ends. This is set relative to 00:00 hrs on the selected day when time adjustment is to end.
RP1 Time Zone Local UTC, Local N/A
Setting for the rear port 1 interface to specify if time synchronization received will be local or universal time co-ordinated
RP2 Time Zone Local UTC, Local N/A
Setting for the rear port 2 interface to specify if time synchronization received will be local or universal time co-ordinated
Tunnel Time Zone Local UTC, Local N/A
Setting to specify if time synchronization received will be local or universal time co-ordinate when ‘tunneling’ courier protocol over Ethernet.
Table 32 - Date and time menu
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MiCOM P341 TablesControl And Support Settings (ST) 4 Settings
4.10 CT and VT Ratios
Menu text Default setting
CT AND VT RATIOS
Main VT Primary 110.0 V
Main voltage transformer input, primary voltage setting.
100
Min.
Setting range
Max.
1000 kV
Main VT Sec’y 110.0 V
Main transformer input, secondary voltage setting.
80 140
C/S VT Primary 110.0 V 100 1000 kV
Sets the check sync. voltage transformer input primary voltage (P341 60TE case version only).
C/S VT Secondary 110.0 V 80 140
Sets the check sync. voltage transformer input secondary voltage (P341 60TE case version only).
VN Primary 110.0 V 100
VN input, primary voltage setting. VN1 is the neutral voltage input.
1000 kV
1
1
1
1
1
Step size
VN Secondary 110.0 V
VN input, secondary voltage setting.
80 140
Ph CT Polarity Standard Standard, Inverted
Phase CT polarity selection. This setting can be used to easily reverse the CT polarity for wiring errors.
1 60 k Phase CT Primary 1.000 A
Phase current transformer input, primary current rating setting.
Phase CT Sec’y 1.000 A 1 5
1
1
4
Phase current transformer input, secondary current rating setting.
Isen CT Polarity Standard Standard, Inverted
Sensitive Current transformer polarity selection. This setting can be used to easily reverse the CT polarity for wiring errors.
Isen CT Primary 1.000 A 1 60 k 1
Sensitive current transformer input, primary current rating setting.
Isen CT Secondary 1.000 A 1
Sensitive current transformer input, secondary current rating setting.
5 4
Table 33 - CT and VT ratio settings
P341/EN ST/G74 Page (ST) 4-63
(ST) 4 Settings MiCOM P341 TablesControl And Support Settings
4.11 Record Control
It is possible to disable the reporting of events from all interfaces that support setting changes. The settings that control the reporting of various types of events are in the
Record Control column. The effect of setting each to disabled is as follows:
Menu text Default setting
RECORD CONTROL
No
Clear Faults No
Selecting “Yes” will cause the existing fault records to be erased from the relay.
Clear Maint. No
Selecting “Yes” will cause the existing maintenance records to be erased from the relay.
Available settings
Clear Events No, Yes
Selecting “Yes” will cause the existing event log to be cleared and an event will be generated indicating that the events have been erased.
No, Yes
No, Yes
Alarm Event Enabled
Disabling this setting means that no event will be generated for all alarms.
Disabled, Enabled
Relay O/P Event Enabled Disabled, Enabled
Disabling this setting means that no event will be generated for any change in relay output contact state.
Opto Input Event Enabled Disabled, Enabled
Disabling this setting means that no event will be generated for any change in logic input state.
General Event Enabled Disabled, Enabled
Disabling this setting means that no General Events will be generated. See the event record sheet in the Relay Menu Database document , P34x/EN MD for the list of general events.
Fault Rec Event Enabled Disabled, Enabled
Disabling this setting means that no event will be generated for any fault that produces a fault record.
Maint. Rec Event Enabled Disabled, Enabled
Disabling this setting means that no event will be generated for any maintenance records.
Protection Event Enabled Disabled, Enabled
Disabling this setting means that no event will be generated for any operation of the protection elements.
Clear Dist Recs No No, Yes
Selecting “Yes” will cause the existing disturbance records to be erased from the relay.
DDB 31 - 0 11111111111111111111111111111111
32 bit setting to enable or disable the event recording for DDBs 0-31. For each bit 1 = event recording Enabled, 0 = event recording Disabled.
DDB 2047 - 2016 11111111111111111111111111111111
32 bit setting to enable or disable the event recording for DDBs 2047 - 2016. For each bit 1 = event recording Enabled, 0 = event recording Disabled. There are similar cells showing 32 bit binary strings for all DDBs from 0 – 2047. The first and last 32 bit binary strings only are shown here.
Table 34 - Record control menu
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MiCOM P341 TablesControl And Support Settings (ST) 4 Settings
4.12 Disturbance Recorder Settings
The disturbance recorder settings include the record duration and trigger position, selection of analog and digital signals to record, and the signal sources that trigger the recording.
Menu text Default setting
Min.
DISTURB RECORDER
Setting range
Max.
Step size
Duration
Overall recording time setting.
1.5 s 0.1 s 10.5 s 0.01 s
Trigger Position 33.3% 0 100% 0.1%
Trigger point setting as a percentage of the duration. For example, the default settings show that the overall recording time is set to 1.5 s with the trigger point being at 33.3% of this, giving 0.5 s pre-fault and 1 s post fault recording times.
Trigger Mode Single Single, Extended
If set to single mode and a further trigger occurs while a recording is taking place, the recorder will ignore the trigger. However, if this has been set to "Extended", the post trigger timer will be reset to zero, thereby extending the recording time.
Analog. Channel 1 VA
Unused, VA, VB, VC, VN, IA, IB, IC, ISensitive, Frequency,
C/S Voltage.
Selects any available analog input to be assigned to this channel.
Analog. Channel 2 VB As above
Analog. Channel 3
Analog. Channel 4
Analog. Channel 5
VC
VN
IA
As above
As above
As above
Analog. Channel 6
Analog. Channel 7
Analog. Channel 8
Digital Inputs 1 to 32
IB
IC
I Sensitive
Relays 1 to 7 and Opto’s 1 to
8
As above
As above
As above
Any of 7 O/P Contacts or Any of 8 Opto Inputs or Internal
Digital Signals
The digital channels may be mapped to any of the opto isolated inputs or output contacts, in addition to a number of internal relay digital signals, such as protection starts, LEDs etc.
Inputs 1 to 32 Trigger
No Trigger except Dedicated
Trip Relay O/P’s which are set to Trigger L/H
No Trigger, Trigger L/H, Trigger H/L
Any of the digital channels may be selected to trigger the disturbance recorder on either a low to high (L/H) or a high to low
(H/L) transition.
Table 35 - Disturbance record settings
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(ST) 4 Settings MiCOM P341 TablesControl And Support Settings
4.13 Measurement Setup
Menu text Default settings
MEASURE’T SETUP
Available settings
Default Display Description
Description, Plant Reference, Frequency,
Access Level, 3Ph + N Current, 3Ph Voltage,
Power, Date and Time
This setting can be used to select the default display from a range of options, note that it is also possible to view the other default displays whilst at the default level using the and keys. However once the 15 minute timeout elapses the default display will revert to that selected by this setting.
Local Values Primary Primary, Secondary
This setting controls whether measured values via the front panel user interface and the front courier port are displayed as primary or secondary quantities.
Remote Values Primary Primary, Secondary
This setting controls whether measured values via the rear communication port are displayed as primary or secondary quantities.
Measurement Ref. VA VA, VB, VC, IA, IB, IC
Using this setting the phase reference for all angular measurements by the relay can be selected.
Measurement Mode 0 0 to 3 step 1
This setting is used to control the signing of the real and reactive power quantities; the signing convention used is defined in the
Measurements and Recording chapter.
Fix Dem Period 30 minutes
This setting defines the length of the fixed demand window.
1 to 99 minutes step 1 minute
Roll Sub Period
Num Sub Periods
30 minutes
1
This setting is used to set the number of rolling demand sub periods.
1 to 99 minutes step 1 minute
The rolling demand uses a sliding/rolling window. The rolling demand window consists of a number of smaller sub periods
(Num Sub Periods). The resolution of the rolling window is the sub period length (Roll Sub Period) with the displayed values being updated at the end of each sub period.
1 to 15 step 1
Remote 2 Values Primary Primary, Secondary
This setting controls whether measured values via the 2nd rear communication port are displayed as primary or secondary quantities.
Table 36 - Measurement setup settings
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MiCOM P341 TablesControl And Support Settings (ST) 4 Settings
4.14 Communications
The communications settings apply to the rear communications ports only and will depend upon the particular protocol being used. For further details see the SCADA
Communications chapter.
4.14.1 Communication Settings for Courier Protocol
Menu text Default setting
COMMUNICATIONS
Min.
Setting range
Max.
RP1 Protocol Courier
Indicates the communications protocol that will be used on the rear communications port.
RP1 Address 255 0 255 1
This cell sets the unique address for the relay such that only one relay is accessed by master station software.
Step size
RP1 Inactiv Timer 15 mins. 1 mins. 30 mins.
This cell controls how long the relay will wait without receiving any messages on the rear port before it reverts to its default state, including resetting any password access that was enabled.
RP1 Physical Link Copper Copper, Fiber Optic, KBus
1 min.
This cell defines whether an electrical EIA(RS)485, fiber optic or KBus connection is being used for communication between the master station and relay. If ‘Fiber Optic’ is selected, the optional fiber optic communications board will be required.
RP1 Card Status RP1 Card Status
Rear Port 1 Courier Protocol Status.
RP1 Port Config. KBus KBus, EIA(RS)485
This cell defines whether an electrical KBus or EIA(RS)485 is being used for communication between the master station and relay.
RP1 Comms Mode IEC 60870 FT1.2 Frame
IEC 60870 FT1.2 Frame,
10-Bit No Parity
The choice is either IEC 60870 FT1.2 for normal operation with 11-bit modems, or 10-bit no parity.
RP1 Baud Rate 19200 bits/s 9600 bits/s, 19200 bits/s, 38400 bits/s
This cell controls the communication speed between relay and master station. It is important that both relay and master station are set at the same speed setting.
Table 37 - Communication settings for courier protocol
P341/EN ST/G74 Page (ST) 4-67
(ST) 4 Settings MiCOM P341 TablesControl And Support Settings
4.14.2 Communication Settings for MODBUS Protocol
Menu text Default setting
Min.
COMMUNICATIONS
Setting range
Max.
MODBUS RP1 Protocol
Indicates the communications protocol that will be used on the rear communications port.
RP1 Address 1 1 247 1
This cell sets the unique address for the relay such that only one relay is accessed by master station software.
Step size
RP1 Inactiv Timer 15 mins. 1 mins. 30 mins. 1 min.
This cell controls how long the relay will wait without receiving any messages on the rear port before it reverts to its default state, including resetting any password access that was enabled.
RP1 Baud Rate 19200 bits/s 9600 bits/s, 19200 bits/s, 38400 bits/s
This cell controls the communication speed between relay and master station. It is important that both relay and master station are set at the same speed setting.
RP1 Parity None Odd, Even, None
This cell controls the parity format used in the data frames. It is important that both relay and master station are set with the same parity setting.
RP1 Physical Link Copper Copper, Fiber Optic
This cell defines whether an electrical EIA(RS) 485 or fiber optic connection is being used for communication between the master station and relay. If ‘Fiber Optic’ is selected, the optional fiber optic communications board will be required.
MODBUS IEC Time Standard IEC Standard IEC, Reverse
When ‘Standard IEC’ is selected the time format complies with IEC 60870-5-4 requirements such that byte 1 of the information is transmitted first, followed by bytes 2 through to 7. If ‘Reverse’ is selected the transmission of information is reversed.
Table 38 - Communication settings for MODBUS protocol
4.14.3 Communication Settings for IEC 60870-5-103 Protocol
Menu text Default setting
Min.
COMMUNICATIONS
Setting range
Max.
IEC60870-5-103 RP1 Protocol
Indicates the communications protocol that will be used on the rear communications port.
RP1 Address 1 0 247 1
This cell sets the unique address for the relay such that only one relay is accessed by master station software.
Step size
RP1 Inactiv Timer 15 mins. 1 mins. 30 mins. 1 min.
This cell controls how long the relay will wait without receiving any messages on the rear port before it reverts to its default state, including resetting any password access that was enabled.
RP1 Baud Rate 19200 bits/s 9600 bits/s, 19200 bits/s
This cell controls the communication speed between relay and master station. It is important that both relay and master station are set at the same speed setting.
RP1 Measure’t Period 15 s 1 s 60 s 1 s
This cell controls the time interval that the relay will use between sending measurement data to the master station.
RP1 Physical Link Copper Copper, Fiber Optic
This cell defines whether an electrical EIA(RS) 485 or fiber optic connection is being used for communication between the master station and relay. If ‘Fiber Optic’ is selected, the optional fiber optic communications board will be required.
RP1 CS103 Blocking Disabled Disabled, Monitor Blocking, Command Blocking
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Menu text Default setting
Min.
COMMUNICATIONS
Setting range
Max.
There are three settings associated with this cell:
Disabled
Monitor Blocking
Command Blocking
Step size
No blocking selected
When the monitor blocking DDB Signal is active high, either by energizing an opto input or control input, reading of the status information and disturbance records is not permitted. When in this mode the relay returns a “termination of general interrogation” message to the master station.
When the command blocking DDB signal is active high, either by energizing an opto input or control input, all remote commands will be ignored (i.e. CB Trip/Close, change setting group etc.). When in this mode the relay returns a “negative acknowledgement of command” message to the master station.
Table 39 - Communication settings for IEC-103 protocol
4.14.4 Communication Settings for DNP3.0 Protocol
Menu text Default setting
Min.
COMMUNICATIONS
Setting range
Max.
Step size
RP1 Protocol DNP 3.0
Indicates the communications protocol that will be used on the rear communications port.
RP1 Address 3 0 65519 1
This cell sets the unique address for the relay such that only one relay is accessed by master station software.
RP1 Baud Rate 19200 bits/s
1200 bits/s, 2400 bits/s, 4800 bits/s, 9600 bits/s, 19200 bits/s or 38400 bits/s
This cell controls the communication speed between relay and master station. It is important that both relay and master station are set at the same speed setting.
RP1 Parity None Odd, Even, None
This cell controls the parity format used in the data frames. It is important that both relay and master station are set with the same parity setting.
RP1 Physical Link Copper Copper, Fiber Optic
This cell defines whether an electrical EIA(RS) 485 or fiber optic connection is being used for communication between the master station and relay. If ‘Fiber Optic’ is selected, the optional fiber optic communications board will be required.
RP1 Time Sync. Disabled Disabled, Enabled
If set to ‘Enabled’ the DNP3.0 master station can be used to synchronize the time on the relay. If set to ‘Disabled’ either the internal free running clock, or IRIG-B input are used.
30 mins 1 mins DNP Need Time 10 mins. 1 mins.
The duration of time waited, before requesting another time sync from the master.
DNP App Fragment 2048 bytes 100 bytes
The maximum message length (application fragment size) transmitted by the relay.
2048 bytes 1 byte
DNP App Timeout 2 s 1 s 120 s
Duration of time waited, after sending a message fragment and awaiting a confirmation from the master.
DNP SBO Timeout 10 s 1 s 10 s
1 s
1 s
Duration of time waited, after receiving a select command and awaiting an operate confirmation from the master.
DNP Link Timeout 0 s 0 s 120 s 1 s
Duration of time that the relay will wait for a Data Link Confirm from the master. A value of 0 means data link support disabled and 1 to 120 seconds is the timeout setting.
Table 40 - Communication settings for DNP3.0 protocol
P341/EN ST/G74 Page (ST) 4-69
(ST) 4 Settings MiCOM P341 TablesControl And Support Settings
4.14.5 Communication Settings for Ethernet Port
Menu text
NIC Protocol
Default setting
IEC 61850
Indicates that IEC 61850 will be used on the rear Ethernet port.
NIC MAC Address Ethernet MAC Address
Indicates the MAC address of the rear Ethernet port.
Min.
Setting range
Max.
Step size
NIC Tunl Timeout 5 mins 1 min
Duration of time waited before an inactive tunnel to S1 Studio is reset.
NIC Link Report Alarm Alarm, Event, None
Configures how a failed/unfitted network link (copper or fiber) is reported:
Alarm -
Event - an alarm is raised for a failed link an event is logged for a failed link
30 mins 1 min
None - nothing reported for a failed link
NIC Link Timeout 60 s 0.1 s 60 s 0.1 s
Duration of time waited, after failed network link is detected, before communication by the alternative communications interface
(fiber optic/copper interface) is attempted.
See also the IED CONFIGURATOR column for IEC 61850 data.
Table 41 - Ethernet port communication settings
4.14.6 Rear Port 2 Connection Settings
The settings shown are those configurable for the second rear port which is only available with the courier protocol.
Menu text Default setting
COMMUNICATIONS
Min.
Setting range
Max.
RP2 Protocol Courier
Indicates the communications protocol that will be used on the 2nd rear communications port.
RP2 Card Status K-Bus OK, RS485 OK, Fiber Optic OK
Step size
Rear Port 2 Courier Protocol Status.
RP2 Port Config. RS232 EIA(RS)232, EIA(RS)485, KBus
This cell defines whether an electrical EIA(RS)232, EIA(RS)485 or KBus is being used for communication.
RP2 Comms. Mode IEC 60870 FT1.2 Frame IEC60870 FT1.2 Frame, 10-Bit No Parity
The choice is either IEC60870 FT1.2 for normal operation with 11-bit modems, or 10-bit no parity.
RP2 Address 255 0 255 1
This cell sets the unique address for the relay such that only one relay is accessed by master station software.
RP2 Inactiv Timer 15 mins. 1 mins. 30 mins. 1 min.
This cell controls how long the relay will wait without receiving any messages on the rear port before it reverts to its default state, including resetting any password access that was enabled.
RP2 Baud Rate 19200 bits/s 9600 bits/s, 19200 bits/s, 38400 bits/s
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MiCOM P341 TablesControl And Support Settings (ST) 4 Settings
Menu text Default setting
Min.
Setting range
Max.
Step size
COMMUNICATIONS
This cell controls the communication speed between relay and master station. It is important that both relay and master station are set at the same speed setting.
Table 42 - Rear port connection settings
P341/EN ST/G74 Page (ST) 4-71
(ST) 4 Settings MiCOM P341 TablesControl And Support Settings
4.15 Commissioning Tests
There are menu cells which allow the status of the opto-isolated inputs, output relay contacts, internal digital data bus (DDB) signals and user-programmable LEDs to be monitored. Also, there are cells to test the operation of the output contacts and userprogrammable LEDs.
Menu text Default setting
COMMISSION TESTS
Available settings
Opto I/P Status 0000000000000000
This menu cell displays the status of the relay’s opto-isolated inputs as a binary string, a ‘1’ indicating an energized optoisolated input and a ‘0’ a de-energized one.
Relay O/P Status 0000000000000000
This menu cell displays the status of the relay’s output contacts as a binary string, a ‘1’ indicating an operated state and ‘0’ a non-operated state.
When the ‘Test Mode’ cell is set to ‘Enabled’ the ‘Relay O/P Status’ cell does not show the current status of the output relays and hence can not be used to confirm operation of the output relays. Therefore it will be necessary to monitor the state of each contact in turn.
Test Port Status 00000000
This menu cell displays the status of the eight digital data bus (DDB) signals that have been allocated in the ‘Monitor Bit’ cells.
Monitor Bit 1 64 (LED 1)
0 to 2047 See PSL chapter for details of digital data bus signals
The eight ‘Monitor Bit’ cells allow the user to select the status of which digital data bus signals can be observed in the ‘Test Port
Status’ cell or via the monitor/download port.
Monitor Bit 8 71 (LED 8) 0 to 2047
The eight ‘Monitor Bit’ cells allow the user to select the status of which digital data bus signals can be observed in the ‘Test Port
Status’ cell or via the monitor/download port.
Test Mode Disabled
Disabled, Test Mode, Contacts
Blocked
The Test Mode menu cell is used to allow secondary injection testing to be performed on the relay without operation of the trip contacts. It also enables a facility to directly test the output contacts by applying menu controlled test signals. To select test mode the Test Mode menu cell should be set to ‘Test Mode’, which takes the relay out of service and blocks the maintenance, counters. It also causes an alarm condition to be recorded and the yellow ‘Out of Service’ LED to illuminate and an alarm message ‘Prot’n. Disabled’ is given. This also freezes any information stored in the CB Condition column and in IEC60870-5-
103 builds changes the Cause of Transmission, COT, to Test Mode. To enable testing of output contacts the Test Mode cell should be set to Contacts Blocked. This blocks the protection from operating the contacts and enables the test pattern and contact test functions which can be used to manually operate the output contacts. Once testing is complete the cell must be set back to ‘Disabled’ to restore the relay back to service.
Test Pattern 00000000000000000000000000000000 0 = Not Operated 1 = Operated
This cell is used to select the output relay contacts that will be tested when the ‘Contact Test’ cell is set to ‘Apply Test’.
Contact Test No Operation
No Operation, Apply Test,
Remove Test
When the ‘Apply Test’ command in this cell is issued the contacts set for operation (set to ‘1’) in the ‘Test Pattern’ cell change state. After the test has been applied the command text on the LCD will change to ‘No Operation’ and the contacts will remain in the Test State until reset issuing the ‘Remove Test’ command. The command text on the LCD will again revert to ‘No
Operation’ after the ‘Remove Test’ command has been issued.
Note: When the ‘Test Mode’ cell is set to ‘Enabled’ the ‘Relay O/P Status’ cell does not show the current status of the output relays and hence can not be used to confirm operation of the output relays. Therefore it will be necessary to monitor the state of each contact in turn.
Test LEDs No Operation No Operation Apply Test
When the ‘Apply Test’ command in this cell is issued the 8 user-programmable LEDs will illuminate for approximately 2 seconds before they extinguish and the command text on the LCD reverts to ‘No Operation’.
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MiCOM P341 TablesControl And Support Settings (ST) 4 Settings
Menu text Default setting
COMMISSION TESTS
DDB 31 - 0 00000000000000000000001000000000
Displays the status of DDB signals 0-31.
Available settings
DDB 2047 - 2016 00000000000000000000000000000000
Displays the status of DDB signals 2047 – 2016. There are similar cells showing 32 bit binary strings for all DDBs from 0 –
2047. The first and last 32 bit words only are shown here.
Table 43 - Commissioning tests menu cells
P341/EN ST/G74 Page (ST) 4-73
(ST) 4 Settings MiCOM P341 TablesControl And Support Settings
4.16 Circuit Breaker Condition Monitor Setup
The Circuit Breaker condition monitoring includes features to monitor the CB condition such as the current broken, number of CB operations, number of CB operations in a set time and CB operating time. Alarms or a circuit breaker lockout can be raised for different threshold values.
Menu text Default setting
Min.
Setting range
Max.
Step size
Broken I^ 2
CB MONITOR SETUP
1 2 0.1
This sets the factor to be used for the cumulative I^ counter calculation that monitors the cumulative severity of the duty placed on the interrupter. This factor is set according to the type of Circuit Breaker used.
I^ Maintenance Alarm Disabled Alarm Disabled, Alarm Enabled
Enables or disables the cumulative I^ maintenance alarm element.
I^ Maintenance 1000 In^ 1 In^ 25000 In^ 1 In^
Threshold setting for the cumulative I^ maintenance counter. This alarm indicates when preventative maintenance is due.
I^ Lockout Alarm Disabled
Enables or disables the cumulative I^lockout element.
Alarm Disabled, Alarm Enabled
I^ Lockout 2000 In^ 1 In^ 25000 In^ 1 In^
Threshold setting for the cumulative I^ lockout counter. The relay can be used to lockout the CB reclosing if maintenance is not carried out on reaching this lockout threshold.
No CB Ops Maint. Alarm Disabled Alarm Disabled, Alarm Enabled
Number of circuit breaker operations setting for the maintenance alarm.
No CB Ops Maint. 10 1 10000 1
Threshold setting for number of circuit breaker operations for the maintenance alarm. This alarm indicates when preventative maintenance is due.
No CB Ops Lock Alarm Disabled Alarm Disabled, Alarm Enabled
Enables or disables the number of circuit breaker operations lockout alarm.
No CB Ops Lock 20 1 10000 1
Threshold setting for number of circuit breaker operations for maintenance lockout. This lockout alarm can be used to block or lockout the CB reclosing if maintenance is not carried out on reaching this lockout threshold.
CB Time Maint Alarm Disabled Alarm Disabled, Alarm Enabled
Enables or disables the circuit breaker operating time maintenance alarm.
CB Time Maint 0.1 s 0.005 s 0.5 s 0.001 s
Circuit breaker operating time threshold setting. This alarm is set in relation to the specified interrupting time of the circuit breaker.
CB Time Lockout Alarm Disabled Alarm Disabled, Alarm Enabled
Enables or disables the circuit breaker operating time lockout alarm.
CB Time Lockout
Fault Freq Lock
0.2 s
Alarm Disabled
Enables or disables the fault frequency counter alarm.
0.005 s 0.5 s 0.001 s
Circuit breaker operating time threshold setting. This lockout alarm is set in relation to the specified interrupting time of the circuit breaker.
Alarm Disabled, Alarm Enabled
Fault Freq Count 10 1 9999 1
Circuit breaker frequent operations counter setting. This element monitors the number of operations over a set time period.
Fault Freq. Time 3600 s 0 9999 s 1 s
Page (ST) 4-74 P341/EN ST/G74
MiCOM P341 TablesControl And Support Settings (ST) 4 Settings
Menu text Default setting
Min.
Setting range
Max.
CB MONITOR SETUP
Time period setting over which the circuit breaker frequent operations are to be monitored.
Table 44 - Circuit breaker condition monitoring menu
Step size
4.17 Opto Configuration
Menu text Default setting
OPTO CONFIG.
Min.
Setting range
Max.
Step size
Global Nominal V 24 - 27 24 - 27, 30 - 34, 48 - 54, 110 - 125, 220 - 250, Custom
Sets the nominal battery voltage for all opto inputs by selecting one of the five standard ratings in the Global Nominal V settings. If Custom is selected then each opto input can individually be set to a nominal voltage value.
Opto Input 1 24 - 27 24 - 27, 30 - 34, 48 - 54, 110 - 125, 220 - 250
Each opto input can individually be set to a nominal voltage value if custom is selected for the global setting.
Opto Input 2 - 24 24 - 27 24 - 27, 30 - 34, 48 - 54, 110 - 125, 220 - 250
Each opto input can individually be set to a nominal voltage value if custom is selected for the global setting.
Opto Filter Cntl. 1111111111111111 0 = Disable Filtering 1 = Enable filtering
A binary string is used to represent the opto inputs available. A ‘1’ or ‘0’ is used to enable or disable for each input a pre-set filter of ½ cycle that renders the input immune to induced ac noise on the wiring.
Characteristics
Standard
60% - 80%
Standard 60% - 80%, 50% - 70%
Selects the pick-up and drop-off characteristics of the optos. Selecting the standard setting means they nominally provide a
Logic 1 or On value for Voltages 80% of the set lower nominal voltage and a Logic 0 or Off value for the voltages 60% of the set higher nominal voltage.
Table 45 - Opto inputs configuration settings
4.18 Control Inputs
The control inputs function as software switches that can be set or reset either locally or remotely. These inputs can be used to trigger any function that they are connected to as part of the PSL.
Menu text Default setting
CONTROL INPUTS
Setting range Step size
Ctrl I/P Status 00000000000000000000000000000000
0 = Reset (Not Operated/OFF)
1 = Set (Operated/ON)
This menu cell displays the status of the relay’s control inputs as a binary string, a ‘1’ indicating an Set control input and a ‘0’ a
Reset one.
Control Input 1 to 32 No Operation No Operation, Set, Reset
When the ‘Set’ command in this cell is issued the Control Input 1 is set ON and when the ‘Reset’ command in this cell is issued the Control Input 1 is set OFF.
Table 46 - Control inputs settings
P341/EN ST/G74 Page (ST) 4-75
(ST) 4 Settings MiCOM P341 TablesControl And Support Settings
4.19 Control Input Configuration
The control inputs function as software switches that can be set or reset either locally or remotely. These inputs can be used to trigger any function that they are connected to as part of the PSL.
Menu text
Hotkey Enabled
Default setting
CTRL I/P CONFIG.
11111111111111111111111111111111
Setting range Step size
Setting to allow the control inputs to be individually assigned to the “Hotkey” menu by setting ‘1’ in the appropriate bit in the
“Hotkey Enabled” cell. The hotkey menu allows the control inputs to be set, reset or pulsed without the need to enter the
“CONTROL INPUTS” column.
Control Input 1 Latched Latched, Pulsed
Configures the control inputs as either ‘latched’ or ‘pulsed’. A latched control input will remain in the set state until a reset command is given, either by the menu or the serial communications. A pulsed control input, however, will remain energized for
10 ms after the set command is given and will then reset automatically (i.e. no reset command required).
Ctrl Command 1 Set/Reset Set/Reset, In/Out, Enabled/Disabled, On/Off
Allows the SET / RESET text, displayed in the hotkey menu, to be changed to something more suitable for the application of an individual control input, such as “ON / OFF”, “IN / OUT”, “ENABLED / DISABLED”.
Control Input 2 to 32 Latched
Configures the control inputs as either ‘latched’ or ‘pulsed’.
Latched, Pulsed
Ctrl Command 2 to 32 Set/Reset Set/Reset, In/Out, Enabled/Disabled, On/Off
Allows the SET / RESET text, displayed in the hotkey menu, to be changed to something more suitable for the application of an individual control input, such as “ON / OFF”, “IN / OUT”, “ENABLED / DISABLED”.
Table 47 - Control inputs configuration settings
4.20 Control Input Labels
Menu text Default setting
CTRL I/P LABELS
Setting range Step size
Control Input 1 Control Input 1 16 Character Text
Text label to describe each individual control input. This text will be displayed when a control input is accessed by the hotkey menu and it is displayed in the programmable scheme logic description of the control input.
Control Input 2 to 32 Control Input 2 to 32 16 Character Text
Text label to describe each individual control input. This text will be displayed when a control input is accessed by the hotkey menu and it is displayed in the programmable scheme logic description of the control input.
Table 48 - Control input label settings
Page (ST) 4-76 P341/EN ST/G74
MiCOM P341 TablesControl And Support Settings (ST) 4 Settings
4.21 IED Configurator (for IEC 61850 Configuration)
The contents of the IED CONFIGURATOR column are mostly data cells, displayed for information but not editable. In order to edit the configuration, it is necessary to use the
IED Configurator tool within S1 Studio.
Menu text Default setting
Min.
IED CONFIGURATOR
Setting range
Max.
Step size
Switch Conf.Bank No Action No Action, Switch Banks
Setting which allows the user to switch between the current configuration, held in the Active Memory Bank (and partly displayed below), to the configuration sent to and held in the Inactive Memory Bank.
Restore MCL No Action No Action, Restore MCL
Setting which allows the user to reset any changes and restores the MCL stored in the relay.
Active Conf.Name Data
The name of the configuration in the Active Memory Bank, usually taken from the SCL file.
Active Conf.Rev Data
Configuration Revision number of the configuration in the Active Memory Bank, usually taken from the SCL file.
Inact.Conf.Name Data
The name of the configuration in the Inactive Memory Bank, usually taken from the SCL file.
Inact.Conf.Rev Data
Configuration Revision number of the configuration in the Inactive Memory Bank, usually taken from the SCL file.
IP PARAMETERS
IP Address Data
Displays the unique network IP address that identifies the relay.
Subnet Mask Data
Displays the sub-network that the relay is connected to.
Gateway Data
Displays the IP address of the gateway (proxy) that the relay is connected to, if any.
SNTP PARAMETERS
SNTP Server 1 Data
Displays the IP address of the primary SNTP server.
SNTP Server 2 Data
Displays the IP address of the secondary SNTP server.
IEC 61850 SCL
IED Name Data
8 character IED name, which is the unique name on the IEC 61850 network for the IED, usually taken from the SCL file.
IEC 61850 GOOSE
GoEna 00000000 0 = Disabled, 1 = Enabled
Setting to enable GOOSE settings, GOOSE configuration blocks (GCB) 1 to 8.
Test Mode 00000000
The Test Mode bit sets the test flag in the outgoing (published) Goose message. Each bit corresponds to one of the eight
GOCBs in the same way that the GOEna bits enable or disable the corresponding Goose message. Clearing the test mode bit clears the test flag of the published Goose message. The data in the Goose message is unaffected.
VOP Test Pattern 0x00000000
The 32-bit test pattern applied in ‘Forced’ test mode.
0x00000000 0xFFFFFFFF 1
Ignore Test Flag No No, Yes
P341/EN ST/G74 Page (ST) 4-77
(ST) 4 Settings MiCOM P341 TablesControl And Support Settings
Menu text Default setting
Min.
Setting range
Max.
IED CONFIGURATOR
When set to ‘Yes’, the test flag in the subscribed GOOSE message is ignored, and the data treated as normal.
Step size
Table 49 - IEC-61850 IED configurator
Page (ST) 4-78 P341/EN ST/G74
MiCOM P341 (OP) 5 Operation
P341/EN OP/G74
OPERATION
CHAPTER 5
Page (OP) 5-1
(OP) 5 Operation
Hardware Suffix:
Software Version:
Connection Diagrams:
J (P341)
36 and 71 (with DLR)
10P341xx (xx = 01 to 12)
MiCOM P341
Page (OP) 5-2 P341/EN OP/G74
Contents (OP) 5 Operation
CONTENTS
Page (OP) 5-
1 Operation of Individual Protection Functions 7
Rate of Change of Frequency Protection (81R)
Voltage Vector Shift Protection (
Δ
θ
Reverse Power/Over Power/Low Forward Power (32R/32O/32L)
Sensitive Power Protection Function
Overcurrent Protection (50/51)
Directional Overcurrent Protection (67)
Negative Phase Sequence (NPS) Overcurrent Protection (46)
Earth Fault Protection (50N/51N)
Standard Earth Fault Protection Element
Sensitive Earth Fault (SEF) Protection Element
Directional Earth Fault (DEF) Protection (67N)
Negative Sequence Polarization
Operation of Sensitive Earth Fault Element (67N/67W)
Restricted Earth Fault (REF) Protection (64)
High Impedance Restricted Earth Fault Protection
Residual Overvoltage/Neutral Voltage Displacement Protection (59N) 28
Negative Sequence Overvoltage Protection (47)
Frequency Protection (81U/81O)
Thermal Overload Protection (49)
Circuit Breaker Fail Protection (50BF)
Current Loop Inputs and Outputs
P341/EN OP/G74 Page (OP) 5-3
(OP) 5 Operation
Dynamic Line Rating (DLR) Protection (49DLR)
CIGRE/IEEE Heat Balance Equation
2 Operation of Non-Protection Functions
Voltage and Phase Angle Correction
Loss of All Three-Phase Voltages Under Load Conditions
Absence of Three-Phase Voltages Upon Line Energization
Circuit Breaker State Monitoring
Circuit Breaker State Monitoring Features
Circuit Breaker (CB) Condition Monitoring
Circuit Breaker (CB) Condition Monitoring Features
Auto Reset of Trip LED Indication
Reset of Programmable LEDs and Output Contacts
Real Time Clock Synchronization Via Opto-Inputs
Page (OP) 5-4
Contents
54
P341/EN OP/G74
Figures (OP) 5 Operation
FIGURES
Page (OP) 5-
Figure 1 - Rate of change of frequency logic diagram for df/dt>1
Figure 2 - Rate of change of frequency logic diagram for df/dt>2, 3, 4
Figure 3 - Voltage vector shift logic diagram
Figure 4 - Reconnect delay logic diagram
Figure 5 - Power logic diagram
Figure 6 - Sensitive power logic diagram
Figure 7 - Non-directional overcurrent logic diagram
Figure 8 - Directional overcurrent logic
Figure 9 - Negative sequence overcurrent non-directional operation
Figure 10 - Directionalizing the negative phase sequence overcurrent element 18
Figure 11 - Non-directional EF logic (single stage)
Figure 12 - IDG characteristic
Figure 13 - Directional EF with neutral voltage polarization (single state)
Figure 14 - Directional EF with negative sequence polarization (single stage)
Figure 15 - Directional SEF with VN polarization (single stage)
Figure 16 - Resistive components of spill current
Figure 17 - Operating characteristic for Icos
Figure 18 - Restricted earth fault logic diagram
Figure 19 - Principle of high impedance differential protection
Figure 20 - Relay connections for high impedance REF protection
Figure 21 - Alternative relay connections for residual overvoltage/NVD protection 28
Figure 22 - Residual overvoltage logic (single stage) 29
Figure 23 - Undervoltage - single and three phase tripping mode (single stage) 30
Figure 24 - Overvoltage - single and three phase tripping mode (single stage) 31
Figure 25 - Negative sequence overvoltage element logic
Figure 26 - Underfrequency logic (single stage)
Figure 27 - Overfrequency logic (single stage)
Figure 28 - Thermal overload protection logic diagram
Figure 30 - Relationship between the transducer measuring quantity and the current input range 39
Figure 31 - Current loop input logic diagram 40
Figure 32 - Relationship between the current output and the relay measurement 41
Figure 33 - Dynamic line rating protection outputs for 6 stages 52
Figure 34 - Dynamic line rating protection inputs
Figure 35 - Synchro check and synchro split functionality
P341/EN OP/G74 Page (OP) 5-5
(OP) 5 Operation
Figure 36 - System checks functional logic diagram
Figure 38 - CT supervision diagram
Figure 39 - CB state monitoring
Figure 41 - Remote control of circuit breaker
Figure 42 - CB control hotkey menu
Figure 43 - Trip LED logic diagram
TABLES
Table 4 - Directional overcurrent, operate and polarizing signals
Table 5 - CB fail timer reset mechanisms
Table 7 - Current loop output parameters
Table 8 - Viscosity, density, and thermal conductivity of air
Table 13 - CB condition monitoring settings
Table 14 - CB control settings
Table 15 - Setting group selection logic
Table 17 - Control input configuration
Table 18 - Control input labels
Table 20 - Event filtering of time sync signal
Page (OP) 5-
Tables
Page (OP) 5-6 P341/EN OP/G74
Operation of Individual Protection Functions
1
(OP) 5 Operation
OPERATION OF INDIVIDUAL PROTECTION FUNCTIONS
These sections detail the individual protection functions.
A facility is provided in the P341 to maintain correct operation of all the protection functions even when the generator is running in a reverse phase sequence. This is achieved through user configurable settings available for the four setting groups.
The Phase Sequence – Standard ABC/Reverse ACB setting applies to a power system that has a permanent phase sequence of either ABC or ACB. It is also applicable for temporary phase reversal which affects all the VTs and CTs. As distinct from the other phase reversal settings, this setting does not perform any internal phase swapping of the analogue channels.
The Phase Sequence setting affects the sequence component calculations as follows:
The calculations of positive (I1, V1) and negative (I2, V2) phase sequence voltage and current remain unchanged as follows :
Standard ABC
The calculations of positive (I1, V1) and negative (I2, V2) phase sequence voltage and current are given by the equations :
Reverse ACB
Where
The Phase Sequence setting also affects the directional overcurrent protection as per
Phase rotation
Standard ABC
Reverse ACB
67 (Directional overcurrent)
Phase A use Ia, Vbc
Phase B use Ib, Vca
Phase C use Ic, Vab
Phase A use Ia, -Vbc
Phase B use Ib, -Vca
Phase C use Ic, -Vab
Table 1 - Functional overview
The VT Reversal , CT1 Reversal and CT2 Reversal – No Swap/ A-B Swapped/ B-C
Swapped/ C-A Swapped settings apply to applications where some or all of the voltage or current inputs are temporarily reversed, as in pump storage applications. The settings affect the order of the analogue channels in the relay and are set to emulate the order of the channels on the power system. So, assuming the settings emulate the change in phase configuration on the power system all the protection functions will naturally operate as per a standard phase rotation system. The phase sequence calculations and the protection functions all remain unchanged.
P341/EN OP/G74 Page (OP) 5-7
(OP) 5 Operation
1.2
1.2.1
1.2.2
Operation of Individual Protection Functions
Rate of Change of Frequency Protection (81R)
The df/dt function can be used to isolate an embedded generator connected to the utility’s supply system under ‘loss of mains’ condition or for load shedding applications. An increase or decrease of the system frequency (df/ft) will be directly related to a sudden change of load on the generator. 4 stages of df/dt protection are included in P34x. The first stage, df/dt>1 is designed for loss of grid applications but can also be used for load shedding. For the first stage only, the user can select a deadband around the nominal frequency, within which this element is blocked. The dead band is defined with high and low frequency settings df/dt>1 f Low and df/dt> f High . The deadband is eliminated if the high and low frequencies are set the same or the df/dt> f L/H setting is set to
Disabled . The deadband provides additional stability for non loss of grid disturbances which do not affect the machine frequency significantly. Each stage has a direction setting df/dt>n Dir’n – Negative , Positive , Both . This setting determines whether the element will react to rising or falling frequency conditions respectively, with an incorrect setting being indicated if the threshold is set to zero. For loss of mains applications the df/dt>1 Dir’n should be set to Both to match the previous P341 algorithm.
There are some global df/dt settings that affect all protection stages that can be used to smooth out the frequency measurements and provide stable operation of the protection, df/dt avg cycles and df/dt iterations . These settings enable the user to select the number of cycles the frequency is averaged over and the number of iterations of the averaged cycles before a start is given. Two Operating Mode settings are provided:
Fixed Window and Rolling Window which are described below in detail. The Fixed
Window setting is provided for compatibility with the previous P341 df/dt function which used two consecutive calculations of a 3 cycle fixed window to initiate a start.
The previous software version P341 df/dt element calculated the rate of change of frequency every 3 cycles by calculating the frequency difference over the 3-cycle period as shown below. df/ dt = fn - fn-3cycle
3cycle
Two consecutive calculations must give a result above the setting threshold before a trip decision can be initiated.
The df/dt feature is available only when the df/dt option is enabled in the
CONFIGURATION menu. All the stages may be enabled/disabled by the df/dt>n Status cell depending on which element is selected.
Fixed Window
The df/dt calculation is based upon a user definable fixed window, 2 to 12 cycles. A new value of df/dt is (re)calculated every window. Increasing the window size improves measurement accuracy but has the disadvantage of increasing the measurement calculation time.
The elapsed time between start and end frequency measurements is calculated by summing up all sample interval times (NSamp) within the df/dt window (2 to 12 cycles).
Fault detection delay time (cycles) = df/dt Iterations x df/dt Avg Cycles.
Rolling Window
The df/dt calculation is based upon a user definable rolling window, 2 to 12 cycles. The window is a rolling buffer, so a new value of df/dt is (re)calculated every protection cycle execution. Increasing the window size improves measurement accuracy but has the disadvantage of increasing the measurement calculation time.
Page (OP) 5-8 P341/EN OP/G74
Operation of Individual Protection Functions
1.2.3
(OP) 5 Operation
To help improve the accuracy of the df/dt measurement, the value of df/dt calculated is averaged; the length of the averaging buffer is the window size.
The elapsed time between start and end frequency measurements is calculated by summing up all sample interval times (NSamp) within the df/dt window (2 to 12 cycles).
P341 fault detection delay time (cycles) = df/dt Avg Cycles + (df/dt Iterations-1) x 1/4).
Protection scheduler runs every 1/2 cycle.
Logic Diagram
DDB signals are available to indicate starting and tripping of the df/dt element (Start: DDB
1184 -1187 Trip: DDB 928 - 931). The state of the DDB signals can be programmed to be viewed in the Monitor Bit x cells of the COMMISSION TESTS column in the relay.
The df/dt start is mapped internally to the ANY START DDB signal – DDB 992.
The logic diagrams for the df/dt logic are as shown in Figure 1 and Figure 2.
Figure 1 - Rate of change of frequency logic diagram for df/dt>1
Figure 2 - Rate of change of frequency logic diagram for df/dt>2, 3, 4
1.3 Voltage
Δ
V
θ
)
The P341 has a single stage Voltage Vector Shift protection element. This element measures the change in voltage angle over successive power system half-cycles. The element operates by measuring the time between zero crossings on the voltage waveforms. A measurement is taken every half cycle for each phase voltage. Over a power system cycle this produces 6 results, a trip is issued if 5 of the 6 calculations for the last power system cycle are above the set threshold. Checking all three phases makes the element less susceptible to incorrect operation due to harmonic distortion or interference in the measured voltage waveform.
A DDB (Digital Data Bus) signal is available to indicate that the element has operated
(DDB 933 V Shift Trip). The state of the DDB signal can also be programmed to be viewed in the Monitor Bit x cells of the COMMISSION TESTS column in the relay.
P341/EN OP/G74 Page (OP) 5-9
(OP) 5 Operation Operation of Individual Protection Functions
Figure 3 - Voltage vector shift logic diagram
Disconnection of an embedded generator could lead to a simple loss of revenue. Or in cases where the licensing arrangement demands export of power at times of peak load may lead to penalty charges being imposed. To minimize the disruption caused, the
P341 includes a reconnection timer. This timer is initiated following operation of any protection element that could operate due to a loss of mains event, i.e. df/dt, voltage vector shift, under/over frequency, power and under/over voltage. The timer is blocked should a short circuit fault protection element operate, i.e. residual overvoltage, overcurrent, and earth fault. Once the timer delay has expired the element will provide a pulsed output signal. This signal can be used to initiate external synchronizing equipment that can re-synchronies the machine with the system and reclose the CB.
A DDB (Digital Data Bus) signal is available to indicate that the element has operated
(DDB 1299 Reconnection). The state of the DDB signal can also be programmed to be viewed in the Monitor Bit x cells of the COMMISSION TESTS column in the relay.
Page (OP) 5-10
Figure 4 - Reconnect delay logic diagram
P341/EN OP/G74
Operation of Individual Protection Functions
1.5
(OP) 5 Operation
Reverse Power/Over Power/Low Forward Power (32R/32O/32L)
The standard power protection elements of the P34x relay calculate the three-phase active power based on the following formula, using the current measured at the Ia, Ib, Ic inputs on the relay.
P = Vala cos a + Vblb cos b + Vclc cos c
Two stages of power protection are provided, these can be independently selected as either reverse power, over power, low forward power or disabled, and operation in each mode is described in the following sections. The power elements may be selectively disabled, via fixed logic, so that they can be inhibited when the protected machines CB is open, this will prevent mal-operation and nuisance flagging of any stage selected to operate as low forward power.
The P341 relay is connected with the convention that the forward current is the current flowing from the generator to the busbar. This corresponds to positive values of the active power flowing in the forward direction. When a generator is operating in the motoring mode, the machine is consuming active power from the power system.
The motoring active power therefore flows in the reverse direction. The Operating Mode setting for the power protection allows the user to set the operating mode to either
Generating or Motoring . If the mode is set to Motoring , the polarity of the calculated active power is inverted. The operating mode setting can be useful in applications involving pumped storage generators.
The two stages of power protection in the P34x relay are provided with a timer hold (drop off timer) facility, which may either be set to zero or to a definite time value. Setting of the timer to zero means that the power timer for that stage will reset instantaneously once the current falls below 95% of the power setting. Setting of the hold timer to a value other than zero, delays the resetting of the protection element timers for this period. For an intermittent fault when the reset time (drop-off time) of the power protection is instantaneous, the relay will be repeatedly reset and not be able to trip until the fault becomes permanent. By using the Timer Hold facility the relay will integrate the fault power pulses, thereby reducing fault clearance times. The timer hold (drop off timer) facility can be found for the two power stages as settings Power 1 DO Timer and Power
2 DO Timer respectively
DDB signals are available to indicate starting and tripping of each stage (Starts: DDB
1140, DDB 1141, Trips: DDB 882, 883). The state of the DDB signals can be programmed to be viewed in the Monitor Bit x cells of the COMMISSION TESTS column in the relay.
The power starts are mapped internally to the ANY START DDB signal – DDB 992.
P341/EN OP/G74
Figure 5 - Power logic diagram
Page (OP) 5-11
(OP) 5 Operation
1.5.1
Operation of Individual Protection Functions
Sensitive Power Protection Function
For steam turbine generators and some hydro generators a reverse power setting as low as 0.5%Pn is required. A sensitive setting for low forward power protection may also be required, especially for steam turbine generators that which have relatively low over speed design limits.
To improve the power protection accuracy, a dedicated CT input can be used connected to a metering class CT. The CT input is the same as that of the sensitive earth fault and restricted earth fault protection elements, so the user can only select either sensitive power or SEF/REF in the Configuration menu, but not both.
The sensitive power protection measures only A-phase active power, as the abnormal power condition is a three-phase phenomenon. Having a separate CT input also means that a correctly loaded metering class CT can be used which can provide the required angular accuracy for the sensitive power protection function. A compensation angle setting C is also be provided to compensate for the angle error introduced by the system
CT and VT.
The A-phase power is calculated based on the following formula:
PA = IA VA cos ( - C)
Where is the angle of IA with respect to VA and C is the compensation angle setting.
Therefore, rated single-phase power, Pn, for a 1 A rated CT and 110 V rated VT is
Pn = In x Vn = 1 x 110/ 3 = 63.5 W
The minimum setting is 0.3 W = 0.47% Pn
Two stages of sensitive power protection are provided, these can be independently selected as either reverse power, over power, low forward power or disabled, and operation in each mode is described in the following sections.
The power elements may be selectively disabled, via fixed logic, so that they can be inhibited when the protected machine’s CB is open, this will prevent mal-operation and nuisance flagging of any stage selected to operate as low forward power.
The P34x relay is connected with the convention that the forward current is the current flowing from the generator to the busbar. This corresponds to positive values of the active power flowing in the forward direction. When a generator is operating in the motoring mode, the machine is consuming active power from the power system. The motoring active power therefore flows in the reverse direction. The Operating Mode setting for the sensitive power protection allows the user to set the operating mode to either Generating or Motoring . If the mode is set to Motoring , the polarity of the calculated active power is inverted. The operating mode setting can be useful in applications involving pumped storage generators.
The two stages of sensitive power protection in the P34x relay are provided with a timer hold (drop off timer) facility, which may either be set to zero or to a definite time value.
Setting of the timer to zero means that the power timer for that stage will reset instantaneously once the current falls below 90% of the power setting. Setting of the hold timer to a value other than zero, delays the resetting of the protection element timers for this period. For an intermittent fault when the reset time (drop-off time) of the sensitive power protection is instantaneous, the relay will be repeatedly reset and not be able to trip until the fault becomes permanent. By using the Timer Hold facility the relay will integrate the fault power pulses, thereby reducing fault clearance times.
The timer hold (drop off timer) facility can be found for the two sensitive power stages as settings Power 1 DO Timer and Power 2 DO Timer respectively.
Measurement displays of A Phase sensitive active power, reactive power and power factor angle APh Sen Watts , Aph Sen Vars and APh Power Angle are provided in the
MEASUREMENTS 3 menu to aid testing and commissioning.
Page (OP) 5-12 P341/EN OP/G74
Operation of Individual Protection Functions (OP) 5 Operation
DDB signals are available to indicate starting and tripping of each stage (Starts: DDB
1142 , DDB 1143, Trips: DDB 884, 885). The state of the DDB signals can be programmed to be viewed in the Monitor Bit x cells of the COMMISSION TESTS column in the relay.
The sensitive power starts are mapped internally to the ANY START DDB signal – DDB
992 .
1.6
P341/EN OP/G74
Figure 6 - Sensitive power logic diagram
Overcurrent Protection (50/51)
The overcurrent protection included in the P341 relays provides four-stage nondirectional/ directional three-phase overcurrent protection with independent time delay characteristics. All overcurrent and directional settings apply to all three phases but are independent for each of the four stages.
The first two stages of overcurrent protection have time-delayed characteristics which are selectable between Inverse Definite Minimum Time (IDMT), or Definite Time (DT). The third and fourth stages have definite time characteristics only.
Various methods are available to achieve correct relay co-ordination on a system; by means of time alone, current alone or a combination of both time and current. Grading by means of current is only possible where there is an appreciable difference in fault level between the two relay locations. Grading by time is used by some utilities but can often lead to excessive fault clearance times at or near source substations where the fault level is highest. For these reasons the most commonly applied characteristic in coordinating overcurrent relays is the IDMT type.
The inverse time delayed characteristics indicated above, comply with the following formula: t = T x
(M
- 1)
+ L
or t = TD x time
= Constant
M = I/Is
K = Constant
I = Measured
Is = Current threshold setting
= Constant
L
T
=
=
TD =
ANSI/IEEE constant (zero for IEC curves)
Time multiplier setting for IEC curves
Time dial setting for IEEE curves
(M
- 1)
+ L
where:
Page (OP) 5-13
(OP) 5 Operation Operation of Individual Protection Functions
Curve description Standard constant constant L constant
Standard IEC 0.14 0.02 0
Very Inverse
Extremely Inverse
IEC
IEC
13.5
80
1
2
0
0
UK 120 1 0 Long Time Inverse
Rectifier
Moderately Inverse
Very Inverse
Extremely Inverse
IEEE 19.61 2
IEEE 28.2 2
0.491
0.1217
Short Time Inverse
Table 2 - Inverse time curves
US 0.16758 0.02 0.11858
The IEEE and US curves are set differently to the IEC/UK curves, with regard to the time setting. A time multiplier setting (TMS) is used to adjust the operating time of the IEC curves, whereas a time dial setting is employed for the IEEE/US curves. The menu is arranged such that if an IEC/UK curve is selected, the I> Time Dial cell is not visible and vice versa for the TMS setting.
The IEC/UK inverse characteristics can be used with a definite time reset characteristic, however, the IEEE/US curves may have an inverse or definite time reset characteristic.
The following equation can used to calculate the inverse reset time for IEEE/US curves:
TD x S tRESET =
(1 - M2)
in seconds where:
TD = Time dial setting for IEEE curves
S = Constant
M = I/Is
Curve description
Moderately Inverse
Very Inverse
Extremely Inverse
IEEE
IEEE
IEEE
Standard
4.85
21.6
29.1
S constant
Inverse US 5.95
Short Time Inverse US 2.261
Table 3 - Reset curves
1.6.1 RI Curve
The RI curve (electromechanical) has been included in the first and second stage characteristic setting options for phase overcurrent and both earth fault 1 and earth fault 2 protections. The curve is represented by the following equation. t = K x
1
0.339 -
( 0.236/
M
)
in seconds
With K adjustable from 0.1 to 10 in steps of 0.05
Page (OP) 5-14 P341/EN OP/G74
Operation of Individual Protection Functions
1.6.2
(OP) 5 Operation
Timer Hold Facility
The first two stages of overcurrent protection in the P34x relays are provided with a timer hold facility, which may either be set to zero or to a definite time value. Setting of the timer to zero means that the overcurrent timer for that stage will reset instantaneously once the current falls below 95% of the current setting. Setting of the hold timer to a value other than zero, delays the resetting of the protection element timers for this period.
When the reset time of the overcurrent relay is instantaneous, the relay will be repeatedly reset and not be able to trip until the fault becomes permanent. By using the Timer Hold facility the relay will integrate the fault current pulses, thereby reducing fault clearance time.
The timer hold facility can be found for the first and second overcurrent stages as settings
I>1 tRESET and I>2 tRESET , respectively. If an IEC inverse or DT operating characteristic is chosen, this time delay is set via the I>1/2 tRESET setting. If an
IEEE/US operate curve is selected, the reset characteristic may be set to either definite time or inverse time as selected in cell I>1/2 Reset Char . If definite time ( DT ) is selected the I>1/2 tRESET cell may be used to set the time delay. If inverse time reset ( Inverse ) is selected the reset time will follow the inverse time operating characteristic, modified by the time dial setting, selected for I>1/2 Function .
The functional logic diagram for non-directional overcurrent is shown below.
A timer block input is available for each stage which will reset the overcurrent timers of all three phases if energized, taking account of the reset time delay if selected for the I>1 and I>2 stages (DDB 576-579). DDB signals are also available to indicate the start and trip of each phase of each stage of protection, (Starts: DDB 1040-1055, Trips: DDB 800-
815). The state of the DDB signals can be programmed to be viewed in the Monitor Bit x cells of the COMMISSION TESTS column in the relay.
Overcurrent protection starts 1/2/3/4 are mapped internally to the ANY START DDB signal – DDB 992.
P341/EN OP/G74
Figure 7 - Non-directional overcurrent logic diagram
Page (OP) 5-15
(OP) 5 Operation Operation of Individual Protection Functions
The phase fault elements of the P34x relays are internally polarized by the quadrature phase-phase voltages, as shown in the table below:
Phase of protection
A Phase
B Phase
C Phase
IA
IB
IC
Operate current
VBC
VCA
VAB
Polarizing voltage
Table 4 - Directional overcurrent, operate and polarizing signals
Under system fault conditions, the fault current vector will lag its nominal phase voltage by an angle dependent upon the system X/R ratio. It is therefore a requirement that the relay operates with maximum sensitivity for currents lying in this region. This is achieved by means of the relay characteristic angle (RCA) setting; this defines the angle by which the current applied to the relay must be displaced from the voltage applied to the relay to obtain maximum relay sensitivity. This is set in cell I>Char Angle in the overcurrent menu. On the P34x relays, it is possible to set characteristic angles anywhere in the range –95° to +95°.
The functional logic block diagram for directional overcurrent is shown below.
The overcurrent level detector detects that the current magnitude is above the threshold and together with the respective polarizing voltage, a directional check is performed based on the following criteria:
Directional forward
-90° < (angle(I) - angle(V) - RCA) < 90°
Directional reverse
-90° > (angle(I) - angle(V) - RCA) > 90°
Page (OP) 5-16
Figure 8 - Directional overcurrent logic
Any of the four overcurrent stages may be configured to be directional noting that IDMT characteristics are only selectable on the first two stages. When the element is selected as directional, a VTS Block option is available. When the relevant bit is set to 1,
P341/EN OP/G74
Operation of Individual Protection Functions
1.7.1
1.8
(OP) 5 Operation operation of the Voltage Transformer Supervision (VTS), will block the stage if directionalized. When set to 0, the stage will revert to non-directional upon operation of the VTS.
Synchronous Polarization
For a close up three-phase fault, all three voltages will collapse to zero and no healthy phase voltages will be present. For this reason, the P341 relays include a synchronous polarization feature that stores the pre-fault voltage information and continues to apply it to the directional overcurrent elements for a time period of 3.2 seconds. This ensures that either instantaneous or time delayed directional overcurrent elements will be allowed to operate, even with a three-phase voltage collapse.
Negative Phase Sequence (NPS) Overcurrent Protection (46)
The P341 relays provide four independent stages of negative phase sequence overcurrent protection. Each stage has a current pick up setting I2>n Current Set , and is time delayed in operation by the adjustable timer I2>n Time Delay . The user may choose to directionalize operation of the elements, for either forward or reverse fault protection for which a suitable relay characteristic angle may be set. Alternatively, the elements may be set as non-directional. For the negative phase sequence directional elements to operate, the relay must detect a polarizing voltage above a minimum threshold, I2> V2pol Set .
When the element is selected as directional, a VTS Block option is available. When the relevant bit set to 1, operation of the Voltage Transformer Supervision (VTS), will block the stage if directionalized. When set to 0, the stage will revert to non-directional upon operation of the VTS.
The negative phase sequence overcurrent element has a current pick up setting I2>x
Current Set , and is time delayed in operation by an adjustable timer I2>x Time Delay .
The user may choose to directionalize operation of the element, for either forward or reverse fault protection for which a suitable relay characteristic angle may be set.
Alternatively, the element may be set as non-directional.
A timer block input is available for each stage which will reset the NPS overcurrent timers of the relevant stage if energized, (DDB 583-586). All 4 stages can be blocked by energizing the inhibit DDB signal via the PSL (I2> Inhibit: DDB 582). DDB signals are also available to indicate the start and trip of each stage of protection, (Starts: DDB 1064-
1067, Trips: DDB 824-827). The state of the DDB signals can be programmed to be viewed in the Monitor Bit x cells of the COMMISSION TESTS column in the relay.
Negative sequence overcurrent protection starts 1/2/3/4 are mapped internally to the ANY
START DDB signal – DDB 992.
The non-directional and directional operation is shown in the following diagrams:
P341/EN OP/G74
Figure 9 - Negative sequence overcurrent non-directional operation
Page (OP) 5-17
(OP) 5 Operation Operation of Individual Protection Functions
Figure 10 - Directionalizing the negative phase sequence overcurrent element
Directionality is achieved by comparison of the angle between the negative phase sequence voltage and the negative phase sequence current and the element may be selected to operate in either the forward or reverse direction. A suitable relay characteristic angle setting (I2> Char Angle) is chosen to provide optimum performance.
This setting should be set equal to the phase angle of the negative sequence current with respect to the inverted negative sequence voltage (–V2), in order to be at the center of the directional characteristic.
For the negative phase sequence directional elements to operate, the relay must detect a polarizing voltage above a minimum threshold, I2> V2pol Set . This must be set in excess of any steady state negative phase sequence voltage. This may be determined during the commissioning stage by viewing the negative phase sequence measurements in the relay.
Page (OP) 5-18 P341/EN OP/G74
Operation of Individual Protection Functions
1.9
1.9.1
(OP) 5 Operation
Earth Fault Protection (50N/51N)
The P341 relay has a total of four input current transformers; one for each of the phase current inputs and one for supplying the sensitive earth fault protection element.
Residual, or earth fault, current can be derived from the sum of the phase current inputs.
With this flexible input arrangement, various combinations of standard, Sensitive Earth
Fault (SEF) and Restricted Earth Fault (REF) protection may be configured within the relay.
To achieve the sensitive setting range that is available in the P341 relay for SEF protection, the input CT is designed specifically to operate at low current magnitudes.
This common input is used to drive either the SEF or REF protection which are enabled / disabled accordingly within the relay menu.
Standard Earth Fault Protection Element
The four stage Standard Earth Fault protection operates from earth fault current which is derived internally from the summation of the three phase currents.
The first and second stages have selectable IDMT or DT characteristics, whilst the third and fourth stages are DT only. Each stage is selectable to be either non-directional, directional forward or directional reverse. The Timer Hold facility, previously described for the overcurrent elements, is available on each of the first two stages.
The logic diagram for non-directional earth fault overcurrent is shown in Figure 11.
1.9.2
P341/EN OP/G74
Figure 11 - Non-directional EF logic (single stage)
Each stage can be blocked by energizing the relevant DDB signal via the PSL (DDB 544,
DDB 545, DDB 546, DDB 547). This allows the earth fault protection to be integrated into busbar protection schemes, see the Application Notes chapter, or can be used to improve grading with downstream devices. DDB signals are also available to indicate the start and trip of each phase of each stage of protection, (Starts: DDB 1008-1011, Trips: DDB 768-
771). The state of the DDB signals can be programmed to be viewed in the Monitor Bit x cells of the COMMISSION TESTS column in the relay.
IDG Curve
The IDG curve is commonly used for time delayed earth fault protection in the Swedish market. This curve is available in stages 1 and 2 of Earth Fault protection.
The IDG curve is represented by the following equation: t = 5.8 - 1.35 loge
Where
Page (OP) 5-19
(OP) 5 Operation
1.9.3
Operation of Individual Protection Functions
IN>Setting = An adjustable setting which defines the start point of the
characteristic
Although the start point of the characteristic is defined by the IN> setting, the actual relay current threshold is a different setting called IDG Is . The IDG Is setting is set as a multiple of IN>.
An additional setting IDG Time is also used to set the minimum operating time at high levels of fault current.
Figure 12 shows how the IDG characteristic is implemented.
5
4
3
2
10
9
8
7
6
1
0
1
IDG Is Setting Range
10
I/IN>
IDG Time Setting Range
100
P2242ENa
Figure 12 - IDG characteristic
Sensitive Earth Fault (SEF) Protection Element
If a system is earthed through high impedance, or is subject to high ground fault resistance, the earth fault level will be severely limited. Consequently, the applied earth fault protection requires both an appropriate characteristic and a sensitive setting range in order to be effective. A separate 4 stage Sensitive Earth Fault element is provided within the P341 relay for this purpose, this has a dedicated CT input.
Each stage can be blocked by energizing the relevant DDB signal via the PSL (DDB 548,
DDB 549, DDB 550, DDB 551). This allows the earth fault protection to be integrated into
busbar protection schemes, as shown in section 0, or can be used to improve grading
with downstream devices. DDB signals are also available to indicate the start and trip of each phase of each stage of protection, (Starts: DDB 1012-1015, Trips: DDB 773-776).
The state of the DDB signals can be programmed to be viewed in the Monitor Bit x cells of the COMMISSION TESTS column in the relay.
Page (OP) 5-20 P341/EN OP/G74
Operation of Individual Protection Functions
1.10
1.10.1
(OP) 5 Operation
Directional Earth Fault (DEF) Protection (67N)
Each of the four stages of standard earth fault protection and SEF protection may be set to be directional if required. Consequently, as with the application of directional overcurrent protection, a voltage supply is required by the relay to provide the necessary polarization.
With the standard earth fault protection element in the P341 relay, two options are available for polarization; Residual Voltage or Negative Sequence.
Residual Voltage Polarization
With earth fault protection, the polarizing signal requires to be representative of the earth fault condition. As residual voltage is generated during earth fault conditions, this quantity is commonly used to polarize DEF elements. The P341 relay can internally derive this voltage from the 3 phase voltage input, or can measure the voltage via the neutral displacement or residual overvoltage input. The method of measuring the polarizing signal is set in the IN> Vnpol Input cell. Where the residual voltage is derived from the 3 phase voltages a 5-limb or three single phase VT’s must be used. These types of VT design allow the passage of residual flux and consequently permit the relay to derive the required residual voltage. In addition, the primary star point of the VT must be earthed. A three limb VT has no path for residual flux and is therefore unsuitable to supply the relay.
It is possible that small levels of residual voltage will be present under normal system conditions due to system imbalances, VT inaccuracies, relay tolerances etc. Hence, the
P341 relay includes a user settable threshold, IN>VNpol Set , which must be exceeded in order for the DEF function to be operational. The residual voltage measurement provided in the MEASUREMENTS 1 column of the menu may assist in determining the required threshold setting during the commissioning stage, as this will indicate the level of standing residual voltage present.
Note: Residual voltage is nominally 180º out of phase with residual current.
Consequently, the DEF relays are polarized from the ‘–Vres’ quantity. This
180º phase shift is automatically introduced within the P341 relay.
The logic diagram for directional earth fault overcurrent with neutral voltage polarization is shown below.
P341/EN OP/G74
Figure 13 - Directional EF with neutral voltage polarization (single state)
VT Supervision (VTS) selectively blocks the directional protection or causes it to revert to non-directional operation. When selected to block the directional protection, VTS blocking is applied to the directional checking which effectively blocks the start outputs as well.
Page (OP) 5-21
(OP) 5 Operation
1.10.2
Operation of Individual Protection Functions
Negative Sequence Polarization
In certain applications, the use of residual voltage polarization of DEF may either be not possible to achieve, or problematic. An example of the former case would be where a suitable type of VT was unavailable, for example if only a three limb VT was fitted. An example of the latter case would be an HV/EHV parallel line application where problems with zero sequence mutual coupling may exist.
In either of these situations, the problem may be solved by the use of Negative Phase
Sequence (NPS) quantities for polarization. This method determines the fault direction by comparison of NPS voltage with NPS current. The operate quantity, however, is still residual current. This is available for selection on the derived earth fault element but not on the SEF protection. It requires a voltage and current threshold to be set in cells IN>
V2pol Set & IN> I2pol Set , respectively.
Negative sequence polarizing is not recommended for impedance earthed systems regardless of the type of VT feeding the relay. This is due to the reduced earth fault current limiting the voltage drop across the negative phase sequence source impedance
(V2pol) to negligible levels. If this voltage is less than 0.5 volts the relay will cease to provide DEF protection.
The logic diagram for directional earth fault overcurrent with negative sequence polarization is shown below.
1.10.3
Page (OP) 5-22
Figure 14 - Directional EF with negative sequence polarization (single stage)
The directional criteria with negative sequence polarization is given below:
Directional forward
-90° < (angle (I2) - angle(V2 + 180°) - RCA) < 90°
Directional reverse
-90° > (angle (I2) - angle(V2 + 180°) - RCA) > 90°
Operation of Sensitive Earth Fault Element (67N/67W)
The SEF element is designed to be applied to resistively earthed, insulated and compensated networks and have distinct functions to cater for these different requirements. The logic diagram for sensitive directional earth fault overcurrent with
neutral voltage polarization is shown in Figure 15.
P341/EN OP/G74
Operation of Individual Protection Functions (OP) 5 Operation
P341/EN OP/G74
Figure 15 - Directional SEF with VN polarization (single stage)
The sensitive earth fault protection can be set IN/OUT of service using the appropriate
DDB block signal that can be operated from an opto input or control command. VT
Supervision (VTS) selectively blocks the directional protection or causes it to revert to non-directional operation. When selected to block the directional protection, VTS blocking is applied to the directional checking which effectively blocks the start outputs as well.
The directional check criteria are given below for the standard directional sensitive earth fault element:
Directional forward
-90° < (angle(IN) - angle(VN + 180°) - RCA) < 90°
Directional reverse
-90° > (angle(IN) - angle(VN + 180°) - RCA) > 90°
Three possibilities exist for the type of protection element that may be applied for earth fault detection:
1. A suitably sensitive directional earth fault relay having a relay characteristic angle setting (RCA) of zero degrees, with the possibility of fine adjustment about this threshold.
2. A sensitive directional zero sequence wattmetric relay having similar requirements to 1. above with respect to the required RCA settings.
3. A sensitive directional earth fault relay having Ι cos φ and Ι sin φ characteristics.
All stages of the sensitive earth fault element of the P341 relay are settable down to 0.5% of rated current and would therefore fulfill the requirements of the first method listed above and could therefore be applied successfully. However, many utilities (particularly in central Europe) have standardized on the wattmetric method of earth fault detection, which is described in the following section.
Zero sequence power measurement, as a derivative of Vo and Ι o, offers improved relay security against false operation with any spurious core balance CT output for non earth fault conditions. This is also the case for a sensitive directional earth fault relay having an adjustable Vo polarizing threshold.
Some utilities in Scandinavia prefer to use Icos /Isin for non compensated Peterson Coil or insulated networks.
Page (OP) 5-23
(OP) 5 Operation
1.10.4
Operation of Individual Protection Functions
Wattmetric Characteristic
The previous analysis has shown that a small angular difference exists between the spill current on the healthy and faulted feeders. It can be seen that this angular difference gives rise to active components of current which are in antiphase to one another. This is
Page (OP) 5-24
Figure 16 - Resistive components of spill current
Consequently, the active components of zero sequence power will also lie in similar planes and so a relay capable of detecting active power would be able to make a discriminatory decision. i.e. if the wattmetric component of zero sequence power was detected in the forward direction, then this would be indicative of a fault on that feeder; if power was detected in the reverse direction, then the fault must be present on an adjacent feeder or at the source.
For operation of the directional earth fault element within the P341 relay, all three of the settable thresholds on the relay must be exceeded; namely the current ISEF> , the voltage ISEF>VNpol Set and the power PN> Setting .
As can be seen from the following formula, the power setting within the relay menu is called PN> and is therefore calculated using residual rather than zero sequence quantities. Residual quantities are three times their respective zero sequence values and so the complete formula for operation is as shown below:
Vres x Ires X Cos ( – c) = 9 x Vo x Io x Cos ( – c)
Where:
=
c =
Vres =
Ires =
Vo =
Io =
Angle between the Polarizing Voltage (-Vres) and the Residual Current
Relay Characteristic Angle (RCA) Setting (ISEF> Char Angle)
Residual Voltage
Residual Current
Zero Sequence Voltage
Zero Sequence Current
The action of setting the PN> threshold to zero would effectively disable the wattmetric function and the relay would operate as a basic, sensitive directional earth fault element.
However, if this is required, then the SEF option can be selected from the Sens E/F
Options cell in the menu.
A further point to note is that when a power threshold other than zero is selected, a slight alteration is made to the angular boundaries of the directional characteristic. Rather than being ±90° from the RCA, they are made slightly narrower at ±85°.
The directional check criteria is as follows:
P341/EN OP/G74
Operation of Individual Protection Functions
1.10.5
(OP) 5 Operation
Directional forward
-85° < (angle(IN) - angle(VN + 180°) - RCA) < 85°
Directional reverse
-85° > (angle(IN) - angle(VN + 180°) - RCA) > 85°
Icos
/Isin
Characteristic
In some applications, the residual current on the healthy feeder can lie just inside the operating boundary following a fault condition. The residual current for the faulted feeder lies close to the operating boundary.
Polarizing Voltage
Icos ( 1)
Faulted
Feeder
Forward
Operation
Icos( 2)
1
2
Healthy
Feeder
Reverse
Operation
Reverse
Operation
P1634ENa
Figure 17 - Operating characteristic for Icos
The diagram illustrates the method of discrimination when the real (cos φ ) component is considered, since faults close to the polarizing voltage will have a higher magnitude than those close to the operating boundary. In the diagram, it is assumed that the actual magnitude of current is I in both the faulted and non-faulted feeders.
Active component Icos φ
The criterion for operation is: I (cos φ ) > Isef
Reactive component Isin φ
The criterion for operation is: I (sin φ ) > Isef
Where Isef is the relay stage sensitive earth fault current setting.
If any stage is set non-directional, the element reverts back to normal operation based on current magnitude I with no directional decision. In this case, correct discrimination is achieved by means of an Ι cos φ characteristic as the faulted feeder will have a large active component of residual current, whilst the healthy feeder will have a small value.
For insulated earth applications, it is common to use the Ι sin φ characteristic.
P341/EN OP/G74 Page (OP) 5-25
(OP) 5 Operation
1.10.6
1.10.7
Operation of Individual Protection Functions
Restricted Earth Fault (REF) Protection (64)
The REF protection in the P341 relays may be configured to operate as a high impedance differential. The following sections describe the application of the relay.
Note The high impedance REF element of the relay shares the same CT input as the SEF protection. Hence, only one of these elements may be selected.
A DDB signal is available to indicate the tripping of the REF protection, (DDB 772). The state of the DDB signals can be programmed to be viewed in the Monitor Bit x cells of the COMMISSION TESTS column in the relay.
Restricted Earth
Fault Operation
IREF> Trip
P1988ENa
Figure 18 - Restricted earth fault logic diagram
High Impedance Restricted Earth Fault Protection
The high impedance principle is best explained by considering a differential scheme
where one CT is saturated for an external fault, as shown in Figure 19.
If the relay circuit is considered to be a very high impedance, the secondary current produced by the healthy CT will flow through the saturated CT. If CT magnetizing impedance of the saturated CT is considered to be negligible, the maximum voltage across the relay circuit will be equal to the secondary fault current multiplied by the connected impedance, (R
L3
+ R
L4
+ R
CT2
).
The relay can be made stable for this maximum applied voltage by increasing the overall impedance of the relay circuit, such that the resulting current through the relay is less than its current setting. As the impedance of the relay input alone is relatively low, a series connected external resistor is required. The value of this resistor, RST, is
calculated by the formula shown in Figure 19.
An additional non-linear resistor, Metrosil, may be required to limit the peak secondary circuit voltage during internal fault conditions.
To ensure that the protection will operate quickly during an internal fault the CT’s used to operate the protection must have a kneepoint voltage of at least 4 Vs.
Page (OP) 5-26 P341/EN OP/G74
Operation of Individual Protection Functions (OP) 5 Operation
Figure 19 - Principle of high impedance differential protection
P341/EN OP/G74
Figure 20 - Relay connections for high impedance REF protection
The necessary relay connections for high impedance REF are shown in Figure 20.
Figure 20 shows the high impedance protection uses an external differential connection
between the line CTs and neutral CT. The SEF input is then connected to the differential circuit with a stabilizing resistor in series.
Page (OP) 5-27
(OP) 5 Operation
1.11
Operation of Individual Protection Functions
Residual Overvoltage/Neutral Voltage Displacement Protection (59N)
The neutral voltage displacement protection function of the P341 relay includes two stages of derived (VN>1, VN>2) and two stages of measured (VN>3, VN>4) neutral overvoltage protection with adjustable time delays.
The relay derives the neutral/residual voltage operating quantity from this equation:
Vneutral = Va + Vb + Vc
A dedicated voltage input (VN input) is available in the P341 for this protection function which may be used to measure the residual voltage supplied from either an open delta connected VT or the voltage measured on the secondary side of a distribution
transformer earth connection, as shown in Figure 21. Alternatively, the residual voltage
may be derived internally from the three-phase to neutral voltage measurements. Where derived measurement is used the three-phase to neutral voltage must be supplied from either a 5-limb or three single-phase VTs. These types of VT design allow the passage of residual flux and consequently permit the relay to derive the required residual voltage. In addition, the primary star point of the VT must be earthed. A three limb VT has no path for residual flux and is therefore unsuitable to supply the relay when residual voltage is required to be derived from the phase to neutral voltage measurement.
The residual voltage signal can be used to provide interturn protection for machine windings as well as earth fault protection. The residual voltage signal also provides a polarizing voltage signal for the directional and sensitive directional earth fault protection functions.
Page (OP) 5-28
Figure 21 - Alternative relay connections for residual overvoltage/NVD protection
The functional block diagram of the first stage residual overvoltage is shown below:
P341/EN OP/G74
Operation of Individual Protection Functions (OP) 5 Operation
1.12
P341/EN OP/G74
Figure 22 - Residual overvoltage logic (single stage)
VTS blocking when asserted, effectively blocks the start outputs. Only the derived neutral voltage protection stages (VN>1, VN>2) are blocked by the VT Supervision.
A timer block input is available for each stage which will reset the residual overvoltage timers of the relevant stage if energized, (DDB 592-595). DDB signals are also available to indicate the start and trip of each stage of protection, (Starts: DDB 1088-1099 Trips:
832-835). The state of the DDB signals can be programmed to be viewed in the Monitor
Bit x cells of the COMMISSION TESTS column in the relay.
The residual overvoltage fault protection starts are mapped internally to the ANY START
DDB signal – DDB 992.
The IDMT characteristic available on the first stage is defined by the formula: t = K / (M – 1)
Where:
K = t =
M =
Time Multiplier Setting ( VN>1 TMS
Operating Time in Seconds
)
Measured Residual Voltage/Relay Setting Voltage ( VN>1 Voltage Set )
Undervoltage Protection (27)
Both the under and overvoltage protection functions can be found in the relay menu Volt
Protection . The undervoltage protection included within the P341 relays consists of two independent stages. These are configurable as either phase to phase or phase to neutral measuring within the V<Measur't mode cell.
Note If the undervoltage protection is set for phase-phase operation then the
DDB signals V<1/2 Start/Trip A/AB, V<1/2 Start/Trip B/BC, V<1/2 Start/ Trip
C/CA refer to V<1/2 Start/Trip AB and V<1/2 Start/Trip BC and V<1/2
Start/Trip CA. If set for phase-neutral then the DDB signals V<1/2 Start/Trip
A/AB, V<1/2 Start/Trip B/BC, V<1/2 Start/Trip C/CA refer to V<1/2 Start/Trip
A and V<1/2 Start/Trip B and V<1/2 Start/Trip C.
Stage 1 may be selected as IDMT , DT or Disabled , within the V<1 Function cell. Stage
2 is DT only and is enabled/disabled in the V<2 status cell.
The IDMT characteristic available on the first stage is defined by the formula: t = K / (M - 1)
Where:
K = t =
M =
Time multiplier setting
Operating time in seconds
Measured voltage/relay setting voltage (V< Voltage Set)
Two stages are included to provide both alarm and trip stages, where required.
Alternatively, different time settings may be required depending upon the severity of the voltage dip, i.e. motor loads will be able to withstand a small voltage depression for a longer time than if a major voltage excursion were to occur.
Outputs are available for single or three-phase conditions via the V<Operate Mode cell.
Page (OP) 5-29
(OP) 5 Operation Operation of Individual Protection Functions
A timer block input is available for each stage which will reset the undervoltage timers of the relevant stage if energized, (DDB 601, DDB 602). DDB signals are also available to indicate a three-phase and per phase start and trip, (Starts: DDB 1103-1110, Trips: DDB
847-854). The state of the DDB signals can be programmed to be viewed in the Monitor
Bit x cells of the COMMISSION TESTS column in the relay.
Undervoltage protection starts are mapped internally to the ANY START DDB signal –
DDB 992.
The logic diagram of the undervoltage function is shown in Figure 23.
Figure 23 - Undervoltage - single and three phase tripping mode (single stage)
When the protected feeder is de-energized, or the circuit breaker is opened, an undervoltage condition would be detected. Therefore, the V<Poledead Inh cell is included for each of the two stages to block the undervoltage protection from operating for this condition. If the cell is enabled, the relevant stage will become inhibited by the inbuilt pole dead logic within the relay. This logic produces an output when it detects either an open circuit breaker via auxiliary contacts feeding the relay opto inputs or it detects a combination of both undercurrent and undervoltage on any one phase.
Page (OP) 5-30 P341/EN OP/G74
Operation of Individual Protection Functions
1.13
(OP) 5 Operation
Overvoltage Protection (59)
Both the under and overvoltage protection functions can be found in the relay menu Volt
Protection . The overvoltage protection included within the P341 relays consists of two independent stages. These are configurable as either phase to phase or phase to neutral measuring within the V>Measur't mode cell.
Note If the overvoltage protection is set for phase-phase operation then the DDB signals V>1/2 Start/Trip A/AB, V>1/2 Start/Trip B/BC, V>1/2 Start/Trip C/CA refer to V>1/2 Start/Trip AB and V>1/2 Start/Trip BC and V>1/2 Start/Trip
CA. If set for phase-neutral then the DDB signals V>1/2 Start/Trip A/AB,
V>1/2 Start/Trip B/BC, V>1/2 Start/Trip C/CA refer to V>1/2 Start/Trip A and
V>1/2 Start/Trip B and V>1/2 Start/Trip C.
Stage 1 may be selected as IDMT , DT or Disabled , within the V>1 Function cell. Stage
2 is DT only and is enabled/disabled in the V>2 status cell.
The IDMT characteristic available on the first stage is defined by the formula: t
Where:
K = t
M
=
=
=
K / (M – 1)
Time multiplier setting
Operating time in seconds
Measured voltage / relay setting voltage (V> Voltage Set)
A timer block input is available for each stage which will reset the undervoltage timers of the relevant stage if energized, (DDB 598, DDB 599). DDB signals are also available to indicate a three-phase and per phase start and trip, (Starts: DDB 1094-1101, Trips: DDB
838-875). The state of the DDB signals can be programmed to be viewed in the Monitor
Bit x cells of the COMMISSION TESTS column in the relay.
Overvoltage protection starts are mapped internally to the ANY START DDB signal –
DDB 992.
The logic diagram of the overvoltage function is shown in Figure 24.
P341/EN OP/G74
Figure 24 - Overvoltage - single and three phase tripping mode (single stage)
Page (OP) 5-31
(OP) 5 Operation
1.14
1.15
Operation of Individual Protection Functions
Negative Sequence Overvoltage Protection (47)
The P341 relay includes a negative phase sequence overvoltage element. This element monitors the input voltage rotation and magnitude (normally from a bus connected voltage transformer) and may be interlocked with the machine circuit breaker to prevent the machine from being energized whilst incorrect phase rotation exists.
This single stage is selectable as definite time only and is enabled within the V2>status cell.
The logic diagram for the negative sequence overvoltage protection is shown below:
VTS Block
&
V2>1 Time Delay
(DT)
V2>I Trip
V2> V2>I Setting
V2>1 Start
V2>1 Accelerate
&
Accelerates V2>1 Start and
V2>1 Trip if Set Instantaneous
P1638ENb
Figure 25 - Negative sequence overvoltage element logic
DDB signals are available to indicate a start and a trip, (Start: DDB 1102, Trip: DDB 846).
There is also a signal to accelerate the NPS overvoltage protection start (V2>1
Accelerate: DDB 600) which accelerates the operating time of the function from typically
80 ms to 40 ms when set to instantaneous.
The state of the DDB signals can be programmed to be viewed in the Monitor Bit x cells of the COMMISSION TESTS column in the relay.
The NPS overvoltage protection start is mapped internally to the ANY START DDB signal
– DDB 992.
Frequency Protection (81U/81O)
The P341 relay includes four stages of underfrequency and two stages of overfrequency protection to facilitate load shedding and subsequent restoration. The underfrequency stages may be optionally blocked by a pole dead (CB Open) condition. All the stages may be enabled/disabled in the F<n Status or F>n Status cell depending on which element is selected.
The logic diagram for the underfrequency logic is as shown in Figure 26. Only a single
stage is shown. The other three stages are identical in functionality.
If the frequency is below the setting and not blocked the DT timer is started. Blocking may come from the All_Poledead signal (selectively enabled for each stage) or the underfrequency timer block.
If the frequency cannot be determined (Frequency Not Found, DDB 1295), the function is also blocked.
Page (OP) 5-32 P341/EN OP/G74
Operation of Individual Protection Functions (OP) 5 Operation
Figure 26 - Underfrequency logic (single stage)
The functional logic diagram for the overfrequency function is as shown in Figure 27.
Only a single stage is shown as the other stages are identical in functionality. If the frequency is above the setting and not blocked the DT timer is started and after this has timed out the trip is produced. Blocking may come from the All_Poledead signal
(selectively enabled for each stage) or the overfrequency timer block.
Figure 27 - Overfrequency logic (single stage)
A timer block input is available for each stage which will reset the under and overfrequency timers of the relevant stage if energized, (DDB 626-629, DDB 630-631).
DDB signals are also available to indicate start and trip of each stage, (Starts: DDB 916-
919, DDB 920-921, Trips: DDB 916-919, DDB 920-921).
The state of the DDB signals can be programmed to be viewed in the Monitor Bit x cells of the COMMISSION TESTS column in the relay.
The under and overfrequency protection starts are mapped internally to the ANY START
DDB signal – DDB 992.
P341/EN OP/G74 Page (OP) 5-33
(OP) 5 Operation
1.16
1.16.1
1.16.2
Page (OP) 5-34
Operation of Individual Protection Functions
Thermal Overload Protection (49)
Introduction
The physical and electrical complexity of a generator or motor construction results in a complex thermal relationship. It is not therefore possible to create an accurate mathematical model of the true thermal characteristics of the machine.
However, if a generator/motor is considered to be a homogeneous body, developing heat internally at a constant rate and dissipating heat at a rate directly proportional to its temperature rise, it can be shown that the temperature at any instant is given by:
T = T max
(1-e
-t/
)
Where:
T max
=
= final steady state temperature heating time constant
This assumes a thermal equilibrium in the form:
Heat developed = Heat stored + Heat dissipated
Temperature rise is proportional to the current squared:
R
2
(1-e
-t/
)
T = T max
= K I
R
2 if t =
Where:
I
R
= the continuous current level which would produce a temperature T generator max
in
For an overload current of ‘I’ the temperature is given by:
T = KI
2
(1-e
-t/
)
For a machine not to exceed Tmax, the rated temperature, then the time ‘t’ for which the machine can withstand the current ‘I’ can be shown to be given by:
T max
= KI
R
2 = KI
2
(1-e t = . Loge (1/(1-(I
R
/I)
2
))
-t/
)
An overload protection element should therefore satisfy the above relationship. The value of IR may be the full load current or a percentage of it depending on the design.
As previously stated it is an oversimplification to regard a generator/motor as an homogeneous body. The temperature rise of different parts or even of various points in the same part may be very uneven. However, it is reasonable to consider that the current-time relationship follows an inverse characteristic.
Thermal Replica
The P341 relay models the time-current thermal characteristic of a generator/motor by internally generating a thermal replica of the machine. The thermal overload protection can be selectively enabled or disabled. The positive and negative sequence components of the generator/motor current are measured independently and are combined together to form an equivalent current, I eq
, which is supplied to the replica circuit. The heating effect in the thermal replica is produced by I eq2
and therefore takes into account the heating effect due to both positive and negative sequence components of current.
Unbalanced phase currents will cause additional rotor heating that may not be accounted for by some thermal protection relays based on the measured current only. Unbalanced loading results in the flow of positive and negative sequence current components. Load
P341/EN OP/G74
Operation of Individual Protection Functions (OP) 5 Operation unbalance can arise as a result of single-phase loading, non-linear loads (involving power electronics or arc furnaces, etc.), uncleared or repetitive asymmetric faults, fuse operation, single-pole tripping and reclosing on transmission systems, broken overhead line conductors and asymmetric failures of switching devices. Any negative phase sequence component of stator current will set up a reverse-rotating component of stator flux that passes the rotor at twice synchronous speed. Such a flux component will induce double frequency eddy currents in the rotor, which can cause overheating of the rotor body, main rotor windings, damper windings etc. This extra heating is not accounted for in the thermal limit curves supplied by the generator manufacturer as these curves assume positive sequence currents only that come from a perfectly balanced supply and generator/motor design. The P341 thermal model may be biased to reflect the additional heating that is caused by negative sequence current when the machine is running. This biasing is done by creating an equivalent heating current rather than simply using the phase current. The M factor is a constant that relates negative sequence rotor resistance to positive sequence rotor resistance. If an M factor of 0 is used the unbalance biasing is disabled and the overload curve will time out against the measured generator/motor positive sequence current.
The equivalent current for operation of the overload protection is in accordance with the expression:
I eq
= (I
1
2
+ MI
2
2
)
Where:
I1 =
I2 =
M = machine
Positive sequence current
Negative sequence current
A user settable constant proportional to the thermal capacity of the
As previously described, the temperature of a generator/motor will rise exponentially with increasing current. Similarly, when the current decreases, the temperature also decreases in a similar manner. Therefore to achieve close sustained overload protection, the P341 relay incorporates a wide range of thermal time constants for heating and cooling.
Furthermore, the thermal withstand capability of the generator/motor is affected by heating in the winding prior to the overload. The thermal replica is designed to take account the extremes of zero pre-fault current, known as the ‘cold’ condition and the full rated pre-fault current, known as the ‘hot’ condition. With no pre-fault current the relay will be operating on the ‘cold curve’. When a generator/motor is or has been running at full load prior to an overload the ‘hot curve’ is applicable. Therefore during normal operation the relay will be operating between these two limits.
The following equation is used to calculate the trip time for a given current. Note that the relay will trip at a value corresponding to 100% of its thermal state.
The thermal time characteristic is given by: t = log e
(I eq
2
- I
P
2
)/(I eq
2
- (Thermal I>)
2
Where:
I t
I eq
=
=
=
Thermal I> =
P
=
Time to trip, following application of the overload current, I
Heating time constant of the protected plant
Equivalent current
Relay setting current
Steady state pre-load current before application of the overload
The time to trip varies depending on the load current carried before application of the overload, i.e. whether the overload was applied from 'hot” or “cold”.
The thermal time constant characteristic may be rewritten as: exp(–t/ ) = ( - 1)/( - p
)
P341/EN OP/G74 Page (OP) 5-35
(OP) 5 Operation Operation of Individual Protection Functions t = loge ( - p
) / ( - 1)
Where:
= I and
p = I eq
2
/(Thermal I>)
2 p
2 /(Thermal I>) 2
Where is the thermal state and is p
the pre-fault thermal state.
Note: The thermal model does not compensate for the effects of ambient temperature change. t t = . Loge ((K
2
-A
2
)/(K
2
-1)) alarm
= . Loge ((K
2
-A
2
)/(K
2
-(Thermal Alarm/100))
Where:
K = I eq
A = I
P
/Thermal I> (K2 = Thermal state, )
/Thermal I> (A = Pre-fault thermal state, p
Thermal Alarm = Thermal alarm setting, 20-80%
)
The Thermal state of the machine can be viewed in the Thermal Overload cell in the
MEASUREMENTS 3 column. The thermal state can be reset by selecting Yes in the
Reset ThermalO/L cell in Measurements 3 . Alternatively the thermal state can be reset by energizing DDB 641 Reset Gen Thermal via the relay PSL.
A DDB signal Gen Thermal Trip is also available to indicate tripping of the element (DDB
945). A further DDB signal Gen Thermal Alm is generated from the thermal alarm stage
(DDB 371). The state of the DDB signal can be programmed to be viewed in the
Monitor Bit x cells of the COMMISSION TESTS column in the relay.
Thermal State
> Thermal Alarm
Setting
&
Thermal Alarm
Thermal State
> 100%
&
Thermal Trip
CTS-I Block
P1629ENb
Figure 28 - Thermal overload protection logic diagram
The functional block diagram for the thermal overload protection is shown in Figure 28.
Page (OP) 5-36 P341/EN OP/G74
Operation of Individual Protection Functions
1.17
(OP) 5 Operation
Circuit Breaker Fail Protection (50BF)
The circuit breaker failure protection incorporates two timers, CB Fail 1 Timer and CB
Fail 2 Timer , allowing configuration for the following scenarios:
Simple CBF, where only CB Fail 1 Timer is enabled. For any protection trip, the
CB Fail 1 Timer is started, and normally reset when the circuit breaker opens to isolate the fault. If breaker opening is not detected, CB Fail 1 Timer times out and closes an output contact assigned to breaker fail (using the programmable scheme logic). This contact is used to backtrip upstream switchgear, generally tripping all infeeds connected to the same busbar section.
CBF CB Fail 1 Timer and CB Fail 2 Timer can be configured to operate for trips triggered by protection elements within the relay or via an external protection trip. The latter is achieved by allocating one of the relay opto-isolated inputs to External Trip using the programmable scheme logic.
A re-tripping scheme, plus delayed backtripping. Here, CB Fail 1 Timer is used to route a trip to a second trip circuit of the same circuit breaker. This requires duplicated circuit breaker trip coils, and is known as re-tripping. Should re-tripping fail to open the circuit breaker, a backtrip may be issued following an additional time delay. The backtrip uses CB Fail 2 Timer , which is also started at the instant of the initial protection element trip.
Resetting of the CBF is possible from a breaker open indication (from the relay’s pole dead logic) or from a protection reset. In these cases resetting is only allowed provided the undercurrent elements have also reset. The resetting options are
Initiation (menu selectable)
CB fail timer reset mechanism
Current based protection
(e.g. 50/51/46/21/87..)
Sensitive earth fault element
Non-current based protection
(e.g. 27/59/81/32L..)
External protection
The resetting mechanism is fixed.
[IA< operates] &
[IB< operates] &
[IC< operates] &
[IN< operates]
The resetting mechanism is fixed.
[ISEF< operates]
Three options are available.
The user can select from the following options.
[All I< and IN< elements operate]
[Protection element reset] AND
[All I< and IN< elements operate]
CB open (all 3 poles) AND
[All I< and IN< elements operate]
Three options are available. The user can select any or all of the options.
[All I< and IN< elements operate]
[External trip reset] AND
[All I< and IN< elements operate]
CB open (all 3 poles) AND
[All I< and IN< elements operate]
Table 5 - CB fail timer reset mechanisms
P341/EN OP/G74 Page (OP) 5-37
(OP) 5 Operation Operation of Individual Protection Functions
Figure 29 - CB fail logic
Page (OP) 5-38 P341/EN OP/G74
Operation of Individual Protection Functions
1.18
1.18.1
Current Loop Inputs and Outputs
(OP) 5 Operation
Current Loop Inputs
Four analog (or current loop) inputs are provided for transducers with ranges of 0 - 1 mA,
0 - 10 mA, 0 - 20 mA or 4 - 20 mA. The analog inputs can be used for various transducers such as vibration monitors, tachometers and pressure transducers.
Associated with each input there are two protection stages, one for alarm and one for trip.
Each stage can be individually enabled or disabled and each stage has a definite time delay setting.
The Alarm and Trip stages can be set for operation when the input value falls below the
Alarm/Trip threshold Under or when the input current is above the input value Over . The sample interval is nominally 50 ms per input.
The relationship between the transducer measuring range and the current input range is linear. The maximum and minimum settings correspond to the limits of the current input
range. This relationship is shown in Figure 30.
Figure 30 also shows the relationship between the measured current and the analog to
digital conversion (ADC) count. The hardware design allows for over-ranging, with the maximum ADC count (4095 for a 12-bit ADC) corresponding to 1.0836 mA for the 0 - 1 mA range, and 22.7556 mA for the 0 - 10 mA, 0 - 20 mA and 4 - 20 mA ranges. The relay will therefore continue to measure and display values beyond the Maximum setting, within its numbering capability (-9999 to 9999).
P341/EN OP/G74
Figure 30 - Relationship between the transducer measuring quantity and the current input range
Note If the Maximum is set less than the Minimum, the slopes of the graphs will be negative. This is because the mathematical relationship remains the same irrespective of how Maximum and Minimum are set, e.g., for 0 - 1 mA range, Maximum always corresponds to 1 mA and Minimum corresponds to
0 mA.
Page (OP) 5-39
(OP) 5 Operation Operation of Individual Protection Functions
Power-on diagnostics and continuous self-checking are provided for the hardware associated with the current loop inputs. When a failure is detected, the protection associated with all the current loop inputs is disabled and a single alarm signal (CL Card
I/P Fail, DDB 384) is set and an alarm (CL Card I/P Fail) is raised. A maintenance record with an error code is also recorded with additional details about the type of failure.
For the 4 - 20 mA input range, a current level below 4 mA indicates that there is a fault with the transducer or the wiring. An instantaneous under current alarm element is available, with a setting range from 0 to 4 mA. This element controls alarm output signals
(CLI1/2/3/4 I< Fail Alm., DDB 390-393).
Hysteresis is implemented for each protection element. For Over protection, the dropoff/pick-up ratio is 95%, for Under protection, the ratio is 105%.
A timer block input is available for each current loop input stage which will reset the CLI timers of the relevant stage if energized, (DDB 656-659). If a current loop input is blocked the protection and alarm timer stages and the 4 - 20 mA undercurrent alarm associated with that input are blocked. The blocking signals may be useful for blocking the current loop inputs when the CB is open for example.
DDB signals are available to indicate starting an operation of the alarm and trip stages of the each current loop inputs, (CLI1/2/3/4 Alarm Start: DDB 1232-1235, CLI1/2/3/4 Trip
Start: DDB 1236-1239, CL Input 1/2/3/4 Alarm: DDB 386-389, CLI Input1/2/3/4 Trip: DDB
987-990). The state of the DDB signals can be programmed to be viewed in the Monitor
Bit x cells of the COMMISSION TESTS column in the relay.
The current loop input starts are mapped internally to the ANY START DDB signal – DDB
992.
1.18.2
Page (OP) 5-40
Figure 31 - Current loop input logic diagram
Current Loop Output
Four analog current outputs are provided with ranges of 0 - 1 mA, 0 - 10 mA, 0 - 20 mA or
4 - 20 mA which can alleviate the need for separate transducers. These may be used to feed standard moving coil ammeters for analog indication of certain measured quantities or into a SCADA using an existing analog RTU.
The CLIO output conversion task runs every 50 ms and the refresh interval for the output measurements is nominally 50 ms. The exceptions are marked with an asterisk in the table of current loop output parameters below. Those exceptional measurements are updated once every second.
P341/EN OP/G74
Operation of Individual Protection Functions (OP) 5 Operation
The user can set the measuring range for each analog output. The range limits are defined by the Maximum and Minimum settings.
This allows the user to “zoom in” and monitor a restricted range of the measurements with the desired resolution. For voltage, current and power quantities, these settings can be set in either primary or secondary quantities, depending on the CLO1/2/3/4 Set
Values - Primary/Secondary setting associated with each current loop output.
The output current of each analog output is linearly scaled to its range limits, as defined
by the Maximum and Minimum settings. The relationship is shown in Figure 32.
0 – 1 mA 0 – 10 mA
P341/EN OP/G74
0 – 20 mA 4 – 20 mA
Figure 32 - Relationship between the current output and the relay measurement
Note If the Maximum is set less than the Minimum, the slopes of the graphs will be negative. This is because the mathematical relationship remains the same irrespective of how Maximum and Minimum are set, e.g., for 0 - 1 mA range, Maximum always corresponds to 1 mA and Minimum corresponds to
0 mA.
The P341 transducers are of the current output type. This means that the correct value of output will be maintained over the load range specified. The range of load resistance varies a great deal, depending on the design and the value of output current.
Transducers with a full scale output of 10 mA will normally feed any load up to a value of
1000 (compliance voltage of 10 V). This equates to a cable length of 15 km
(approximately) for lightweight cable (1/0.6 mm cable). A screened cable earthed at one end only is recommended to reduce interference on the output current signal. The table below gives typical cable impedances/km for common cables. The compliance voltage dictates the maximum load that can be fed by a transducer output. Therefore the 20 mA output will be restricted to a maximum load of 500 approximately.
Cable 1/0.6 mm
CSA (mm 2 ) 0.28
R ( /km)
1/0.85 mm
0.57
1/1.38 mm
1.50
65.52 32.65 12.38
Table 6 - Cable resistances
The receiving equipment, whether it be a simple moving-coil (DC milli-ammeter) instrument or a remote terminal unit forming part of a SCADA system, can be connected
Page (OP) 5-41
(OP) 5 Operation Operation of Individual Protection Functions at any point in the output loop and additional equipment can be installed at a later date
(provided the compliance voltage is not exceeded) without any need for adjustment of the transducer output.
Where the output current range is used for control purposes, it is sometimes worthwhile to fit appropriately rated diodes, or Zener diodes, across the terminals of each of the units in the series loop to guard against the possibility of their internal circuitry becoming open circuit. In this way, a faulty unit in the loop does not cause all the indications to disappear because the constant current nature of the transducer output simply raises the voltage and continues to force the correct output signal round the loop.
Power-on diagnostics and continuous self-checking are provided for the hardware associated with the current loop outputs. When failure is detected, all the current loop output functions are disabled and a single alarm signal (CL Card O/P Fail, DDB 385) is set and an alarm (CL Card O/P Fail) is raised. A maintenance record with an error code is also recorded with additional details about the type of failure.
Current loop output parameters are shown in this table:
Current loop output parameter
Abbreviation
Current Magnitude
IA Magnitude
IB Magnitude
IC Magnitude
IN Derived Mag.
Sensitive Current Input
Magnitude
I Sen Magnitude
Phase Sequence Current
Components
I1 Magnitude
I2 Magnitude
I0 Magnitude
RMS Phase Currents
P-P Voltage Magnitude
IA RMS*
IB RMS*
IC RMS*
VAB Magnitude
VBC Magnitude
VCA Magnitude
P-N voltage Magnitude
Neutral Voltage
Magnitude
VAN Magnitude
VBN Magnitude
VCN Magnitude
VN1 Measured Mag.
VN Derived Mag.
Phase Sequence Voltage
Components
V1 Magnitude*
V2 Magnitude
V0 Magnitude
RMS Phase Voltages
VAN RMS*
VBN RMS*
VCN RMS*
Frequency Frequency
A
A
A
A
V
V
V
V
V
Units
Hz
Range
0 to 16 A
0 to 2 A
0 to 16 A
0 to 16 A
0 to 200 V
0 to 200 V
0 to 200 V
0 to 200 V
0 to 200 V
Step
0.01 A
0.01 A
0.01 A
0.01 A
0.1 V
0.1 V
0.1 V
0.1 V
0.1 V
0.01 Hz
Default min.
0 A
0 A
0 A
0 A
0 V
0 V
0 V
0 V
0 V
45 Hz
Default max.
1.2 A
1.2 A
1.2 A
1.2 A
140 V
80 V
80 V
80 V
80 V
65 Hz
3 Ph Active Power
3 Ph Reactive Power
3 Ph Apparent Power
3 Ph Power Factor
Three-Phase Watts*
Three-Phase Vars*
Three-Phase VA*
3Ph Power Factor*
W
Var
VA
-
0 to 70 Hz
-6000 W to
6000 W
-6000 Var to
6000 Var
0 to
6000VA
-1 to 1
1 W
1 Var
1 VA
0.01
0 W
0 Var
0 VA
0
300 W
300 Var
300 VA
1
Page (OP) 5-42 P341/EN OP/G74
Operation of Individual Protection Functions (OP) 5 Operation
Current loop output parameter
Single-Phase Active
Power
Single-Phase Reactive
Power
Single-Phase Apparent
Power
Single-Phase Power
Factor
Three-Phase Current
Demands
3Ph Active Power
Demands
3Ph Reactive Power
Demands
Stator Thermal State
Current Loop Inputs
DLR
Abbreviation
A Phase Watts*
B Phase Watts*
C Phase Watts*
A Phase Vars*
B Phase Vars*
C Phase Vars*
A Phase VA*
B Phase VA*
C Phase VA*
APh Power Factor*
BPh Power Factor*
CPh Power Factor*
IA Fixed Demand*
IB Fixed Demand*
IC Fixed Demand*
IA Roll Demand*
IB Roll Demand*
IC Roll Demand*
IA Peak Demand*
IB Peak Demand*
IC Peak Demand*
3Ph W Fix Demand*
3Ph W Roll Dem*
3Ph W Peak Dem*
3Ph Vars Fix Dem*
3Ph Var Roll Dem*
3Ph Var Peak Dem*
Thermal Overload
CL Input 1
CL Input 2
CL Input 3
CL input 4
DLR Amapacity
Max Iac
Units
W
Var
VA
Range
0 to
2000 VA
Step
-2000 W to
2000 W
1 W
-2000 Var to
2000 Var
1 Var
1 VA
A
W
Var
%
-
A
-1 to 1
0 to 16 A
-6000 W to
6000 W
-6000 Var to
6000 Var
0 to 200
-9999 to
9999
0 to 16 A
0.01
0.01 A
1 W
1 Var
0.01
Default min.
0 W
Default max.
100 W
0 Var
0
300 Var
120
0.1 0 9999
0.01 A
0 Var
0 VA
0
0 A
0 W
0 A
100 Var
100 VA
1
1.2 A
300 W
1.2 A
Check Synch Voltages
Slip Frequency
C/S Voltage Mag
C/S Bus Gen-Mag
Slip frequency
Table 7 - Current loop output parameters
Note 1
Note 2
Note 3
V
Hz
0 to 200 V
0 to 70 Hz
0.01 Hz/s -1 Hz/s
0.1 V
0.01 Hz
0 V
-0.5 Hz
1 Hz/s
80 V
0.5 Hz
For measurements marked with an asterisk, the internal refresh rate is nominally 1 s, others are 0.5 power system cycle or less.
The polarity of Watts, Vars and power factor is affected by the
Measurements Mode setting.
These settings are for nominal 1 A and 100/120 V versions only. For other nominal versions they need to be multiplied accordingly.
P341/EN OP/G74 Page (OP) 5-43
(OP) 5 Operation
1.19
1.19.1
Operation of Individual Protection Functions
Dynamic Line Rating (DLR) Protection (49DLR)
The thermal rating, also referred to as ampacity, of an overhead line is the maximum current that a circuit can carry without exceeding its sag temperature or the annealing onset temperature of the conductor, whichever is lower. The sag temperature is that temperature at which the legislated height of the phase conductor above ground is met.
The present practice in many utilities is to monitor the power flow in overhead lines without knowledge of the actual conductor temperature or the height of the conductor above ground. There are many variables affecting the conductor temperature, such as wind speed and direction, ambient temperature and solar radiation. As these are difficult to predict, conservative assumptions have been made so far in order to always ensure public safety. The main purpose of real time line monitoring is to achieve a better utilization of the load current capacity of overhead lines whilst ensuring that the regulatory clearances above ground are always met. Different real time line monitoring methods have been applied and evaluated as described in various publications. There are fundamentally two different ways to derive ampacity dynamically. One is by direct measurement using sensors to determine the tension, conductor temperature, or sag.
Alternatively, an indirect method can be used, by measuring ambient weather conditions, from which the ampacity can be calculated by solving standard equations in real time which is implemented in the P341.
In the P341 DLR weather stations are employed to derive ampacity for use in the load management and back-up protection systems. Various computational methods have been developed in the past to calculate the heat transfer and ampacities of the conductors. Engineering Recommendation P27 which is based on Price’s experimental work and statistical method has been applied commonly in the UK to calculate fixed line ratings for winter or summer. The ER P27 current ratings are based on the following weather conditions: wind speed 0.5 m/s, ambient temperature winter 2°C, ambient temperature summer 20°C and solar radiation 0 W. The two most commonly used international standards are the CIGRE 207 standard and the IEEE 738 standard for the current-temperature relationship of the line. Both the CIGRE 207 standard and the IEEE
738 algorithms are implemented in the P341 Dynamic Line Rating protection to derive the ampacity from the weather measurements.
In the DLR protection in the P341 relay the ampacity is calculated in real time using the
CIGRE 207 or IEEE 738 equations. When the measured line current reaches a certain percentage of dynamically calculated ampacity one of the 6 protection stages can be operated after a time delay. These stages can be used to provide control commands to the distributed generators to hold or reduce their power output. If the control actions are not successful at reducing the ampacity, possibly due to a communications failure, as a back-up the protection relay can use one of protection stages to trip out the distributed generation after a time delay.
CIGRE/IEEE Heat Balance Equation
The current-temperature relationship of the bare overhead conductors is described below.
The conductor surface temperature is a function of:
4. Conductor material properties
6. Conductor geographical position
7. Conductor electrical current
Based on the above parameters, the temperature of the line conductor can be dynamically calculated using the differential heat-balance equation which is used by
CIGRE 207 and IEEE 738 standards:
Page (OP) 5-44 P341/EN OP/G74
Operation of Individual Protection Functions (OP) 5 Operation
Equation 1
Where: m = Conductor mass density per unit length (kg/m) c = Conductor specific heat capacity (J/kg K)
T c
= Conductor temperature (oC)
P
J
P
M
P
P i
S
= Joule Heating per unit length (W/m)
= Magnetic heating per unit length (W/m)
P
C
P
R
P w
= Solar Heating per unit length (W/m)
= Corona heating per unit length (W/m)
= Convective cooling per unit length (W/m)
= Radiative cooling per unit length (W/m)
= evaporative cooling per unit length (W/m)
P i
and P w
are commonly neglected and for the Lynx conductor for example PM can be neglected because the two layers of Aluminum strand spiral in opposite directions around the steel core, and the magnetic fields largely cancel out. Pi, Pw and PM are not considered in the P341 DLR calculations.
Equation 1 is related to the electrical current and the conductor temperature and it is used
to calculate the conductor’s temperature when the conductor’s electrical current is known and to calculate the current that yields a given maximum allowable conductor temperature, the ampacity.
While calculating the line ampacity, the conductor temperature Tc can be considered as the maximum allowable temperature under steady state conditions, so dTc/dt = 0 as
shown in Equation 2. The line’s rating Iac can then be calculated by re-arranging
Equation 1 to form the heat balance equation and substituting for PJ from Equation 10 for
CIGRE and Equation 18 for IEEE. The IEEE standard uses ac current to calculate Joule
heating, however the CIGRE standard uses dc current which has to be converted to an
ac current as shown in Equation 11.
Equation 2
Equation 3
The steady state heat balance equation (heat gain = heat loss) is given in Equation 4:
Equation 4 PJ + PM +PS +Pi = PC +Pr +Pw
P341/EN OP/G74 Page (OP) 5-45
(OP) 5 Operation
1.19.2
1.19.2.1
Page (OP) 5-46
Operation of Individual Protection Functions
CIGRE 207 Equations
Convective Cooling – P
C
CIGRE considers the convective cooling by natural convective and corrected convection for low wind-speed scenarios and forced convective for high wind-speed scenarios as shown below:
1. Natural convective cooling (Wind-speed < 0.5 m/s)
Equation 5
2. Forced convective cooling (All Wind speeds)
Equation 6
3. Corrected convective cooling (Wind-speed < 0.5 m/s)
Equation 7
Where:
T a
= Ambient temperature (°C)
T f
= Film temperature at surface of conductor = 0.5(T a
+ T c
) (°C)
= conductivity of air (W/m K)
=2.42.10-2+7.2.10-5.Tf g = Gravitational acceleration, constant 9.807 m/s
2
Pr = Prandtl number (unitless)
0.715-2.5.10-
4
.Tf
r = Relative air density (unitless)
r = 4 y), y is the height above the sea level.
δ
V = Wind velocity (m/s)
= Kinematic viscosity (m
2
/s)
=1.32.105 +9.5.108 .Tf
= Effective angle between wind and conductor line (°)
= (wind direction-line direction)
D = Overall conductor diameter (m)
A
1
, A
2
, B
1
, B parameters.
2
, m
1
, m
2
are the values determined by the intermediate calculated
The maximum value of the calculated convective cooling is used in the relay.
A
1
, A
2
, B
1
, B parameters.
2
, m
1
, m
2
are the values determined by the intermediate calculated
A
1
=0.42, B
2
=0.68 and m
1
=1.08 for 0º< δ <24º
A
1
=0.42, B
2
=0.58 and m
1
=0.90 for 24º< δ <90º
A
2
=0.850, m
2
=0.188 for
P341/EN OP/G74
Operation of Individual Protection Functions
1.19.2.2
1.19.2.3
1.19.2.4
(OP) 5 Operation
A
2
=0.480, m
2
=0.250 for
B
1
=0.641, n=0.471 for
B
1
=0.178, n=0.633 for
B1=0.048, n=0.800 for
R f
= Roughness of conductor surface (unitless)
, and d = Outer layer (non-ferrous material for steel reinforced conductors) wire diameter (m)
P
C
= MAX (P
C
_ natr,
P
C_ ,
P
C
_ cor
)
The convective cooling mainly depends on V (wind velocity) and (effective wind angle).
Radiative Cooling – P
R
CIGRE calculates the radiative cooling as below:
Equation 8
Where:
B
= Emissivity (unitless)
= Stefan-Boltzmann constant = 5.670400
10-
8
W/m
2
D = Overall conductor diameter (m)
K
4
The radiative cooling mainly depends on the difference between the T temperature) and T a
4 (ambient temperature). c
4
(conductor
Basic Solar Heating – P
S
The solar heating calculation is simplified and calculated by considering the Global Solar
Radiation as a constant for a long period of time.
Equation 9
Where:
s
= Solar absorptivity (unitless)
S = Global solar radiation (W/m 2 )
D = Overall conductor diameter (m)
The solar heating mainly depends on S (solar radiation) and D (conductor diameter).
Joule Heating – P
J
CIGRE includes the magnetic heating into the Joule heating by considering a coefficient factor for the skin effect.
Equation 10
I
I
Where: dc dc
= DC current of conductor line (A)
is calculated based on the Equation 12, for an example of Lynx conductor.
R dc
T c
= DC conductor resistance at 20°C per unit length ( /m)
= Conductor temperature (°C)
= Temperature coefficient of resistance per degree Kelvin (1/K)
P341/EN OP/G74 Page (OP) 5-47
(OP) 5 Operation Operation of Individual Protection Functions
1.19.2.5
1.19.3
1.19.3.1
Page (OP) 5-48
a
= Temperature coefficient of resistance of non-ferrous material for steel reinforced conductors (1/K)
s
A a s
= Temperature coefficient of resistance of steel for steel reinforced conductors (1/K)
A s a
= Resistivity of non-ferrous material for steel reinforced conductors ( /m)
= Resistivity of steel for steel reinforced conductors ( /m)
= Area of non-ferrous material for steel reinforced conductors (m
= Area of steel for steel reinforced conductors (m
The joule heating mainly depends on I dc
2 )
(DC current) and T c
2
)
(conductor temperature).
CIGRE Ampacity Calculation
This section briefly describes the algorithm for calculating the line ampacity.
From Equation 3 and Equation 10, the line’s rating I
dc
can be calculated as shown in
Equation 11
CIGRE converts the DC current to an AC current based on an empirical formula which takes into account the skin effect and the construction of the conductor. The ampacity I ac for Lynx conductor for example is shown below. Other empirical formulae for other conductor types are stored in the relay.
Equation 12
IEEE 738 Equations
The IEEE equations for dynamic line rating protection are described below.
Convective Cooling – P
C
IEEE considers the convective cooling by natural convection for low wind-speed scenarios and high wind-speed scenarios.
Natural convective cooling (Wind-speed < 0.5 m/s)
Equation 13
Low wind-speed cooling (All Wind speed)
Equation 14
High wind-speed cooling (Wind-speed < 0.5 m/s)
P341/EN OP/G74
Operation of Individual Protection Functions (OP) 5 Operation
45
55
65
75
15
25
35
85
95
5
Temperature
T film
ºC
Equation 15
Where:
f = Air density (kg/ m3)
f = Absolute viscosity of air (kg/m hr)
Thermal
D = Overall conductor diameter (m)
K)
Dynamic discosity µ f
(Pa.s) 0 m
Air density p f (kg/m
3
)
1000 m 2000 m
0.0000174 1.270 1.126 0.995
4000 m
Thermal conductivity of air k f
W/(m ºC)
0.771 0.0246
0.0000179
0.0000184
0.0000188
0.0000193
0.0000198
0.0000202
0.0000207
0.0000211
0.0000215
1.226
1.184
1.146
1.110
1.076
1.044
1.014
0.986
0.959
1.087
1.051
1.016
0.984
0.954
0.926
0.899
0.874
0.850
0.961
0.928
0.898
0.870
0.843
0.818
0.795
0.773
0.752
0.744
0.719
0.696
0.674
0.653
0.634
0.616
0.598
0.582
0.0254
0.0261
0.0269
0.0276
0.0283
0.0291
0.0298
0.0306
0.0313
Table 8 - Viscosity, density, and thermal conductivity of air
The maximum value of the calculated convective cooling is used in the relay algorithm.
P
C
= MAX (P
C
_ natr
, P
C
_low, P
C
_high) k angle
1.19.3.2 Radiative Cooling – P
R
IEEEE calculates the radiative cooling as shown below:
Equation 16
Where:
= Emissivity (unitless)
D = Overall conductor diameter (m)
P341/EN OP/G74 Page (OP) 5-49
(OP) 5 Operation
1.19.3.3
1.19.3.4
1.19.3.5
Operation of Individual Protection Functions
Solar Heating – P
S
IEEE considers the atmospheric conditions that instantly influence the direct solar radiation. IEEE calculates the solar heating as below:
Equation 17
Where:
s = Solar absorptivity (unitless)
Φ
s = Total solar and sky radiated heat flux (W/m 2
= Effective angle of incidence of the sun’s rays (°)
A = Projected area of the conductor (m
D = Overall conductor diameter (m)
2
) per lineal meter)
The real-time solar calculation, Φ s. Sin ( ), depends on the date and time of the year and also the line conductor latitude and longitude and thus is currently not implemented in the
P341.
In the P341 solar heating is implemented in a similar way to the CIGRE standard as shown below:
S = Global solar radiation (W/m2)
Joule Heating – P
J
IEEE uses AC current to calculate the Joule heating and calculates the resistance of the line conductor by interpolation.
Equation 18
Where:
I ac
T c
= Conductor AC current (A)
= Conductor temperature (°C)
R(T c
) = AC resistance at T c
per unit length ( /m)
IEEE Ampacity Calculation
This section briefly describes the algorithm for calculating the line ampacity.
From Equation 3 and Equation 18, the line’s rating, Iac, can be calculated as shown in
1.19.4
Equation 19
Conductor Temperature
Conductor temperature, including steady state conductor temperature and dynamic
conductor temperature, can be calculated by resolving Equation 1 as shown below in
Equation 20
Page (OP) 5-50 P341/EN OP/G74
Operation of Individual Protection Functions
1.19.5
(OP) 5 Operation
Where:
Tc(t) =
Tc(t+ t) =
Conductor temperature at the specific time t (°C)
Conductor temperature after a short time t from t (°C)
The steady state conductor temperature can be considered as the final state conductor temperature, which can be calculated by assuming all of the conditions, e.g. the environmental parameters and current flow, remain stable (considering the heat is balanced as P
J
+P
S
-P
C
-P
R
= 0).
The dynamic conductor temperature is the real-time conductor temperature, which can be calculated by assuming that the calculation time interval ( t) is relatively short, say, less than one twentieth of the thermal time constant.
Although the calculation methods are different for calculating steady state and dynamic conductor temperature, a simple concept can be used to distinguish them using t. t is infinite time for calculating the steady state conductor temperature, but is a relatively small value for calculating dynamic conductor temperature.
Protection Relay Operation
The dynamic line rating protection is included as an additional function to the existing protection functions of the P341 in version 7x software.
The current loop interface (0-1 mA, 0 -10 mA, 0-20 mA or 4-20 mA) is an analogue electrical transmission standard for instruments and transducers, therefore, it is the most suitable form of communications between the weather station sensors and the relay.
Thus, the relay does not need to implement specific communication protocols for different weather stations. The relay allows the user to select the type and the current loop input channels to be used for the ambient temperature, wind velocity, wind direction and the
solar radiation sensor inputs, see Figure 34. The user can also define the range of the
physical quantities measured by the sensors, so that the current loop measurements can be interpreted correctly by the relay. An averaging function can optionally be applied to each of the meteorological measurements - wind speed, wind angle, ambient temperature and solar radiation which can vary over a period of time. The results are fed into the algorithm which implements the dynamic line rating calculations. Three phase currents are also measured and the maximum phase current magnitude is selected for the alarm and tripping criteria. User-defined hysteresis (pick-up / drop-off ratio) is available to ensure correct operation even in the presence of fluctuating currents. The current magnitudes, together with the sensor measurements are available from the relay as measuring quantities in the MEASUREMENTS 4 menu. They can be accessed either locally through the front panel, or remotely using one of the relay’s remote communication ports. Other derived values, in particular, the calculated line ampacity and stead state and dynamic conductor temperatures are also available to be accessed in the
MEASUREMENTS 4 menu.
There are a total of 6 DLR protection stages, all of which have their own setting level as a percentage of the line ampacity and time delay settings. These 6 stages can be used to provide alarms, controls or tripping signals. DDB Signals are available to indicate the start and trip of each stage (DLR I>1/2/3/4/5/6 Start: DDB 1206-1211, DLR I>1/2/3/4/5/6 Trip:
DDB 952-957). There is also an inhibit input for each protection element and for all elements, which can be used to inhibit the DLR operation (DLR I>1/2/3/4/5/6 Inhibit, DLR
Scheme Inh: DDB 642-648). For the 4-20 mA inputs a current level below 4 mA indicates that there is a fault with the transducer or the wiring. An instantaneous under current alarm element is available with a setting range 0-4 mA which controls a number of alarm signals (Amb T Fail Alm, Wind V Fail Alm, Wind D Fail Alm, Solar R Fail Alm, DDB 396-
399).
The state of the DDB signals can be programmed to be viewed in the Monitor Bit x cells of the COMMISSION TESTS column in the relay. The protection starts for each element are mapped internally to the ANY START DDB signal – DDB992.
P341/EN OP/G74 Page (OP) 5-51
(OP) 5 Operation Operation of Individual Protection Functions
In configuring the relay, apart from setting the trip thresholds and time delays, it is also necessary to enter a range of conductor data parameters, which are required for the heating and cooling calculations (PJ, PC, Pr and PS). To assist the user, the relay stores the relevant parameters of 36 types of British conductors and a custom conductor type can also be defined.
There are six protection stages with pre-indicating start signals for DLR protection.
The operation of each stage can be explained as follows,
I operate
= max (Ia, Ib, Ic)
Pickup criteria: I operate
/I
Drop-off criteria: I operate
Where, ac
/I
threshold (%) ac
< threshold (%) * Drop-off Ratio
I operate
I ac
is the operating quantity for the protection
is the calculated dynamic line rating
Page (OP) 5-52
Figure 33 - Dynamic line rating protection outputs for 6 stages
P341/EN OP/G74
Operation of Individual Protection Functions (OP) 5 Operation
Figure 34 - Dynamic line rating protection inputs
P341/EN OP/G74 Page (OP) 5-53
(OP) 5 Operation
2
2.1
2.1.1
Operation of Non-Protection Functions
OPERATION OF NON-PROTECTION FUNCTIONS
Check Synchronism (25)
Overview
In most situations it is possible for both the Generator and Bus sides of a circuit breaker to be live when the circuit breaker is open, for example where the Bus has a power source. Therefore when closing the circuit breaker, it is normally necessary to check that the network conditions on both sides are suitable, before giving a CB Close command. This applies to manual circuit breaker closing of any CB and auto-reclosure applications specific to feeder CBs. If a circuit breaker is closed when the generator and bus voltages are both live, with a large phase angle, frequency or magnitude difference between them, the system could be subjected to an unacceptable shock, resulting in loss of stability, and possible damage to connected machines.
System checks involve monitoring the voltages on both sides of a circuit breaker, and, if both sides are live, performing a synchronism check to determine whether the phase angle, frequency and voltage magnitude differences between the voltage vectors, are within permitted limits.
The pre-closing system conditions for a given circuit breaker depend on the system configuration and, for auto-reclosing, on the selected auto-reclose program. For example, on a feeder with delayed auto-reclosing, the circuit breakers at the two line ends are normally arranged to close at different times. The first line end to close usually has a live bus and a dead line immediately before reclosing, and charges the line (dead line charge) when the circuit breaker closes. The second line end circuit breaker sees live bus and live line after the first circuit breaker has re-closed. If there is a parallel connection between the ends of the tripped feeder, they are unlikely to go out of synchronism, i.e. the frequencies will be the same, but the increased impedance could cause the phase angle between the two voltages to increase. Therefore the second circuit breaker to close might need a synchronism check, to ensure that the phase angle has not increased to a level that would cause an unacceptable shock to the system when the circuit breaker closes.
If there are no parallel interconnections between the ends of the tripped feeder, the two systems could lose synchronism, and the frequency at one end could slip relative to the other end. In this situation, the second line end would require a synchronism check comprising both phase angle and slip frequency checks.
If the second line end busbar has no power source other than the feeder that has tripped; the circuit breaker will see a live line and dead bus assuming the first circuit breaker has re-closed. When the second line end circuit breaker closes the bus will charge from the live line (dead bus charge).
For generator applications before closing the CB the frequency and voltage from the machine is varied automatically or manually until the generator voltage is in synchronism with the power system voltage. A check synchronizing relay is used to check the generator voltage is in synchronism with the system voltage in terms of voltage magnitude, voltage difference, phase angle and slip frequency before the generator CB is allowed to close.
Page (OP) 5-54 P341/EN OP/G74
Operation of Non-Protection Functions
2.1.2
2.1.3
(OP) 5 Operation
VT Selection
The P34x has a three-phase Main VT input and a single-phase Check Sync VT input.
Depending on the primary system arrangement, the main three-phase VT for the relay may be located on either the busbar side or the generator side of the circuit breaker, with the check sync. VT being located on the other side. Hence, the relay has to be programmed with the location of the main VT. This is done via the Main VT Location -
Gen/Bus setting in the SYSTEM CONFIG menu. This is required for the voltage monitors to correctly define the Live Gen/Dead Gen and Live Bus/Dead Bus DDBs.
The Check Sync. VT may be connected to either a phase to phase or phase to neutral voltage, and for correct synchronism check operation, the relay has to be programmed with the required connection. The C/S Input setting in the CT & VT RATIOS menu should be set to A-N , B-N , C-N , A-B , B-C or C-A as appropriate.
The P341 (40TE case) uses the neutral voltage input, VNeutral, for the Check Synch VT and so the user can not use check synch and measured neutral voltage (59N) protection
(VN>3, VN>4) at the same time. The derived neutral voltage protection (VN>1, VN>2) from the 3 phase voltage input can still be used with the check synchronizing function.
The P341 (60TE case) uses a dedicated V Check Sync voltage input for the Check
Synch VT and so there are no restrictions in using the check synchronizing function and other protection functions in the relay.
Basic Functionality
System check logic is collectively enabled or disabled as required, by setting System
Checks in the CONFIGURATION menu. The associated settings are available in
SYSTEM CHECKS , sub-menus VOLTAGE MONITORS , CHECK SYNC and SYSTEM
SPLIT . If System Checks is selected to Disabled , the associated SYSTEM CHECKS menu becomes invisible, and a Sys checks inactive DDB signal is set.
P341/EN OP/G74
Figure 35 - Synchro check and synchro split functionality
The overall Check Sync and System Split
functionality is shown in Figure 35.
In most situations where synchronism check is required, the Check Sync 1 function alone will provide the necessary functionality, and the Check Sync 2 and System Split signals can be ignored.
Page (OP) 5-55
(OP) 5 Operation
2.1.3.1
2.1.3.2
Operation of Non-Protection Functions
Voltage Monitors
The P34x System Checks function includes voltage monitors to indicate if the generator and system busbar voltages are Live or Dead.
The voltage monitor DDBs, if required, are combined in the PSL to provide the manual
CB close check synchronizing logic, e.g. Dead Line/Live Gen. The DDBs are connected to the Man Check Synch DDB (1362) which provides an input to the CB control logic to indicate a manual check synchronizing condition is satisfied.
When Vgen magnitude is > Live Voltage, the generator is taken as Live (DDB
1328, Live Gen)
When Vgen magnitude is < Dead Voltage, the generator is taken as Dead (DDB
1329, Dead Gen)
When Vbus magnitude is > Live Voltage, the busbar is taken as Live (DDB 1330,
Live Bus)
When Vbus magnitude is < Dead Voltage, the busbar is taken as Dead (DDB 1331,
Dead Bus)
Synchronism Check
The P34x System Checks function includes 2 check synchronization elements, Check
Sync 1 and Check Sync 2. The check synch 1 OK (1332) and Check Synch 2 OK (1333)
DDBs, if required, are used in the PSL to provide the manual CB close check synchronizing logic. The DDBs are connected to the Man Check Synch DDB (1362) which provides an input to the CB control logic to indicate a manual check synchronizing condition is satisfied.
Each check synch element checks that the generator frequency, voltage magnitude, and phase angle match the system frequency, voltage magnitude, and phase angle before allowing the generator breaker to be closed. Each element includes settings for the phase angle difference and slip frequency between the generator and system busbar voltages.
The P34x also includes independent under/over voltage monitors for the generator and system side of the CB as well as a differential voltage monitor applicable to both the
Check Sync 1 and 2 elements. The user can select a number of under/over/differential voltage check synchronizing blocking options using the setting CS Voltage Block –
None , V< , V> , Vdiff> , V< and V> , V< and Vdiff> , V> and Vdiff> , V< V> Vdiff> .
The slip frequency used by Check Synch 1/2 can be calculated from the CS1/2 Phase
Angle and CS1/2 Slip Timer settings as described below or can be measured directly from the frequency measurements, slip frequency = |Fgen-Fbus|. The user can select a number of slip frequency options using the settings CS1 Slip Control – None , Timer
Only , Frequency Only , Frequency + Timer, Frequency + CB and CS2 Slip Control –
None , Timer , Frequency .
If Slip Control by Timer or Frequency + Timer/Both is selected, the combination of CS
Phase Angle and CS Slip Timer settings determines an effective maximum slip frequency, calculated as:
2 x A
T x 360 Hz. for Check Sync. 1, or
A
T x 360 Hz. for Check Sync. 2
A =
T =
Phase Angle setting ( )
Slip Timer setting (seconds)
The Frequency + CB (Frequency + CB Time Compensation) setting modifies the Check
Sync 2 function to take account of the circuit breaker closing time. When set to provide
Page (OP) 5-56 P341/EN OP/G74
Operation of Non-Protection Functions (OP) 5 Operation
CB Close Time compensation, a predictive approach is used to close the circuit breaker ensuring that closing occurs at close to 0º therefore minimizing the impact to the power system. The actual closing angle is subject to the constraints of the existing product architecture, i.e. the protection task runs four times per power system cycle, based on frequency tracking over the frequency range of 40 Hz to 70 Hz.
Check Sync 1 and Check Sync 2 are two synchronism check logic modules with similar
functionality, but independent settings (see Figure 35).
For either module to function: the System Checks setting must be Enabled
AND the individual CS1/2 Status setting must be Enabled
AND the module must be individually enabled, by activation of DDB signal CS1/2 Enabled , mapped in PSL.
When enabled, each logic module sets its output signal when:
Gen volts and bus volts are both live (Gen Live and Bus Live signals both set)
AND measured phase angle is < CS1/2 Phase Angle setting
AND
(for Check Sync 2 only), the phase angle magnitude is decreasing (Check Sync 1 can operate with increasing or decreasing phase angle provided other conditions are satisfied)
AND if CS1/2 Slip Control is set to Frequency Only or Frequency or Frequency + Timer the measured slip frequency is < CS1/2 Slip Freq Setting
AND if CS Voltage Block is set to V> or V< and V> or V> and VDiff> or V< V> Vdiff> , both generator voltage and busbar voltage magnitudes are < Gen Over Voltage and CS Over
Voltage setting respectively
AND if CS Voltage Block is set to V< , or V< and V> or V< and Vdiff> or V< V> Vdiff>, generator voltage and busbar voltage magnitudes are > Gen Under Voltage and CS
Under Voltage setting respectively
AND if CS Voltage Block is set to Vdiff> or V< and Vdiff or V> and VDiff> or V< V> Vdiff> , the voltage magnitude difference between generator voltage and busbar voltage is < CS
Diff Voltage setting
AND if CS 1/2 Slip Control is set to Timer or Frequency + Timer (CS1) / Freq + Timer
(CS2), the above conditions have been true for a time > or = CS 1/2 Slip Timer setting
P341/EN OP/G74 Page (OP) 5-57
(OP) 5 Operation
2.1.3.3
Operation of Non-Protection Functions
System Split
For the System Split module to function (see Figure 35):
The System Checks setting must be Enabled
AND the SS Status setting must be Enabled
AND the module must be individually enabled, by activation of DDB signal Sys Split Enabled , mapped in PSL.
When enabled, the System Split module sets its output signal when:
Gen volts and bus volts are both live (Line Gen and Bus Live signals both set)
AND measured phase angle is > SS Phase Angle setting
AND if SS Volt Blocking is set to Enabled , both gen volts and bus volts magnitudes are > SS
Undervoltage setting
The System Split output remains set for as long as the above conditions are true, or for a minimum period equal to the SS Timer setting, whichever is longer.
The overall system checks functionality and default PSL for the function is shown in
Page (OP) 5-58 P341/EN OP/G74
Operation of Non-Protection Functions (OP) 5 Operation
Figure 36 - System checks functional logic diagram
P341/EN OP/G74 Page (OP) 5-59
(OP) 5 Operation
2.1.3.4
Operation of Non-Protection Functions
Voltage and Phase Angle Correction
This C/S V Ratio Corr setting in the SYSTEM CONFIG menu is used by the System
Check function to provide magnitude correction to the check synch VT to correct for small differences between the main VT and check synch VT. Magnitude differences may be introduced by unmatched or slightly erroneous voltage transformer ratios, normally the setting is close to 1.0.
The Main VT Vect Grp setting in the SYSTEM CONFIG menu is used by the System
Check function to provide vector correction between the main VT and check synch VT caused by the vector group phase shift (e.g. 30 degree phase shift for a Dy11 or Dy1 transformer vector group) across the generator-transformer.
There are some applications where the main VT is on the generator side of a transformer and the check sync VT is in the transformer LV side or vice-versa where vector group correction may be required.
The Voltage Transformer Supervision (VTS) feature is used to detect failure of the ac voltage inputs to the relay. This may be caused by internal voltage transformer faults, overloading, or faults on the interconnecting wiring to relays. This usually results in one or more VT fuses blowing. Following a failure of the ac voltage input there would be a misrepresentation of the phase voltages on the power system, as measured by the relay, which may result in mal-operation.
The VTS logic in the relay is designed to detect the voltage failure, and automatically adjust the configuration of protection elements whose stability would otherwise be compromised. A time-delayed alarm output is also available.
There are three main aspects to consider regarding the failure of the VT supply. These are defined below:
1. Loss of one or two-phase voltages
2. Loss of all three-phase voltages under load conditions
3. Absence of three-phase voltages upon line energization
The VTS feature within the relay operates on detection of negative phase sequence
(NPS) voltage without the presence of negative phase sequence current. This gives operation for the loss of one or two-phase voltages. Stability of the VTS function is assured during system fault conditions, by the presence of NPS current. The use of negative sequence quantities ensures correct operation even where three-limb or ‘V’ connected VT’s are used.
Negative sequence VTS element:
The negative sequence thresholds used by the element are V2 = 10 V (Vn = 100/120 V) or 40 V (Vn = 380/480 V), and I2 = 0.05 to 0.5 In settable (defaulted to 0.05 In).
Page (OP) 5-60 P341/EN OP/G74
Operation of Non-Protection Functions
2.2.1
2.2.2
(OP) 5 Operation
Loss of All Three-Phase Voltages Under Load Conditions
Under the loss of all three-phase voltages to the relay, there will be no negative phase sequence quantities present to operate the VTS function. However, under such circumstances, a collapse of the three-phase voltages will occur. If this is detected without a corresponding change in any of the phase current signals (which would be indicative of a fault), then a VTS condition will be raised. In practice, the relay detects the presence of superimposed current signals, which are changes in the current applied to the relay. These signals are generated by comparison of the present value of the current with that exactly one cycle previously. Under normal load conditions, the value of superimposed current should therefore be zero. Under a fault condition a superimposed current signal will be generated which will prevent operation of the VTS.
The phase voltage level detectors are fixed and will drop off at 10 V (Vn = 100/120 V),
40 V (Vn = 380/480 V) and pick-up at 30 V (Vn = 100/120 V), 120 V (Vn = 380/480 V).
The sensitivity of the superimposed current elements is fixed at 0.1 In.
Absence of Three-Phase Voltages Upon Line Energization
If a VT were inadvertently left isolated prior to line energization, incorrect operation of voltage dependent elements could result. The previous VTS element detected threephase VT failure by absence of all three-phase voltages with no corresponding change in current. On line energization there will, however, be a change in current (as a result of load or line charging current for example). An alternative method of detecting threephase VT failure is therefore required on line energization.
The absence of measured voltage on all three-phases on line energization can be as a result of 2 conditions. The first is a three-phase VT failure and the second is a close up three-phase fault. The first condition would require blocking of the voltage dependent function and the second would require tripping. To differentiate between these 2 conditions an overcurrent level detector (VTS I> Inhibit) is used which will prevent a VTS block from being issued if it operates. This element should be set in excess of any nonfault based currents on line energization (load, line charging current, transformer inrush current if applicable) but below the level of current produced by a close up three-phase fault. If the line is now closed where a three-phase VT failure is present the overcurrent detector will not operate and a VTS block will be applied. Closing onto a three-phase fault will result in operation of the overcurrent detector and prevent a VTS block being applied.
This logic will only be enabled during a live line condition (as indicated by the relays pole dead logic) to prevent operation under dead system conditions i.e. where no voltage will be present and the VTS I> Inhibit overcurrent element will not be picked up.
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(OP) 5 Operation Operation of Non-Protection Functions
Page (OP) 5-62
P2226ENa
Figure 37 - VTS logic
Required to drive the VTS logic are a number of dedicated level detectors as follows:
IA>, IB>, IC>, these level detectors operate in less than 20 ms and their settings should be greater than load current. This setting is specified as the VTS current threshold. These level detectors pick-up at 100% of setting and drop-off at 95% of setting.
I2>, this level detector operates on negative sequence current and has a user setting. This level detector picks-up at 100% of setting and drops-off at 95% of setting.
IIA>, IB>, IC>, these level detectors operate on superimposed phase currents and have a fixed setting of 10% of nominal. These level detectors are subject to a count strategy such that 0.5 cycle of operate decisions must have occurred before operation.
VA>, VB>, VC>, these level detectors operate on phase voltages and have a fixed setting, Pick-up level = 30 V (Vn = 100/120 V), 120 V (Vn = 380/480 V), Drop Off level = 10 V (Vn = 100/120 V), 40 V (Vn = 380/480 V).
V2>, this level detector operates on negative sequence voltage, it has a fixed setting of 10 V/40 V depending on VT rating (100/120 or 380/480) with pick-up at
100% of setting and drop-off at 95% of setting.
P341/EN OP/G74
Operation of Non-Protection Functions
2.2.2.1
2.2.2.2
2.2.3
(OP) 5 Operation
Inputs
Signal name
IA>, IB>, IC>
I2>
IA, IB, IC
VA>, VB>, VC>
V2>
Description
Phase current levels (Fourier magnitudes)
I2 level (Fourier magnitude).
Phase current samples (current and one cycle previous)
ALL POLE DEAD
VTS_MANRESET
Phase voltage signals (Fourier magnitudes)
Negative sequence voltage (Fourier magnitude)
Breaker is open for all phases (driven from auxiliary contact or pole dead logic).
A VTS reset performed via front panel or remotely.
VTS_AUTORESET
MCB/VTS OPTO
Accelerate Ind
Any Pole Dead tVTS
A setting to allow the VTS to automatically reset after this delay.
To remotely initiate the VTS blocking via an opto
Any Voltage Dependent
Function
Outputs from any function that utilizes the system voltage, if any of these elements operate before a VTS is detected the VTS is blocked from operation. The outputs include starts and trips.
Signal from a fast tripping voltage dependent function used to accelerate indications when the indicate only option is selected
Breaker is open on one or more than one phases (driven from auxiliary contact or pole dead logic)
The VTS timer setting for latched operation
Table 9 - VTS inputs
Outputs
Signal name
VTS Fast Block
VTS Slow Block
VTS Indication
Table 10 - VTS outputs
Description
Used to block voltage dependent functions
Used to block the Any Pole dead signal
Signal used to indicate a VTS operation
Operation
The relay may respond as follows to an operation of any VTS element:
VTS set to provide alarm indication only (DDB 356 VT Fail Alarm);
Optional blocking of voltage dependent protection elements (DDB 1248 VTS Fast
Block, DDB 1249 VTS Slow Block);
Optional conversion of directional SEF, directional overcurrent and directional NPS overcurrent elements to non-directional protection (available when set to blocking mode only). These settings are found in the function links cell of the relevant protection element columns in the menu.
Time delayed protection elements (Directional NPS Overcurrent, Directional SEF, Power,
Sensitive Power, Field Failure) are blocked after the VTS Time Delay on operation of the
VTS Slow Block. Fast operating protection elements (Directional overcurrent, Neutral
Voltage Displacement, System Backup, Undervoltage, Dead Machine, Pole Slipping,
NPS Overpower) are blocked on operation of the VTS Fast Block.
Note The directional SEF and neutral voltage displacement protection are only blocked by VTS if the neutral voltage input is set to Derived and not
Measured.
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(OP) 5 Operation Operation of Non-Protection Functions
Other protections can be selectively blocked by customizing the PSL, integrating DDB
1248 VTS Fast Block and DDB 1249 VTS Slow Block with the protection function logic.
The VTS I> Inhibit or VTS I2> Inhibit elements are used to override a VTS block in event of a fault occurring on the system which could trigger the VTS logic. Once the VTS block has been established, however, then it would be undesirable for subsequent system faults to override the block. The VTS block will therefore be latched after a user settable time delay VTS Time Delay . Once the signal has latched then two methods of resetting are available. The first is manually via the front panel interface (or remote communications) provided the VTS condition has been removed and secondly, when in
Auto mode, by the restoration of the three-phase voltages above the phase level detector settings mentioned previously.
A VTS indication will be given after the VTS Time Delay has expired. In the case where the VTS is set to indicate only the relay may potentially mal-operate, depending on which protection elements are enabled. In this case the VTS indication will be given prior to the
VTS time delay expiring if a trip signal is given.
Where a Miniature Circuit Breaker (MCB) is used to protect the voltage transformer ac output circuits, it is common to use MCB auxiliary contacts to indicate a three-phase output disconnection. As previously described, it is possible for the VTS logic to operate correctly without this input. However, this facility has been provided for compatibility with various utilities current practices. Energizing an opto-isolated input assigned to “MCB
Open” on the relay will therefore provide the necessary block.
Where directional overcurrent elements are converted to non-directional protection on
VTS operation, it must be ensured that the current pick-up setting of these elements is higher than full load current.
The blocking of the VTS logic for a number of different fault conditions is considered below, assuming Vn = 100/120 V.
The I2> element should detect phase-earth faults and block the VTS logic when the CB is closed for solidly earthed generators.
For a high impedance earthed system the level of Io, I2 and V2 will be very small
<5% for an earth fault. For a generator connected to load if there is a close-up earth fault where the voltage on 1 phase < 10 V and the delta change in current on the faulted phase is >10%In the VTS logic is blocked.
For example if load current is 0.5 In and there is an A-N fault then the current in the faulted phase will drop to say 1%In during an earth fault and so delta I A = 0.49 In which is > 0.1 In delta threshold. So, Delta I = ON, Any Pole Dead = OFF, VA> =
OFF (<10 V) for a close up fault and so the VTS is blocked.
During starting of the machine if the CB auxiliary contacts are indicating the CB is open the VTS logic is blocked. However, if a contact is used to indicate the CB is closed during the start up of the machine then the VTS logic will be active.
If there is an A-N fault during the start-up of the machine and the CB is closed and the voltage was >30 V (VA>/VB>/VC>) if the VA> element drops off (<10 V) due to the fault and the delta change in current is <10% In (delta IA>) there could be a potential incorrect operation of the VTS logic.
So, if the load current during the start up period is < 0.1 In then there could be a false VTS operation if the relay thinks the CB is closed.
Note: The VTS operates will block the derived neutral voltage protection but the measured neutral voltage protection is not blocked and will trip correctly during an earth fault.
Page (OP) 5-64 P341/EN OP/G74
Operation of Non-Protection Functions (OP) 5 Operation
The I2> element should detect phase-phase faults and block the VTS logic when the CB is closed.
The delta current level detectors should detect the change in current for a close up
3 phase fault when the CB is closed and block the VTS.
The IA>/IB>/IC> level detectors should detect a 3 phase fault when closing the CB onto a fault and block the VTS logic.
The CT supervision feature operates on detection of derived residual current, in the absence of corresponding derived or measured residual voltage that would normally accompany it.
The CT supervision can be set to operate from the residual voltage measured at the
VNEUTRAL input (VN input) or the residual voltage derived from the three-phase-neutral voltage inputs as selected by the CTS Vn Input setting.
The voltage transformer connection used must be able to refer residual voltages from the primary to the secondary side. Thus, this element should only be enabled where the three-phase VT is of five limb construction, or comprises three single-phase units, and has the primary star point earthed. A derived residual voltage or a measured residual voltage is available.
There is one stage of CT supervision CTS-1. The derived neutral current is calculated vectorially from IA, IB, IC for CTS-1. The neutral voltage is either measured or derived, settable by the user.
CTS-1 supervises the CT inputs to IA, IB, IC which are used by the all the power and overcurrent based protection functions.
Operation of the element will produce a time-delayed alarm visible on the LCD and event record (plus DDB 357: CT-1 Fail Alarm), with an instantaneous block (DDB 1263: CTS-1
Block) for inhibition of protection elements. Protection elements operating from derived quantities, (Negative Phase Sequence (NPS) Overcurrent and Thermal Overload protection) are always blocked on operation of the CTS-1 supervision element; other protections can be selectively blocked by customizing the PSL, integrating DDB 1263:
CTS-1 Block with the protection function logic.
CTS Block
I
N
>
&
Time delay t
CTS Alarm
V
N
<
P2130ENa
Figure 38 - CT supervision diagram
P341/EN OP/G74 Page (OP) 5-65
(OP) 5 Operation Operation of Non-Protection Functions
2.4.1
Page (OP) 5-66
An operator at a remote location requires a reliable indication of the state of the switchgear. Without an indication that each circuit breaker is either open or closed, the operator has insufficient information to decide on switching operations. The relay incorporates circuit breaker state monitoring, giving an indication of the position of the circuit breaker, or, if the state is unknown, an alarm is raised.
Circuit Breaker State Monitoring Features
Schneider Electric relays can be set to monitor normally open (52a) and normally closed
(52b) auxiliary contacts of the circuit breaker. Under healthy conditions, these contacts will be in opposite states. Should both sets of contacts be open, this would indicate one of these conditions:
Auxiliary
Circuit Breaker (CB) is defective
CB is in isolated position
Should both sets of contacts be closed, only one of these two conditions would apply:
Auxiliary
Circuit Breaker (CB) is defective
If any of the above conditions exist, an alarm will be issued after a 5 s time delay. A normally open/normally closed output contact can be assigned to this function via the
Programmable Scheme Logic (PSL). The time delay is set to avoid unwanted operation during normal switching duties.
In the CB CONTROL column of the relay menu there is a setting called CB Status Input .
This cell can be set at one of these four options:
None
52A
52B
Both 52A and 52B
Where None is selected no CB status will be available. This will directly affect any function within the relay that requires this signal, for example CB control, auto-reclose, etc. Where only 52A is used on its own then the relay will assume a 52B signal from the absence of the 52A signal. Circuit breaker status information will be available in this case but no discrepancy alarm will be available. The above is also true where only a 52B is used. If both 52A and 52B are used then status information will be available and in
addition a discrepancy alarm will be possible, according to Table 11. 52A and 52B inputs
are assigned to relay opto-isolated inputs via the PSL. The CB State Monitoring logic is
Auxiliary contact position CB state detected
52A 52B
Open
Closed
Closed
Open
Breaker Open
Breaker Closed
Action
Circuit breaker healthy
Circuit breaker healthy
Alarm raised if the condition persists for greater than 5 s
Alarm raised if the condition persists for greater than 5 s
Table 11 - CB state logic
P341/EN OP/G74
Operation of Non-Protection Functions (OP) 5 Operation
P341/EN OP/G74
Figure 39 - CB state monitoring
P2227ENd
Page (OP) 5-67
(OP) 5 Operation Operation of Non-Protection Functions
The Pole Dead Logic can indicate if one or more phases of the line are dead. It can also be used to selectively block operation of the underfrequency, under voltage and power elements. The under voltage protection will be blocked by a pole dead condition provided the Pole Dead Inhibit setting is enabled. Any of the four underfrequency elements can be blocked by setting the relevant F< function links . The Power and Sensitive Power protection will be blocked by a pole dead condition provided the Pole Dead Inhibit setting is enabled.
A pole dead condition can be determined by either monitoring the status of the CB auxiliary contacts or by measuring the line currents and voltages. The status of the CB is provided by the CB State Monitoring logic. If a CB Open signal (DDB 1282) is given the relay will automatically initiate a pole dead condition regardless of the current and voltage measurement. Similarly if both the line current and voltage fall below a pre-set threshold the relay will also initiate a pole dead condition. This is needed so a pole dead indication is given even when an upstream breaker is opened. The undervoltage (V<) and undercurrent (I<) thresholds have these fixed, pickup and drop-off levels:
Settings
V< Pick-up and drop off
I< Pick-up and drop off
Table 12 - Pole dead settings
Range
10 V and 30 V (100/120 V)
40 V and 120 V (380/480 V)
0.05 In and 0.055 In
Fixed
Fixed
Step size
If one or more poles are dead, the relay will show which phase is dead and will also assert the ANY POLE DEAD DDB signal (DDB 1285). If all phases were dead the ANY
POLE DEAD signal would be accompanied by the ALL POLE DEAD DDB signal (DDB
1284).
If the VT fails, a signal is taken from the VTS logic (DDB 1249 – VTS Slow Block) to block the pole dead indications that would be generated by the under voltage and undercurrent thresholds. However, the VTS logic will not block the pole dead indications if they are initiated by a CB Open
signal (DDB 1282). Figure 40 shows the pole dead logic diagram:
Page (OP) 5-68
Figure 40 - Pole dead logic
P341/EN OP/G74
Operation of Non-Protection Functions (OP) 5 Operation
2.6 Circuit Breaker (CB) Condition Monitoring
The P34x relays record various statistics related to each Circuit Breaker (CB) trip operation, allowing a more accurate assessment of the CB condition to be determined.
These monitoring features are discussed in the following section.
2.6.1 Circuit Breaker (CB) Condition Monitoring Features
For each Circuit Breaker (CB) trip operation the relay records statistics as shown in Table
13 taken from the relay menu. The menu cells shown are counter values only. The
Min./Max. values in this case show the range of the counter values. These cells can not be set:
Menu text
CB Operations {3 pole tripping} 0
Default setting
0
Min.
Setting range
Max.
10000
Displays the total number of 3 pole trips issued by the relay.
Total IA Broken 0 0
Displays the total accumulated fault current interrupted by the relay for the A phase.
Total IB Broken 0 0
25000 In^
25000 In^
1
1
1
Step size
Displays the total accumulated fault current interrupted by the relay for the A phase.
Total IC Broken 0 0
Displays the total accumulated fault current interrupted by the relay for the A phase.
25000 In^ 1 In^
CB Operate Time 0 0 0.5 s 0.001
Displays the calculated CB operating time. CB operating time = time from protection trip to undercurrent elements indicating the
CB is open.
Reset CB Data No Yes, No
Reset CB Data command. Resets CB Operations and Total IA/IB/IC broken current counters to 0.
Table 13 - CB condition monitoring settings
The above counters may be reset to zero, for example, following a maintenance inspection and overhaul.
The CB condition monitoring counters will be updated every time the relay issues a trip command. In cases where the CB is tripped by an external protection device it is also possible to update the CB condition monitoring. This is achieved by allocating one of the relays opto-isolated inputs (via the programmable scheme logic) to accept a trigger from an external device. The signal that is mapped to the opto is called Ext. Trip 3Ph , DDB
680.
Note When in Commissioning test mode the CB condition monitoring counters will not be updated.
P341/EN OP/G74 Page (OP) 5-69
(OP) 5 Operation
2.7
Operation of Non-Protection Functions
Circuit Breaker (CB) Control
The relay includes these options for control of a single Circuit Breaker (CB):
Local tripping and closing, via the relay menu.
Local tripping and closing, via relay opto-isolated inputs.
Remote tripping and closing, using the relay communications.
It is recommended that separate relay output contacts are allocated for remote CB control and protection tripping. This enables the control outputs to be selected via a local/remote
selector switch as shown in Figure 41. Where this feature is not required the same
output contact(s) can be used for both protection and remote tripping.
Menu text
CB control by
Close Pulse Time
Trip Pulse Time
Man Close Delay
CB Healthy Time
Lockout Reset
Figure 41 - Remote control of circuit breaker
Table 14 is taken from the relay menu and shows the available settings and commands
associated with circuit breaker control. Depending on the relay model some of the cells may not be visible:
0.5 s
0.5 s
10 s
5 s
No
Default setting
Disabled
Setting range Step size
Min.
CB control
Max.
Disabled, Local, Remote, Local+Remote, Opto, Opto+Local,
Opto+Remote, Opto+Rem+Local
0.01 s
0.01 s
0.01 s
0.01 s
No, Yes
10 s
5 s
600 s
9999 s
0.01 s
0.01 s
0.01 s
0.01 s
Page (OP) 5-70 P341/EN OP/G74
Operation of Non-Protection Functions (OP) 5 Operation
Menu text
Reset Lockout By
Man Close RstDly
CB Status Input
Default setting
CB Close
5 s
None
Setting range
Min.
CB control
User Interface, CB Close
Max.
0.01 s 600 s
None, 52A, 52B, Both 52A and 52B
0.01 s
Step size
Table 14 - CB control settings
A manual trip will be permitted provided that the circuit breaker is initially closed.
Likewise, a close command can only be issued if the CB is initially open. To confirm these states it will be necessary to use the breaker 52A and/or 52B contacts (the different selection options are given from the CB Status Input cell above). If no CB auxiliary contacts are available then this cell should be set to None. Under these circumstances no CB control (manual or auto) will be possible.
Once a CB Close command is initiated the output contact can be set to operate following a user-defined time delay ( Man Close Delay ). This would give personnel time to move away from the circuit breaker following the close command. This time delay will apply to all manual CB Close commands.
The length of the trip or close control pulse can be set via the Trip Pulse Time and
Close Pulse Time settings respectively. These should be set long enough to ensure the breaker has completed its open or close cycle before the pulse has elapsed.
Note The manual close commands are found in the SYSTEM DATA column and the hotkey menu.
If an attempt to close the breaker is being made, and a protection trip signal is generated, the protection trip command overrides the close command.
There is also a CB Healthy check if required. This facility accepts an input to one of the relays opto-isolators to indicate that the breaker is capable of closing (circuit breaker energy for example). A user settable time delay is included CB Healthy Time for manual closure with this check. If the CB does not indicate a healthy condition in this time period following a close command then the relay will lockout and alarm.
If the CB fails to respond to the control command (indicated by no change in the state of
CB Status inputs) a CB Failed to Trip or CB Failed to Close alarm will be generated after the relevant trip or close pulses have expired. These alarms can be viewed on the relay LCD display, remotely via the relay communications, or can be assigned to operate output contacts for annunciation using the relays programmable scheme logic (PSL).
The Lockout Reset and Reset Lockout by setting cells in the menu are applicable to
CB Lockouts associated with manual circuit breaker closure, CB Condition monitoring
(Number of circuit breaker operations, for example).
The lockout alarms can be reset using the Lockout Reset command or the by pressing the Clear key after reading the alarm or by closing the CB if the Reset Lockout By setting is set to CB Close or via an opto input using DDB 690, Reset Lockout. If lockout is reset by closing the CB then there is a time delay after closing the CB to resetting of lockout, the Man Close RstDly .
2.7.1 CB Control using “Hotkeys”
The hotkeys allow direct access to the manual trip and close commands without the need to enter the SYSTEM DATA column. The CB trip and close functionality via the hotkey menu is identical to that of the SYSTEM DATA menu.
IF <<TRIP>> or <<CLOSE>> is selected the user is prompted to confirm the execution of the relevant command. If a trip is executed a screen with the CB status will be displayed
P341/EN OP/G74 Page (OP) 5-71
(OP) 5 Operation Operation of Non-Protection Functions once the command has been completed. If a close is executed a screen with a timing bar will appear while the command is being executed. This screen has the option to cancel or restart the close procedure. The timer used is taken from the manual close delay timer setting in the CB Control menu. When the command has been executed, a screen confirming the present status of the circuit breaker is displayed. The user is then prompted to select the next appropriate command or exit – this will return to the default relay screen.
If no keys are pressed for a period of 25 seconds while waiting for the command confirmation, the relay will revert to showing the CB Status. If no key presses are made for a period of 25 seconds while displaying the CB status screen, the relay will revert to
the default relay screen. Figure 42 shows the hotkey menu associated with CB control
functionality.
To avoid accidental operation of the trip and close functionality, the hotkey CB control commands will be disabled for 10 seconds after exiting the hotkey menu.
Figure 42 - CB control hotkey menu
P2246ENi
Page (OP) 5-72 P341/EN OP/G74
Operation of Non-Protection Functions (OP) 5 Operation
2.9
P341/EN OP/G74
The setting groups can be changed either via 2 DDB signals or via a menu selection selection or via the hotkey menu. In the Configuration column if Setting Group - select via DDB is selected then DDBs 676 (SG Select 1x) and 675 (SG Select x1), which are dedicated for setting group selection, can be used to select the setting group as shown in the table below. These DDB signals can be connected to opto inputs for local selection or control inputs for remote selection of the setting groups. If Setting Group - select via menu is selected then in the Configuration column the Active Settings - Group1/2/3/4 can be used to select the setting group. The setting group can be changed via the hotkey menu providing Setting Group select via menu is chosen.
SG select 1x SG select x1 Selected setting group
0 0 1
1 0 2
0 1 3
1 1 4
Table 15 - Setting group selection logic
Note Setting groups comprise both Settings and Programmable Scheme Logic.
Each is independent per group - not shared as common. The settings are generated in the Settings and Records application within S1 Studio, or can be applied directly from the relay front panel menu. The programmable scheme logic can only be set using the PSL Editor application within S1
Studio, generating files with extension ".psl".
It is essential that where the installation needs application-specific PSL that the appropriate PSL file is downloaded (sent) to the relay, for each and every setting group that will be used. If the user fails to download the required PSL file to any setting group that may be brought into service, then factory default PSL will still be resident. This may have severe operational and safety consequences.
Control Inputs
The control inputs function as software switches that can be set or reset either locally or remotely. These inputs can be used to trigger any function that they are connected to as part of the PSL. There are three setting columns associated with the control inputs which are: CONTROL INPUTS , CTRL I/P CONFIG and CTRL I/P LABELS . The function of these columns is described below:
Menu text
Ctrl I/P Status
Control Input 1
Control Input 2 to 32
Default setting Setting range
CONTROL INPUTS
00000000000000000000000000000000
No Operation
No Operation
No Operation, Set, Reset
No Operation, Set, Reset
Step size
Table 16 - Control inputs
The Control Input commands can be found in the Control Input menu. In the Ctrl I/P status menu cell there is a 32 bit word which represent the 32 control input commands.
The status of the 32 control inputs can be read from this 32 bit word. The 32 control inputs can also be set and reset from this cell by setting a 1 to set or 0 to reset a particular control input. Alternatively, each of the 32 Control Inputs can be set and reset using the individual menu setting cells Control Input 1, 2, 3, etc. The Control Inputs are available through the relay menu as described above and also via the rear communications.
Page (OP) 5-73
(OP) 5 Operation Operation of Non-Protection Functions
In the programmable scheme logic editor 32 Control Input signals, DDB 1376 - 1407, which can be set to a logic 1 or On state, as described above, are available to perform control functions defined by the user.
The status of the Control Inputs are held in non-volatile memory (battery backed RAM) such that when the relay is power-cycled, the states are restored upon power-up.
Menu text
Hotkey Enabled
Control Input 1
Ctrl Command 1
Control Input 2 to 32
Ctrl Command 2 to 32
Default setting Setting range
CTRL I/P CONFIG
11111111111111111111111111111111
Latched
SET/RESET
Latched
SET/RESET
Step size
Latched, Pulsed
SET/RESET, IN/OUT, ENABLED/DISABLED,
ON/OFF
Latched, Pulsed
SET/RESET, IN/OUT, ENABLED/DISABLED,
ON/OFF
Table 17 - Control input configuration
Menu text
Control Input 1
Control Input 2 to 32
Default setting
CTRL I/P LABELS
Setting range
Control Input 1
Control Input 2 to 32
16 character text
16 character text
Step size
Table 18 - Control input labels
The CTRL I/P CONFIG column has several functions one of which allows the user to configure the control inputs as either latched or pulsed . A latched control input will remain in the set state until a reset command is given, either by the menu or the serial communications. A pulsed control input, however, will remain energized for 10ms after the set command is given and will then reset automatically (i.e. no reset command required).
In addition to the latched/pulsed option this column also allows the control inputs to be individually assigned to the “Hotkey” menu by setting ‘1’ in the appropriate bit in the
Hotkey Enabled cell. The hotkey menu allows the control inputs to be set, reset or pulsed without the need to enter the CONTROL INPUTS column. The Ctrl Command cell also allows the SET/RESET text, displayed in the hotkey menu, to be changed to something more suitable for the application of an individual control input, such as ON /
OFF , IN / OUT etc.
The CTRL I/P LABELS column makes it possible to change the text associated with each individual control input. This text will be displayed when a control input is accessed by the hotkey menu, or it can be displayed in the PSL.
Note With the exception of pulsed operation, the status of the control inputs is stored in battery backed memory. In the event that the auxiliary supply is interrupted the status of all the inputs will be recorded. Following the restoration of the auxiliary supply the status of the control inputs, prior to supply failure, will be reinstated. If the battery is missing or flat the control inputs will set to logic 0 once the auxiliary supply is restored.
Page (OP) 5-74 P341/EN OP/G74
Operation of Non-Protection Functions
2.10
2.11
(OP) 5 Operation
PSL DATA Column
The P341 range of relays contains a PSL DATA column that can be used to track PSL modifications. A total of 12 cells are contained in the PSL DATA column, 3 for each setting group. The function for each cell is shown below:
Grp PSL Ref
18 Nov 2002
08:59:32.047
When downloading a PSL to the relay, the user will be prompted to enter which groups the PSL is for and a reference ID. The first 32 characters of the reference ID will be displayed in this cell. The and keys can be used to scroll through 32 characters as only 16 can be displayed at any one time.
This cell displays the date and time when the PSL was down loaded to the relay.
Grp 1 PSL ID –
2062813232
This is a unique number for the PSL that has been entered.
Any change in the PSL will result in a different number being displayed.
Note The above cells are repeated for each setting group.
Auto Reset of Trip LED Indication
The trip LED can be reset when the flags for the last fault are displayed. The flags are displayed automatically after a trip occurs, or can be selected in the fault record menu.
The reset of trip LED and the fault records is performed by pressing the key once the fault record has been read.
Setting Sys Fn Links ( SYSTEM DATA Column) to logic “1” sets the trip LED to automatic reset. Resetting will occur when the circuit is reclosed and the Any Pole Dead signal (DDB 1284) has been reset for three seconds. Resetting, however, will be prevented if the Any start signal is active after the breaker closes.
Figure 43 - Trip LED logic diagram
P341/EN OP/G74 Page (OP) 5-75
(OP) 5 Operation
2.12
2.13
Operation of Non-Protection Functions
Reset of Programmable LEDs and Output Contacts
The programmable LEDs and output contacts can be set to be latched in the programmable scheme logic. If there is a fault record then clearing the fault record by pressing the key once the fault record has been read will clear any latched LEDs and output contacts. If there is no fault record, then as long as the initiating signal to the LED or output contact is reset the LEDs and contacts can be reset by one of these two methods.
1. Via View Records - Reset Indications menu command cell
2. Via DDB 689 Reset Relays/LED which can be mapped to an Opto Input or a
Control Input for example
Real Time Clock Synchronization Via Opto-Inputs
In modern protective schemes it is often desirable to synchronize the relays real time clock so that events from different relays can be placed in chronological order. This can be done using the IRIG-B input, if fitted, or via the communication interface connected to the substation control system. In addition to these methods the P341 range offers the facility to synchronize via an opto-input by routing it in PSL to DDB 687 (Time Sync.).
Pulsing this input will result in the real time clock snapping to the nearest minute if the pulse input is ± 3 s of the relay clock time. If the real time clock is within 3 s of the pulse the relay clock will crawl (the clock will slow down or get faster over a short period) to the correct time. The recommended pulse duration is 20 ms to be repeated no more than once per minute. An example of the time sync. function is shown below:
Time of “sync. pulse”
19:47:00 to 19:47:29
19:47:30 to 19:47:59
Table 19 - Time sync example
19:47:00
19:48:00
Corrected time
Note The above assumes a time format of hh:mm:ss
To avoid the event buffer from being filled with unnecessary time sync. events, it is possible to ignore any event that generated by the time sync. opto input. This can be done by applying these settings:
Menu text
RECORD CONTROL
Opto Input Event
Protection Event
DDB 63 - 32 (Opto Inputs)
Value
Enabled
Enabled
Set “Time Sync.” associated opto to 0
Table 20 - Event filtering of time sync signal
To improve the recognition time of the time sync. opto input by approximately 10 ms, the opto input filtering could be disabled. This is achieved by setting the appropriate bit to 0 in the Opto Filter Cntl cell ( OPTO CONFIG column).
Disabling the filtering may make the opto input more susceptible to induced noise.
Fortunately the effects of induced noise can be minimized by using the methods described in the Firmware Design chapter .
Page (OP) 5-76 P341/EN OP/G74
Operation of Non-Protection Functions
2.15
(OP) 5 Operation
The Any Trip DDB (DDB 674) has been made independent from Relay 3 in the version
32 software. In previous versions of software the Any Trip signal was the operation of
Relay 3. In the version 32 software DDB 674 is the Any Trip signal and any output contact used for tripping can be connected to the Any Trip DDB leaving Relay 3 to be freely assigned for any function. The Any Trip signal affects these functions:
Operates the Trip LED
Triggers CB condition maintenance counters
Used to measure the CB operating time
Triggers the circuit breaker failure logic
Used in the Fault recorder logic
In the default PSL, Relay 3 is still mapped to the Any Trip DDB and the Fault REC TRIG
DDB signals. If the user wants to make use of the CB maintenance features, CB failure function etc they should map the output contact(s) assigned for tripping the monitored circuit breaker to the Any Trip DDB. The output contact(s) assigned for tripping the monitored circuit breaker should also be connected to the fault record trigger Fault REC
TRIG DDB 672 for fault record triggering.
Where relay 3 or any other contact is used to initiate the Any Trip signal the contact should not be set to latched as the Any Trip is used to trigger (on pick-up) and reset (on drop-off) the fault recorder window. So if the Any Trip is latched the fault recording window never resets and so you won’t see a fault record on the relay front display as the relay thinks the fault is still present.
The default setting for relay 3 is a dwell time of 100 ms, a dwell is the minimum time the contact will be ON and is used for trip functions to ensure a good quality trip signal is obtained. As an example of a dwell timer, a dwell of 100 ms means that if the initiating signal is ON for 10 ms then the output contact is ON for 100 ms and if the initiating signal is ON for 200 ms then the output contact is ON for 200 ms.
Read Only Mode
With IEC 61850 and Ethernet/Internet communication capabilities, security has become a pressing issue. The Px40 relay provides a facility to allow the user to enable or disable the change in configuration remotely. This feature is available only in relays with Courier,
Courier with IEC 60870-5-103, Courier with IEC 61850 and IEC 61850 protocol options. It has to be noted that in IEC 60870-5-103 protocol, Read Only Mode function is different from the existing Command block feature.
Read only mode can be enabled/disabled for these rear ports:
Rear Port 1 – IEC 60870-5-103 and Courier protocols
Rear Port 2 (if fitted) - Courier protocol
Ethernet Port (if fitted) - Courier protocol (“tunneled”)
P341/EN OP/G74 Page (OP) 5-77
(OP) 5 Operation
Notes:
Operation of Non-Protection Functions
Page (OP) 5-78 P341/EN OP/G74
MiCOM P341 (AP) 6 Application Notes
P341/EN AP/G74
APPLICATION NOTES
CHAPTER 6
Page (AP) 6-1
(AP) 6 Application Notes
Hardware Suffix:
Software Version:
Connection Diagrams:
J (P341)
36 and 71 (with DLR)
10P341xx (xx = 01 to 12)
MiCOM P341
Page (AP) 6-2 P341/EN AP/G74
Contents (AP) 6 Application Notes
CONTENTS
Page (AP) 6-
1 Introduction 9
2 Application of Individual Protection Functions 10
Case 1 - Phase Reversal Switches affecting all CTs and VTs
Case 2 - Phase Reversal Switches Affecting CT Only
Rate of Change of Frequency Protection (81R)
Setting Guidelines for df/dt Protection
Voltage Vector Shift Protection (
Δ
θ
Setting Guidelines for Voltage Vector Shift Protection
Setting Guidelines for the Reconnect Delay
Reverse Power/Overpower/Low Forward Power (32R/32O/32L)
Low Forward Power Protection Function
Low Forward Power Setting Guideline
Reverse Power Protection Function
Reverse Power Setting Guideline
Overcurrent Protection (50/51)
Transformer Magnetising Inrush
Application of Timer Hold Facility
Setting Guidelines for Overcurrent Protection
Directional Overcurrent Protection
Negative Phase Sequence (NPS) Overcurrent Protection (46)
Setting Guidelines for NPS Overcurrent Protection
Directionalizing the Negative Phase Sequence Overcurrent Element
Earth Fault Protection (50N/51N)
Sensitive Earth Fault (SEF) Protection Element
Directional Earth Fault (DEF) Protection (67N)
General Setting Guidelines for DEF
Application to Insulated Systems
Setting Guidelines - Insulated Systems
P341/EN AP/G74 Page (AP) 6-3
(AP) 6 Application Notes Contents
Application to Petersen Coil Earthed Systems
Applications to Compensated Networks
Required Relay Current and Voltage Connections
Calculation of Required Relay Settings
Restricted Earth Fault Protection (64)
Setting Guidelines for High Impedance REF Protection
Residual Overvoltage/Neutral Voltage Displacement Protection (59N)
Setting Guidelines for Residual Overvoltage/Neutral Voltage Displacement Protection51
Undervoltage Protection (27) 52
Setting Guidelines for Undervoltage Protection 52
Setting Guidelines for Overvoltage Protection
Negative Phase Sequence (NPS) Overvoltage Protection (47)
Underfrequency Protection (81U)
Setting Guidelines for Underfrequency Protection
Overfrequency Protection Function (81O)
Setting Guidelines for Overfrequency Protection
Thermal Overload Protection (49)
Circuit Breaker Fail (CBF) Protection (50BF)
Reset Mechanisms for Breaker Fail Timers
Breaker Fail Undercurrent Settings
Blocked Overcurrent Protection
Current Loop Inputs and Outputs
Setting Guidelines for Current Loop Inputs
Setting Guidelines for Current Loop Outputs
Dynamic Line Rating (DLR) Protection (49DLR)
Dynamic Line Rating (DLR) Method (49 DLR)
Example of Ampacity as a Function of Wind and Ambient Temperature
3 Application of Non-Protection Functions
Voltage and Phase Angle Correction
80
Page (AP) 6-4 P341/EN AP/G74
Contents (AP) 6 Application Notes
Setting the VT Supervision Element
Setting the Differential CTS Element
Circuit Breaker Condition Monitoring
Setting the Number of Operations Thresholds
Setting the Operating Time Thresholds
Setting the Excessive Fault Frequency Thresholds
Trip Circuit Supervision (TCS)
Open Delta (Vee-Connected) VTs
4 Current Transformer Requirements
97
Non-Directional Definite Time/IDMT Overcurrent & Earth Fault Protection97
Time-Delayed Phase Overcurrent Elements
Time-Delayed Earth Fault Overcurrent Elements
Non-Directional Instantaneous Overcurrent & Earth Fault Protection 97
CT Requirements for Instantaneous Phase Overcurrent Elements
CT Requirements for Instantaneous Earth Fault Overcurrent Elements
Directional Definite Time/IDMT Overcurrent & Earth Fault Protection 98
Time-Delayed Phase Overcurrent Elements 98
Time-Delayed Earth Fault Overcurrent Elements
Directional Instantaneous Overcurrent & Earth Fault Protection
CT Requirements for Instantaneous Phase Overcurrent Elements
CT Requirements for Instantaneous Earth Fault Overcurrent Elements
Non-Directional/Directional Definite Time/IDMT Sensitive Earth Fault (SEF)
Non-Directional Time Delayed SEF Protection (Residually Connected)
Non-Directional Instantaneous SEF Protection (Residually Connected)
Directional Time Delayed SEF Protection (Residually Connected)
P341/EN AP/G74 Page (AP) 6-5
(AP) 6 Application Notes Figures
Directional Instantaneous SEF Protection (Residually Connected)
SEF Protection - as fed from a Core-Balance CT
High Impedance Restricted Earth Fault Protection
Reverse and Low Forward Power Protection Functions
Protection Class Current Transformers
Metering Class Current Transformers
Converting an IEC185 Current Transformer Standard Protection
Classification to a Kneepoint Voltage
Converting IEC185 Current Transformer Standard Protection
Classification to an ANSI/IEEE Standard Voltage Rating
5 AUXILIARY SUPPLY FUSE RATING
FIGURES
Page (AP) 6-
Figure 1 - Phase reversal - case 1
Figure 2 - Standard and reverse phase rotation
Figure 3 - Phase reversal - case 2
Figure 4 - Rate of change of frequency protection
Figure 5 - Typical system with embedded generation
Figure 6 - Vector diagram representing steady state condition
Figure 7 - Single phase line diagram showing generator parameters
Figure 8 - Transient voltage vector change due to change in load current IL 18
Figure 9 - Typical distribution system using parallel transformers 27
Figure 10 - Typical ring main with associated overcurrent protection 28
Figure 11 - Positioning of core balance current transformers
Figure 12 - Current distribution in an insulated system with C phase fault
Figure 13 - Phasor diagrams for insulated system with C phase fault
Figure 14 - Current distribution in Peterson Coil earthed system
Figure 15 - Distribution of currents during a C phase to earth fault
Figure 16 - Theoretical case - no resistance present in XL or Xc
Figure 17 - Zero sequence network showing residual currents
Figure 18 - Practical case: resistance present in XL and Xc
Figure 19 - Residual voltage, solidly earthed system
Figure 20 - Residual voltage, resistance earthed system
Figure 21 - Coordination of underfrequency protection function with system load shedding 58
Figure 22 - Simple busbar blocking scheme (single incomer)
Figure 23 - Simple busbar blocking scheme (single incomer)
Figure 24 - Comparison of ambient temperature vs ampacity for IEEE and CIGRE standards 71
103
Page (AP) 6-6 P341/EN AP/G74
Tables (AP) 6 Application Notes
Figure 25 - Comparison of wind velocity vs ampacity for IEEE and CIGRE standards72
Figure 26 - Comparison of wind angle vs ampacity for IEEE and CIGRE standards 73
Figure 27 - Comparison of solar radiation vs ampacity for IEEE and CIGRE standards 74
Figure 30 - Typical connection between system and generator-transformer unit 80
Figure 31 - Typical connection between system and generator-transformer unit
Figure 32 - Transformer vector diagram
Figure 33 - Check synch. 2 phase angle diagram
Figure 34 - Check synch. 2 functional diagram
Figure 35 - Freq/Volt control functional diagram
Figure 37 - PSL for TCS schemes 1 and 3
Figure 39 - PSL for TCS scheme 2
TABLES
Page (AP) 6-
Table 1 - Consequences of loss of prime mover
Table 2 - Recommended Metrosil types for 1 A CTs
Table 3 - Recommended Metrosil types for 5 A CTs
Table 4 - CB fail typical timer settings
Table 5 - ER P27 recommended current ratings for LYNX conductor 75
Table 6 - CIGRE calculated current ratings to match ER P27 for LYNX conductor 76
Table 7 - Resistor values for TCS scheme 1
Table 8 - Resistor values for TCS scheme 2
Table 10 - Sensitive power current transformer requirements
Table 11 - Maximum number of Px40 relays recommended per fuse
P341/EN AP/G74 Page (AP) 6-7
(AP) 6 Application Notes
Notes:
Tables
Page (AP) 6-8 P341/EN AP/G74
Introduction (AP) 6 Application Notes
1 INTRODUCTION
1.1 Interconnection Protection
Small-scale generators can be found in a wide range of situations. These may be used to provide emergency power in the event of loss of the main supply. Alternatively the generation of electrical power may be a by-product of a heat/steam generation process.
Where such embedded generation capacity exists it can be economic to run the machines in parallel with the local Public Electricity Suppliers (PES) network. This can reduce a sites overall power demand or peak load. Additionally, excess generation may be exported and sold to the local PES. If parallel operation is possible great care must be taken to ensure that the embedded generation does not cause any dangerous conditions to exist on the local PES network.
PES networks have in general been designed for operation where the generation is supplied from central sources down into the network. Generated voltages and frequency are closely monitored to ensure that values at the point of supply are within statutory limits. Tap changers and tap changer control schemes are optimized to ensure that supply voltages remain within these limits. Embedded generation can affect the normal flow of active and reactive power on the network leading to unusually high or low voltages being produced and may also lead to excessive fault current that could exceed the rating of the installed distribution switchgear/cables.
It may also be possible for the embedded generators to become disconnected from the main source of supply but be able to supply local load on the PES network. Such islanded operation must be avoided for several reasons
To ensure that unearthed operation of the PES network is avoided
To ensure that automatic reclosure of system circuit breakers will not result in connecting unsynchronized supplies causing damage to the generators
To ensure that system operations staff cannot attempt unsynchronized manual closure of an open circuit breaker.
To ensure that there is no chance of faults on the PES system being undetectable due to the low fault supplying capability of the embedded generator
To ensure that the voltage and frequency supplied to PES customers remains within statutory limits
Before granting permission for the generation to be connected to their system the PES must be satisfied that no danger will result. The type and extent of protection required at the interconnection point between PES system and embedded generation will need to be analyzed.
The P341 relay has been designed to provide a wide range of protection functions required to prevent dangerous conditions that could be present when embedded generators provide power to local power supply networks when the main connection with the Electricity Supply system is lost.
The relay also includes a comprehensive range of non-protection features to aid with power system diagnosis and fault analysis. All these features can be accessed remotely from one of the relay’s remote serial communications options.
P341/EN AP/G74 Page (AP) 6-9
(AP) 6 Application Notes
2
2.1
2.1.1
2.1.1.1
Application of Individual Protection Functions
APPLICATION OF INDIVIDUAL PROTECTION FUNCTIONS
The following sections detail the individual protection functions in addition to where and how they may be applied. Each section also gives setting guidelines for each protection function.
Phase Rotation
Description
A facility is provided in the P341 to maintain correct operation of all the protection functions even when the generator is running in a reverse phase sequence. This is achieved through user configurable settings available for the four setting groups.
The default phase sequence for P341 is the clockwise rotation ABC. Some power systems may have a permanent anti-clockwise phase rotation of ACB.
In pump storage applications there is also a common practice to reverse two phases to facilitate the pumping operation, using phase reversal switches. However, depending on the position of the switches with respect to the VTs and CTs, the phase rotation may not affect all the voltage and current inputs to the relay. The following sections describe some common scenarios and their effects. In the description, CT1 provides current measurements for all the current based protection.
For pump storage applications the correct phase rotation settings can be applied for a specific operating mode and phase configuration in different setting groups. The phase configuration can then be set by selecting the appropriate setting group, see the
Operation chapter for more information of changing setting groups. This method of selecting the phase configuration removes the need for external switching of CT circuits or the duplication of relays with connections to different CT phases. The phase rotation settings should only be changed when the machine is off-line so that transient differences in the phase rotation between the relay and power system due to the switching of phases don’t cause operation of any of the protection functions. To ensure that setting groups are only changed when the machine is off-line the changing of the setting groups could be interlocked with the IA/IB/IC undercurrent start signals and an undervoltage start signal in the PSL.
Case 1 - Phase Reversal Switches affecting all CTs and VTs
The phase reversal affects all the voltage and current measurements in the same way, irrespective of which two phases are being swapped. This is also equivalent to a power system that is permanently reverse phase reversed.
Page (AP) 6-10
Figure 1 - Phase reversal - case 1
All the protection functions that use the positive and negative sequence component of voltage and current will be affected (NPS overcurrent and NPS overvoltage, thermal
P341/EN AP/G74
Application of Individual Protection Functions (AP) 6 Application Notes overload, voltage transformer supervision). Directional overcurrent is also affected as the polarizing signal (Vbc, Vca, Vab) is reversed by the change in phase rotation.
The relationship between voltages and currents from CT for the standard phase rotation
and reverse phase rotation is shown in Figure 2.
2.1.1.2
Figure 2 - Standard and reverse phase rotation
In the above example, the System Config settings - Standard ABC and Reverse ACB can be used in two of the Setting Groups to affect the phase rotation depending on the position of the phase reversal switch.
Case 2 - Phase Reversal Switches Affecting CT Only
The phase reversal affects CT1 only. All the protection functions that use CT1 currents and the 3 phase voltages (power, directional overcurrent) will be affected, since the reversal changes the phase relationship between the voltages and currents. The protection that use positive and negative sequence current and voltage will also be affected.
P341/EN AP/G74
Figure 3 - Phase reversal - case 2
Note There are 2 approaches to using the System Config settings where 2 phases are swapped. The settings can be used to maintain a generator view of the phase sequence or a system (or busbar) view of the phase sequence for a generator fault.
For example, in Case 2, for a generator A-phase winding fault, the relay will report a B phase fault if the CT1 Reversal setting is set to A-B Swapped (system or busbar view of faulted phase). For a busbar fault the correct faulted phase will be given in the fault record.
So, to obtain a phase sequence maintaining a generator viewpoint for a generator fault the CTs/VTs not affected by the change must have the phase swapping setting to match the external switching. Also, since the machine’s sequence rotation has been affected, the Phase Sequence - Reverse ACB setting will also need to be applied accordingly.
Page (AP) 6-11
(AP) 6 Application Notes
2.2
2.2.1
Application of Individual Protection Functions
To obtain a phase sequence maintaining a system viewpoint for a generator fault the
CTs/VTs affected by the change must have the phase swapping setting to match the external switching.
The Sensitive Power is a single phase power element using A phase current usually from a separate metering class CT and A phase voltage. If Sensitive Power is applied and the
A phase current only has been swapped, the power calculation will be wrong since the voltage and current inputs are not from the same phase. If for example in Case 2 the A-B phases are swapped and the sensitive CT is on the generator side of the switch. It is possible to use the approach where the VT phases are swapped so that the A-phase voltage (from generator’s view point) is restored for the correct calculation of the A-phase power. The sensitive current input is a single phase current input in the relay and so it’s phase rotation can not be swapped to match the voltage inputs on the busbar in this application.
Rate of Change of Frequency Protection (81R)
The two main applications for df/dt protection are network decoupling (loss of mains/loss of grid) and load shedding.
Load Shedding
Generated and required active power need to be well balanced in any industrial, distribution or transmission network. As load increases, the generation needs to be stepped up to maintain frequency of the supply because there are many frequency sensitive electrical apparatus that can be damaged when network frequency departs from the allowed band for safe operation. At times, when sudden overloads occur, the frequency drops at a rate decided by the system inertia constant, magnitude of overload, system damping constant and various other parameters. Unless corrective measures are taken at the appropriate time, frequency decay can go beyond the point of no return and cause widespread network collapse. In a wider scenario, this can result in “Blackouts”.
To put the network back into a healthy condition, a considerable amount of time and effort is required to re-synchronize and re-energize.
Protective relays that can detect a low frequency condition are generally used in such cases to disconnect unimportant loads in order to save the network, by re-establishing the “generation-load equation”. However, with such devices, the action is initiated only after the event and while some salvaging of the situation can be achieved, this form of corrective action may not be effective enough and cannot cope with sudden load increases, causing large frequency decays in very short times. In such cases a device that can anticipate the severity of frequency decay and act to disconnect loads before the frequency actually reaches dangerously low levels, can become very effective in containing damage.
During severe disturbances, the frequency of the system oscillates as various generators try to synchronize on to a common frequency. The frequency decay needs to be monitored over a longer period of time and time delayed df/dt can be used to make the correct decision for load shedding or provide early warning to the operator on a developing frequency problem. Additionally, the element could also be used as an alarm to warn operators of unusually high system frequency variations.
In the load shedding scheme below, it is assumed under falling frequency conditions that by shedding a stage of load, the system can be stabilized at frequency f2. For slow rates of decay, this can be achieved using the underfrequency protection element set at frequency f1 with a suitable time delay. However, if the generation deficit is substantial, the frequency will rapidly decrease and it is possible that the time delay imposed by the underfrequency protection will not allow for frequency stabilization. In this case, the chance of system recovery will be enhanced by disconnecting the load stage based upon a measurement of rate of change of frequency and bypassing the time delay.
Page (AP) 6-12 P341/EN AP/G74
Application of Individual Protection Functions (AP) 6 Application Notes
A time delayed rate of change of frequency monitoring element that operates independently from the under and overfrequency protection functions could be used to provide extra flexibility to a load shedding scheme in dealing with such a severe load to generation imbalance. A more secure load shedding scheme could be implemented using f + df/ft by supervising the df/dt element with under frequency elements.
2.2.2
Figure 4 - Rate of change of frequency protection
Loss of Mains Protection
If the capacity of an embedded generator exceeds the locally connected load it is conceivable that it could supply the local load in island mode. Fault clearance may disconnect part of the public supply system from the main source of supply resulting in the embedded generation feeding the local loads, i.e. a ‘Loss of Mains’ or ‘Loss of Grid’
An even more serious problem presents itself if manual operation of distribution switchgear is considered. System Operation staff may operate circuit breakers by hand.
In these circumstances it is essential that unsynchronized reclosure is prevented as this could have very serious consequences for the operator, particularly if the switchgear is not designed, or rated, to be operated when switching onto a fault. To protect personnel, the embedded machine must be disconnected from the system as soon as the system connection is broken, this will ensure that manual unsynchronized closure is prevented.
P341/EN AP/G74 Page (AP) 6-13
(AP) 6 Application Notes Application of Individual Protection Functions
Page (AP) 6-14
Figure 5 - Typical system with embedded generation
Where the embedded generator does not export power under normal conditions it may be possible to use directional power or directional overcurrent protection relays to detect the export of power under loss of mains conditions. If export of power into the system is allowed it may not be possible to set directional relays using settings sensitive enough to detect the loss of the mains connection. In such circumstances a rate of change of frequency protection can be applied. This detects the slight variation in generator speed that occurs when the main supply connection is disconnected and the generator experiences a step change in load.
The type of protection required to detect Loss of Mains conditions will depend on a number of factors, e.g. the generator rating, size of local load, ability to export power, and configuration of supply network etc. Protection requirements should be discussed and agreed with the local Public Electricity Supplier before permission to connect the embedded generator in parallel with the system is granted.
A number of protection elements that may be sensitive to the Loss of Mains conditions are offered in the P341 relay; rate of change of frequency, voltage vector shift, overpower protection, directional overcurrent protection, frequency protection, voltage protection.
Application of each of these elements is discussed in more detail in the following sections.
When a machine is running in parallel with the main power supply the frequency and hence speed of the machine will be governed by the grid supply. When the connection with the grid is lost, the islanded machine is free to slow down or speed up as determined by the new load conditions, machine rating and governor response. Where there is a significant change in load conditions between the synchronized and islanded condition the machine will speed up or slow down before the governor can respond.
The rate of change of speed, or frequency, following a power disturbance can be approximated by: df/ dt =
P.f
2GH
Where
P = Change in power output between synchronized and islanded operation f = Rated
G =
H =
Machine rating in MVA
Inertia constant
This simple expression assumes that the machine is running at rated frequency and that the time intervals are short enough that AVR and governor dynamics can be ignored.
P341/EN AP/G74
Application of Individual Protection Functions
2.2.3
(AP) 6 Application Notes
From this equation it is clear that the rate of change of frequency is directly proportional to the change in power output between two conditions. Provided there is a small change in load between the synchronized and islanded (loss of mains) condition the rate of change of frequency as the machine adjusts to the new load conditions can be detectable. The change in speed of the machine is also proportional to the inertia constant and rating of the machine and so will be application dependent.
Care must be taken in applying this type of protection as the prime consideration is detecting the loss of grid connection. Failure to detect this condition may result in unsynchronized re-connection via remote re-closing equipment. However, if too sensitive a setting is chosen there is a risk of nuisance tripping due to frequency fluctuations caused by normal heavy load switching or fault clearance. Guidance can be given for setting a rate of change of frequency element but these settings must be thoroughly tested on site to prove their accuracy for a given machine and load.
The element also allows the user to set a frequency band within which the element is blocked. This provides additional stability for non loss of grid disturbances which do not affect the machine frequency significantly.
Setting Guidelines for df/dt Protection
There are some global df/dt settings that affect all protection stages that can be used to smooth out the frequency measurements and provide stable operation of the protection, df/dt avg cycles and df/dt iterations . These settings enable the user to select the number of cycles the frequency is averaged over and the number of iterations of the averaged cycles before a start is given. Two Operating Mode settings are provided:
Fixed Window and Rolling Window . The Fixed Window setting is mainly provided for compatibility with the previous P341 df/dt function which used two consecutive calculations of a 3 cycle fixed window to initiate a start.
The previous software version P341 df/dt element calculated the rate of change of frequency every 3 cycles by calculating the frequency difference over the 3-cycle period as shown below. df/ dt = fn - fn-3cycle
3cycle
Two consecutive calculations must give a result above the setting threshold before a trip decision can be initiated.
For loss of grid applications it is recommended that df/dt avg cycles = 3 and df/dt iterations = 2 and the Operating Mode = Fixed Window as per the original P341 algorithm.
For load shedding applications the df/dt avg cycles and df/dt iterations and the
Operating Mode , Fixed Window/Rolling Window will depend on the operating time and stability requirements. The df/dt measurement will provide more stability to power system oscillations when the number of iterations and averaging cycles is high but this will make the function slower. Typical settings for load shedding applications are df/dt avg cycles =
5, df/dt iterations = 1 and the Operating Mode = Rolling Window . For load shedding applications with low df/dt settings < 0.5 Hz/s higher settings for the averaging cycles and iterations should be considered to provide better stability.
The df/dt feature is available only when the df/dt option is enabled in the
CONFIGURATION menu. All four stages may be enabled/disabled by the df/dt>n
Status cell depending on which element is selected.
Each stage has a direction setting df/dt>n Dir’n - Negative , Positive , Both . This setting determines whether the element will react to rising or falling frequency conditions respectively, with an incorrect setting being indicated if the threshold is set to zero. For
P341/EN AP/G74 Page (AP) 6-15
(AP) 6 Application Notes Application of Individual Protection Functions loss of mains applications the df/dt>1 Dir’n should be set to Both to match the previous
P341 algorithm.
A sudden disconnection of loads leads to a surplus of active power. The frequency rises and causes a positive frequency change. A failure of generators, on the other hand, leads to a deficit of active power. The frequency drops and leads to a negative frequency change. For load shedding applications the df/dt>1 Dir’n is typically set to Negative for falling frequencies.
For loss of mains applications the df/dt>1 setting threshold should be set such that the loss of mains condition can be detected; this can be determined by system switching during initial commissioning. A typical setting for df/dt>1 Setting is 0.2 to 0.6 Hz/s. For df/dt>1 only, the user can select a deadband around the nominal frequency, within which this element is blocked. The dead band is defined with high and low frequency settings df/dt>1 f Low and df/dt> f High . The deadband is eliminated if the high and low frequencies are set the same or the df/dt> f L/H setting is set to Disabled . The deadband provides additional stability for non loss of grid disturbances which do not affect the machine frequency significantly.
System simulation testing has shown that the following settings can provide stable operation for external faults, and load switching events, whilst operating for a loss of mains event which causes a 10% change in the machine output, for a typical 4 MW machine. These can be used as a guide but will by no means be acceptable in all applications. Machine rating, governor response, local load and system load, will all affect the dynamic response of a machine to a loss of mains event. df/dt>1 Setting 0.2 Hz/s df/dt Time Delay df/dt>1 f High df/dt>1 f Low df/dt>1 Dir’n
0.5 s
50.5 Hz
49.5 Hz
Both
Once installed, the settings should be periodically reviewed to ensure that they are adequate to detect a loss of grid connection event, but not too sensitive such that unwanted tripping occurs during normal fault clearance, or load switching, that does not lead to the loss of mains condition. Safety of personnel is paramount and this should be kept in mind when optimizing settings; non-synchronized manual operation of circuit breakers must be prevented by disconnection of the embedded machine when the system becomes separated.
For load shedding the df/dt>n setting value depends on the application and is determined by power system conditions. In most cases, a network analysis will be necessary. The under/overfrequency start DDBs can be used to supervise the df/dt elements using the df/dt>1/2/3/4 Tmr Blk DDBs, if required to provide a more secure load shedding scheme.
The following can be used as an example for estimation of the df/dt settings. This applies for the change rate at the beginning of a frequency change (approx. 1 second). df/ dt =
P.f
2GH
For hydro-electric generators (salient-pole machines) H = 1.5 s to 6 s
For turbine-driven generators (cylindrical-rotor machines) H = 2 s to 10 s
For industrial turbine-generators H = 3 s to 4 s f = nominal frequency
H = 3 s
Page (AP) 6-16 P341/EN AP/G74
Application of Individual Protection Functions
2.3
(AP) 6 Application Notes
Case 1: Δ P/G = 0.12
Case 1: Δ P/G = 0.48
Case 1: df/dt = -1 Hz/s
Case 2: df/dt = -4 Hz/s
The time delay setting, df/dt>n Time Delay , can be used to provide a degree of stability against normal load switching events which will cause a change in the frequency before governor correction.
Voltage Vector Shift Protection (
Δ
V
θ
)
The P341 has a single stage Voltage Vector Shift protection element. This element measures the change in voltage angle over successive power system half-cycles. The element operates by measuring the time between zero crossings on the voltage waveforms. A measurement is taken every half cycle for each phase voltage. Over a power system cycle this produces 6 results, a trip is issued if 5 of the 6 calculations for the last power system cycle are above the set threshold. Checking all three phases makes the element less susceptible to incorrect operation due to harmonic distortion or interference in the measured voltage waveform.
An expression for a sinusoidal mains voltage waveform is generally given by the following:
V
Where
= Vp sin (wt) or V = Vp sin (t)
(t) = wt = 2 ft
If the frequency is changing at constant rate Rf from a frequency fo then the variation in the angle (t) is given by:
(t) = 2 f dt, which gives
(t) = 2 (f o
t + t R f
t/2), and
V = V sin {2 (f o
+ t R f
/2)t}
Hence the angle change (t) after time t is given by:
(t) = R f
t 2 ,
Therefore the phase of the voltage with respect to a fixed frequency reference when subject to a constant rate of change of frequency changes in proportion to t conditions can be assumed as changing linearly with time.
2
. This is a characteristic difference from a rate of change of frequency function, which in most
A rate of change of frequency of 10 Hz/s results in an angular voltage vector shift of only
0.72 degrees in the first cycle after the disturbance. This is too small to be detected by vector shift relays. In fact a typical setting for a voltage vector shift relay is, normally between 6 and 13 degrees. Therefore a voltage vector shift relay is not sensitive to the change in voltage phase brought about by change of frequency alone.
To understand the relation between the resulting voltage vector angle change following a disturbance and the embedded generator characteristics a simplified single phase
equivalent circuit of a synchronous generator or induction generator is shown in Figure 6,
P341/EN AP/G74 Page (AP) 6-17
(AP) 6 Application Notes Application of Individual Protection Functions
Figure 6 - Vector diagram representing steady state condition
Figure 7 - Single phase line diagram showing generator parameters
Page (AP) 6-18
Figure 8 - Transient voltage vector change due to change in load current IL
The voltage vector shift function is designed to respond within one to two full mains cycles when its threshold is exceeded. Discrimination between a loss of mains condition and a circuit fault is therefore achievable only by selecting the angle threshold to be above expected fault levels. This setting can be quantified by calculating the angular change due to islanding. However this angular change depends on system topology, power flows and very often also on the instant of the system faults. For example a bolted three phase short circuit which occurs close to the relay may cause a problem in that it inherently produces a vector shift angle at the instant of the fault which is bigger than any normal setting, independent of the mains condition. This kind of fault would cause the relay to trip shortly after the instant of its inception. Although this may seem to be a disadvantage of the vector shift function, isolating the embedded generator at the instant of a bolted three phase fault is of advantage to the PES. This is because the mains short circuit capacity and consequently the energy feeding the short circuit is limited by the instant operation of the relay. The fast operation of this vector shift function renders it to operate at the instant of a disturbance rather than during a gradual change caused by a gradual change of power flow. Operation can occur at the instant of inception of the fault, at fault clearance or following non-synchronized reclosure, which affords additional protection to the embedded generator.
P341/EN AP/G74
Application of Individual Protection Functions
2.3.1
2.4
2.4.1
(AP) 6 Application Notes
Setting Guidelines for Voltage Vector Shift Protection
The element can be selected by setting the V Shift Status cell to Enabled .
The angle change setting threshold, V Shift Angle , should be set to the desired level.
The setting threshold should be set such that the loss of mains condition can be detected, this can be determined by system switching during initial commissioning. System simulation testing has shown that a V Shift Angle setting of 10º can provide stable operation for external faults, and load switching events, whilst operating for a loss of mains event which causes a 10% change in the machine output for a typical 4 MW machine. Although in some circumstances, this setting may prove to be too sensitive, it is recommended to achieve a successful loss of mains trip in as many cases as possible.
Although the vector shift function may trip the relay due to a bolted 3 phase fault, it is also essential in securing a trip at the instant of an out-of-phase auto-reclose, where the df/dt function does not trip.
This setting should be used as a guide but will by no means be acceptable in all applications. Machine rating, governor response, local load and system load, will all affect the dynamic response of a machine to a loss of mains event. Once installed the settings should be periodically reviewed to ensure that they are adequate to detect a loss of grid connection event, but not too sensitive such that unwanted tripping occurs during normal fault clearance that does not lead to the loss of mains condition. Safety of personnel is paramount and this should be kept in mind when optimizing settings; nonsynchronized manual operation of circuit breakers must be prevented by disconnection of the embedded machine when the system becomes separated.
Reconnection Timer (79)
Due to the sensitivity of the settings applied to the df/dt and/or the Voltage Vector Shift element, false operation for non loss of mains events may occur. This could, for example, be due to a close up three phase fault which can cause operation of a Voltage
Vector Shift element. Such operations will lead to the disconnection of the embedded machine from the external network and prevent export of power. Alternatively the loss of mains protections may operate correctly, and auto re-closure equipment may restore the grid supply following a transient fault.
Disconnection of an embedded generator could lead to a simple loss of revenue. Or in cases where the licensing arrangement demands export of power at times of peak load may lead to penalty charges being imposed. To minimize the disruption caused, the
P341 includes a reconnection timer. This timer is initiated following operation of any protection element that could operate due to a loss of mains event, i.e. df/dt, voltage vector shift, under/overfrequency, power and under/over voltage. The timer is blocked should a short circuit fault protection element operate, i.e. residual overvoltage, overcurrent, and earth fault. Once the timer delay has expired the element will provide a pulsed output signal. This signal can be used to initiate external synchronizing equipment that can re-synchronies the machine with the system and reclose the CB.
Setting Guidelines for the Reconnect Delay
The element can be selected by setting the Reconnect Status cell to Enabled .
The timer setting, Reconnect Delay , should be set to the desired delay, this would typically be longer than the dead time of system auto reclose equipment to ensure that re-synchronization is only attempted after the system has been returned to a normal state. The signal pulse time, Reconnect tPULSE should be set such that the output pulse is sufficient to securely initiate the auto synchronizing equipment when required.
P341/EN AP/G74 Page (AP) 6-19
(AP) 6 Application Notes
2.5
2.5.1
Application of Individual Protection Functions
Reverse Power/Overpower/Low Forward Power (32R/32O/32L)
Low Forward Power Protection Function
When the machine is generating and the CB connecting the generator to the system is tripped, the electrical load on the generator is cut. This could lead to generator overspeed if the mechanical input power is not reduced quickly. Large turbo-alternators, with low-inertia rotor designs, do not have a high over speed tolerance. Trapped steam in the turbine, downstream of a valve that has just closed, can rapidly lead to over speed. To reduce the risk of over speed damage to such sets, it is sometimes chosen to interlock non-urgent tripping of the generator breaker and the excitation system with a low forward power check. This ensures that the generator set circuit breaker is opened only when the output power is sufficiently low that over speeding is unlikely. The delay in electrical tripping, until prime mover input power has been removed, may be deemed acceptable for ‘non-urgent’ protection trips; e.g. stator earth fault protection for a high impedance earthed generator. For ‘urgent’ trips, e.g. stator current differential protection the low forward power interlock should not be used. With the low probability of ‘urgent’ trips, the risk of over speed and possible consequences must be accepted.
The low forward power protection can be arranged to interlock ‘non-urgent’ protection tripping using the relay scheme logic. It can also be arranged to provide a contact for external interlocking of manual tripping, if desired.
To prevent unwanted relay alarms and flags, a low forward power protection element can be disabled when the circuit breaker is opened via ‘poledead’ logic.
The low forward power protection can also be used to provide loss of load protection when a machine is motoring. It can be used for example to protect a machine which is pumping from becoming unprimed or to stop a motor in the event of a failure in the mechanical transmission.
A typical application would be for pump storage generators operating in the motoring mode, where there is a need to prevent the machine becoming unprimed which can cause blade and runner cavitation. During motoring conditions, it is typical for the relay to switch to another setting group with the low forward power enabled and correctly set and the protection operating mode set to Motoring.
A low forward power element may also be used to detect a loss of mains or loss of grid condition for applications where the distributed generator is not allowed to export power to the system.
Page (AP) 6-20 P341/EN AP/G74
Application of Individual Protection Functions
2.5.1.1
(AP) 6 Application Notes
Low Forward Power Setting Guideline
Each stage of power protection can be selected to operate as a low forward power stage by selecting the Power1 Function/Sen Power1 Func or Power2 Function/Sen Power 2
Func cell to Low Forward .
When required for interlocking of non-urgent tripping applications, the threshold setting of the low forward power protection function, P<1 Setting/Sen P<1 Setting or P<2
Setting/Sen P<2 Setting , should be less than 50% of the power level that could result in a dangerous over speed transient on loss of electrical loading. The generator set manufacturer should be consulted for a rating for the protected machine. The operating mode should be set to Generating for this application.
When required for loss of load applications, the threshold setting of the low forward power protection function, P<1 Setting/Sen P<1 Setting or P<2 Setting/Sen P<2 Setting , is system dependent, however, it is typically set to 10 - 20% below the minimum load. For example, for a minimum load of 70%Pn, the setting needs to be set at 63% - 56%Pn.
The operating mode should be set to Motoring for this application.
For interlocking non-urgent trip applications the time delay associated with the low forward power protection function, Power1 TimeDelay/Sen Power1 Delay or Power2
TimeDelay/Sen Power2 Delay , could be set to zero. However, some delay is desirable so that permission for a non-urgent electrical trip is not given in the event of power fluctuations arising from sudden steam valve/throttle closure. A typical time delay for this reason is 2 s.
For loss of load applications the pick up time delay, Power1 TimeDelay/Sen Power1
Delay or Power2 TimeDelay/Sen Power2 Delay , is application dependent but is normally set in excess of the time between motor starting and the load being established.
Where rated power can not be reached during starting (for example where the motor is started with no load connected) and the required protection operating time is less than the time for load to be established then it will be necessary to inhibit the power protection during this period. This can be done in the PSL using AND logic and a pulse timer triggered from the motor starting to block the power protection for the required time.
When required for loss of mains or loss of grid applications where the distributed generator is not allowed to export power to the system, the threshold setting of the reverse power protection function, P<1 Setting/Sen P<1 Setting or P<2 Setting/Sen
P<2 Setting , should be set to a sensitive value, typically <2% of the rated power.
The low forward power protection function should be time-delayed to prevent false trips or alarms being given during power system disturbances or following synchronization. A time delay setting, Power1 TimeDelay/Sen Power1 Delay or Power2 TimeDelay/Sen
Power2 Delay of 5 s should be applied typically.
The delay on reset timer, Power1 DO Timer or Power2 DO Timer , would normally be set to zero when selected to operate low forward power elements.
To prevent unwanted relay alarms and flags, a low forward power protection element can be disabled when the circuit breaker is open via ‘poledead’ logic. This is controlled by setting the power protection, inhibit cells, P1 Poledead Inh or P2 Poledead Inh , to
Enabled .
P341/EN AP/G74 Page (AP) 6-21
(AP) 6 Application Notes
2.5.2
Application of Individual Protection Functions
Reverse Power Protection Function
A generator is expected to supply power to the connected system in normal operation. If the generator prime mover fails, a generator that is connected in parallel with another source of electrical supply will begin to ‘motor’. This reversal of power flow due to loss of prime mover can be detected by the reverse power element.
The consequences of generator motoring and the level of power drawn from the power system will be dependent on the type of prime mover. Typical levels of motoring power and possible motoring damage that could occur for various types of generating plant are
Prime mover
Diesel Engine
Motoring power
5% - 25%
Possible damage (percentage rating)
Risk of fire or explosion from unburned fuel
Motoring level depends on compression ratio and cylinder bore stiffness. Rapid disconnection is required to limit power loss and risk of damage.
Gas Turbine
10% - 15% (Split-shaft)
>50% (Single-shaft)
With some gear-driven sets, damage may arise due to reverse torque on gear teeth.
Compressor load on single shaft machines leads to a high motoring power compared to split-shaft machines. Rapid disconnection is required to limit power loss or damage.
Hydraulic Turbines
0.2 - >2% (Blades out of water)
>2.0% (Blades in water)
Blade and runner cavitation may occur with a long period of motoring
Power is low when blades are above tail-race water level. Hydraulic flow detection devices are often the main means of detecting loss of drive. Automatic disconnection is recommended for unattended operation.
Steam Turbines
0.5% - 3% (Condensing sets)
3% - 6% (Non-condensing sets)
Thermal stress damage may be inflicted on low-pressure turbine blades when steam flow is not available to dissipate windage losses.
Damage may occur rapidly with non-condensing sets or when vacuum is lost with condensing sets. Reverse power protection may be used as a secondary method of detection and might only be used to raise an alarm.
Table 1 - Consequences of loss of prime mover
Table 1 shows motor power and possible damage for various types of prime mover.
In some applications, the level of reverse power in the case of prime mover failure may fluctuate. This may be the case for a failed diesel engine. To prevent cyclic initiation and reset of the main trip timer, and consequent failure to trip, an adjustable reset time delay is provided ( Power1 DO Timer/Power2 DO Timer ). This delay would need to be set longer than the period for which the reverse power could fall below the power setting
( P<1 Setting/Sen P<1 Setting ). This setting needs to be taken into account when setting the main trip time delay.
Note A delay on reset in excess of half the period of any system power swings could result in operation of the reverse power protection during swings.
Reverse power protection may also be used to interlock the opening of the generator set circuit breaker for ‘non-urgent’ tripping, as discussed in section 2.18.1. Reverse power interlocks are preferred over low forward power interlocks by some utilities.
A reverse power element may also be used to detect a loss of mains or loss of grid condition for applications where the distributed generator is not allowed to export power to the system.
Page (AP) 6-22 P341/EN AP/G74
Application of Individual Protection Functions
2.5.2.1
2.5.3
2.5.3.1
(AP) 6 Application Notes
Reverse Power Setting Guideline
Each stage of power protection can be selected to operate as a reverse power stage by selecting the Power1 Function/Sen Power1 Func or Power2 Function/Sen Power2
Func cell to Reverse .
The power threshold setting of the reverse power protection, -P>1 Setting/Sen -P>1
Setting or -P>2 Setting/Sen -P>2 Setting , should be less than 50% of the motoring power, typical values for the level of reverse power for generators are given in previous table.
For applications to detect the loss of the prime mover or for applications to provide interlocking of non-urgent trips the reverse power protection operating mode should be set to Generating .
The reverse power protection function should be time-delayed to prevent false trips or alarms being given during power system disturbances or following synchronization.
A time delay setting, Power1 TimeDelay/Sen Power1 Delay or Power2 TimeDelay/Sen
Power2 Delay of 5 s should be applied typically.
The delay on reset timer, Power1 DO Timer or Power2 DO Timer , would normally be set to zero. When settings of greater than zero are used for the reset time delay, the pick up time delay setting may need to be increased to ensure that false tripping does not result in the event of a stable power swinging event.
When required for loss of mains or loss of grid applications where the distributed generator is not allowed to export power to the system, the threshold setting of the reverse power protection function, -P>1 Setting/Sen -P>1 Setting or -P>2 Setting/Sen -
P>2 Setting should be set to a sensitive value, typically <2% of the rated power. The reverse power protection function should be time-delayed, as described above, to prevent false trips or alarms being given during power system disturbances or following synchronization, a typical time delay is 5 s.
Overpower Protection
The overpower protection can be used as overload indication, as a back-up protection for failure of governor and control equipment, and would be set above the maximum power rating of the machine.
Overpower Setting Guideline
Each stage of power protection can be selected to operate as an overpower stage by selecting the Power1 Function/Sen Power1 Func or Power2 Function/Sen Power2
Func cell to Over .
The power threshold setting of the overpower protection, P>1 Setting/Sen P>1 Setting or P>2 Setting/Sen P>2 Setting , should be set greater than the machine full load rated power.
A time delay setting, Power1 TimeDelay/Sen Power1 Delay or Power2 TimeDelay/Sen
Power2 Delay should be applied.
The operating mode should be set to Motoring or Generating depending on the operating mode of the machine.
The delay on reset timer, Power1 DO Timer or Power2 DO Timer , would normally be set to zero.
P341/EN AP/G74 Page (AP) 6-23
(AP) 6 Application Notes
2.6
2.6.1
Application of Individual Protection Functions
Overcurrent Protection (50/51)
Overcurrent relays are the most commonly used protective devices in any industrial or distribution power system. They provide main protection to both feeders and busbars when unit protection is not used. They are also commonly applied to provide back-up protection when unit systems, such as pilot wire schemes, are used.
By a combination of time delays and relay pick-up settings, overcurrent relays may be applied to either feeders or power transformers to provide discriminative phase fault protection (and also earth fault protection if system earth fault levels are sufficiently high).
In such applications, the various overcurrent relays on the system are coordinated with one another such that the relay nearest to the fault operates first. This is referred to as cascade operation because if the relay nearest to the fault does not operate, the next upstream relay will trip in a slightly longer time.
Various methods are available to achieve correct relay co-ordination on a system; by means of time alone, current alone or a combination of both time and current. Grading by means of current is only possible where there is an appreciable difference in fault level between the two relay locations. Grading by time is used by some utilities but can often lead to excessive fault clearance times at or near source substations where the fault level is highest. For these reasons the most commonly applied characteristic in coordinating overcurrent relays is the Inverse Definite Minimum Time (IDMT) type.
There are a few application considerations to make when applying overcurrent relays.
Transformer Magnetising Inrush
When applying overcurrent protection to the HV side of a power transformer, it is usual to apply a high set instantaneous overcurrent element, in addition to the time delayed lowset, to reduce fault clearance times for HV fault conditions. Typically, this will be set to approximately 1.3 times the LV fault level, such that it will only operate for HV faults. A
30% safety margin is sufficient due to the low transient overreach of the third and fourth overcurrent stages. Transient overreach defines the response of a relay to DC components of fault current and is quoted as a percentage. A relay with a low transient overreach will be largely insensitive to a DC offset and may therefore be set more closely to the steady state AC waveform.
The second requirement for this element is that it should remain inoperative during transformer energization, when a large primary current flows for a transient period. In most applications, the requirement to set the relay above the LV fault level will automatically result in settings that will be above the level of magnetizing inrush current.
Due to the nature of operation of the third and fourth overcurrent stages in the P341 relays, it is possible to apply settings corresponding to 35% of the peak inrush current, whilst maintaining stability for the condition.
This is important where low-set instantaneous stages are used to initiate auto-reclose equipment. In such applications, the instantaneous stage should not operate for inrush conditions, which may arise from small teed-off transformer loads for example. However, the setting must also be sensitive enough to provide fast operation under fault conditions.
Where an instantaneous element is required to accompany the time delayed protection, as described above, the third or fourth overcurrent stage of the P341 relay should be used, as they have wider setting ranges.
Page (AP) 6-24 P341/EN AP/G74
Application of Individual Protection Functions (AP) 6 Application Notes
2.6.2
2.6.3
P341/EN AP/G74
Application of Timer Hold Facility
This feature may be useful in certain applications, for example when grading with electromechanical overcurrent relays which have inherent reset time delays. It will also enable the element to become sensitive to a pole slipping condition where the element will cyclically operate as the machine slips successive poles.
Another situation where the timer hold facility may be used to reduce fault clearance times is where intermittent faults may be experienced. An example of this may occur in a plastic insulated cable. In this application it is possible that the fault energy melts and reseals the cable insulation, thereby extinguishing the fault. This process repeats to give a succession of fault current pulses, each of increasing duration with reducing intervals between the pulses, until the fault becomes permanent.
When the reset time of the overcurrent relay is instantaneous the relay will be repeatedly reset and not be able to trip until the fault becomes permanent. By using the timer hold facility the relay will integrate the fault current pulses, thereby reducing fault clearance time.
Setting Guidelines for Overcurrent Protection
The first and second stage of overcurrent protection can be selected by setting I>1/2
Function to any of the inverse or DT settings. The first and second stage is disabled if
I>1/2 Function is set to Disabled .
The first or second stage can provide back-up protection for faults on the generator and the system. As such it should be coordinated with downstream protection to provide discrimination for system faults, setting the current threshold ( I>1/2 Current Set ), and the time delay.
I>1 TMS
I>1 Time Dial
I>1 Time Delay
For IEC curves;
For US/IEEE curves;
For definite time accordingly.
To provide back-up protection for the generator and system, the element must be supplied from CTs connected in the generator neutral. If terminal end CTs are used, the element will provide protection for the system only, unless the generator is connected in parallel to a second source of supply.
The third and fourth stages of overcurrent protection can be enabled by setting
I>3/4 Function to DT , providing a definite time operating characteristic. The third and fourth stages are disabled if I>3/4 Function is set to Disabled . For machine applications where terminal CTs are used, the third or fourth stage can be set as an instantaneous overcurrent protection, providing protection against internal faults on the machine. The current setting of the third or fourth stage, I>3/4 Current Set , could be set to 120% of the maximum fault rating of the generator, typically 8 x full load current. The operating time,
I>3/4 Time Delay , should be set to 0 s to give instantaneous operation. The stage will therefore be stable for external faults where the fault current from the generator will be below the stage current setting. For faults within the machine, the fault current will be supplied from the system and will be above the second stage current setting, resulting in fast clearance of the internal fault.
When applying the overcurrent protection provided in the P341 relay, standard principles should be applied in calculating the necessary current and time settings for coordination.
The setting example detailed below shows a typical setting calculation and describes how the settings are actually applied to the relay.
Assume the following parameters for a relay feeding an LV switchboard:
CT Ratio = 500/1
Full Load Current of circuit = 450 A
Page (AP) 6-25
(AP) 6 Application Notes Application of Individual Protection Functions
Slowest downstream protection = 100 A Fuse
The current setting employed on the P341 relay must account for both the maximum load current and the reset ratio of the relay itself:
I> must be greater than: 450/0.95 = 474 A
The P341 relay allows the current settings to be applied to the relay in either primary or secondary quantities. Programming the Setting Values cell of the CONFIGURATION column to either Primary or Secondary does this. When this cell is set to primary, all phase overcurrent setting values are scaled by the programmed CT ratio. This is found in column 0A of the relay menu, entitled VT & CT RATIOS where cells Phase CT
Primary and Phase CT Sec’y can be programmed with the primary and secondary CT ratings, respectively.
In this example, assuming primary currents are to be used, the ratio should be programmed as 500/1.
The required setting is therefore 0.95 A in terms of secondary current or 475 A in terms of primary.
A suitable time delayed characteristic will now need to be chosen. When coordinating with downstream fuses, the applied relay characteristic should be closely matched to the fuse characteristic. Therefore assuming IDMT coordination is to be used, an Extremely
Inverse (EI) characteristic would normally be chosen. As previously described, this is found under I>1 Function and should therefore be programmed as IEC E Inverse .
Finally, a suitable Time Multiplier Setting (TMS) must be calculated and entered in cell
I>1 TMS .
For more detailed information regarding overcurrent relay coordination, reference should be made to the ‘Protective Relay Application Guide’ - Chapter 9 or ‘Network Protection and Automation Guide’ - Chapter 9. For more detailed information regarding the application of rectifier inverse time/current characteristic, see the P14x Applications Notes chapter, P14x/EN AP .
Page (AP) 6-26 P341/EN AP/G74
Application of Individual Protection Functions
2.7
2.7.1
(AP) 6 Application Notes
Directional Overcurrent Protection
If fault current can flow in both directions through a relay location, it is necessary to add directionality to the overcurrent relays in order to obtain correct coordination. Typical systems that require such protection are parallel feeders (both plain and transformer) and ring main systems, each of which are relatively common in distribution networks.
Two common applications, which require the use of directional relays, are considered in the following sections.
Parallel Feeders
Figure 9 shows a typical distribution system utilizing parallel power transformers. In such an application, a fault at ‘F’ could result in the operation of both R3 and R4 relays and the subsequent loss of supply to the 11 kV busbar. Hence, with this system configuration, it is necessary to apply directional relays at these locations set to “look into” their respective transformers. These relays should coordinate with the non-directional relays, R1 and R2; hence ensuring discriminative relay operation during such fault conditions.
In such an application, relays R3 and R4 may commonly require non-directional overcurrent protection elements to provide protection to the 11 kV busbar, in addition to providing a back-up function to the overcurrent relays on the outgoing feeders (R5).
When applying the P341 relays in the above application, stage 1 of the overcurrent protection of relays R3 and R4 would be set non-directional and time graded with R5, using an appropriate time delay characteristic. Stage 2 could then be set directional, looking back into the transformer, also having a characteristic which provided correct coordination with R1 and R2. IDMT or DT characteristics are selectable for both stages 1 and 2 and directionality of each of the overcurrent stages is set in cell I> Direction .
P341/EN AP/G74
Figure 9 - Typical distribution system using parallel transformers
Note The principles previously outlined for the parallel transformer application are equally applicable for plain feeders which are operating in parallel.
Page (AP) 6-27
(AP) 6 Application Notes
2.7.2
Application of Individual Protection Functions
Ring Main Arrangements
A particularly common arrangement within distribution networks is the ring main circuit.
The primary reason for its use is to maintain supplies to consumers in the event of fault conditions occurring on the interconnecting feeders. A typical ring main with associated overcurrent protection is shown in Figure 10.
Page (AP) 6-28
Figure 10 - Typical ring main with associated overcurrent protection
As with the previously described parallel feeder arrangement, it can be seen that current may flow in either direction through the various relay locations. Therefore directional overcurrent relays are again required in order to provide a discriminative protection system.
The normal grading procedure for overcurrent relays protecting a ring main circuit is to open the ring at the supply point and to grade the relays first clockwise and then anticlockwise. The arrows shown at the various relay locations in Figure 10 depict the direction for forward operation of the respective relays, i.e. in the same way as for parallel feeders; the directional relays are set to look into the feeder that they are protecting.
Figure 10 shows typical relay time settings (if definite time coordination was employed), from which it can be seen that any faults on the interconnectors between stations are cleared discriminatively by the relays at each end of the feeder.
Again, any of the four overcurrent stages may be configured to be directional and coordinated as per the previously outlined grading procedure, noting that IDMT characteristics are only selectable on the first two stages.
P341/EN AP/G74
Application of Individual Protection Functions
2.7.3
2.7.4
(AP) 6 Application Notes
Synchronous Polarization
For a fault condition that occurs close to the relaying point, the faulty phase voltage will reduce to a value close to zero volts. For single or double phase faults, there will always be at least one healthy phase voltage present for polarization of the phase overcurrent elements. For example, a close up A to B fault condition will result in the collapse of the
A and B phase voltages. However, the A and B phase elements are polarized from VBC and VCA respectively. As such a polarizing signal will be present, allowing correct relay operation.
For a close up three phase fault, all three voltages will collapse to zero and no healthy phase voltages will be present. For this reason, the P341 relays include a synchronous polarization feature that stores the pre-fault voltage information and continues to apply it to the DOC elements for a time period of 3.2 seconds. This ensures that either instantaneous or time delayed DOC elements will be allowed to operate, even with a three phase voltage collapse.
Setting Guidelines
The applied current settings for directional overcurrent relays are dependent upon the application in question. In a parallel feeder arrangement, load current is always flowing in the non-operate direction. Hence, the relay current setting may be less than the full load rating of the circuit; typically 50% of In.
The minimum setting that may be applied has to take into account the thermal rating of the relay. Some electro-mechanical directional overcurrent relays have continuous withstand ratings of only twice the applied current setting and hence 50% of rating was the minimum setting that could be applied. With the P341, the continuous current rating is 4 x rated current and so it is possible to apply much more sensitive settings, if required.
However, there are minimum safe current setting constraints to be observed when applying directional overcurrent protection at the receiving-ends of parallel feeders. The minimum safe settings to ensure that there is no possibility of an unwanted trip during clearance of a source fault are as follows for linear system load:
Parallel plain feeders:
Set>50% Prefault load current
Parallel transformer feeders:
Set>87% Prefault load current
When the above setting constraints are infringed, independent-time protection is more likely to issue an unwanted trip during clearance of a source fault than dependent-time protection.
Where the above setting constraints are unavoidably infringed, secure phase fault protection can be provided with relays which have 2-out-of-3 directional protection tripping logic.
A common minimum current setting recommendation (50% relay rated current) would be virtually safe for plain parallel feeder protection as long as the circuit load current does not exceed 100% relay rated current. It would also be safe for parallel transformer feeders, if the system design criterion for two feeders is such that the load on each feeder will never exceed 50% rated current with both feeders in service. For more than two feeders in parallel the 50% relay rated current setting may not be absolutely safe.
In a ring main application, it is possible for load current to flow in either direction through the relaying point. Hence, the current setting must be above the maximum load current, as in a standard non-directional application.
P341/EN AP/G74 Page (AP) 6-29
(AP) 6 Application Notes Application of Individual Protection Functions
The required characteristic angle settings for directional relays will differ depending on the exact application in which they are used. Recommended characteristic angle settings are as follows:
Plain feeders, or applications with an earthing point (zero sequence source) behind the relay location, should utilize a +30º RCA setting.
Transformer feeders, or applications with a zero sequence source in front of the relay location, should utilize a +45º RCA setting.
On the P341 relay, it is possible to set characteristic angles anywhere in the range -95º to
+95º. While it is possible to set the RCA to exactly match the system fault angle, it is recommended that the above guidelines are adhered to, as these settings have been shown to provide satisfactory performance and stability under a wide range of system conditions.
Page (AP) 6-30 P341/EN AP/G74
Application of Individual Protection Functions (AP) 6 Application Notes
2.8
2.8.1
P341/EN AP/G74
Negative Phase Sequence (NPS) Overcurrent Protection (46)
When applying traditional phase overcurrent protection, the overcurrent elements must be set higher than maximum load current, thereby limiting the element’s sensitivity. Most protection schemes also use an earth fault element, which improves sensitivity for earth faults. However, certain faults may arise which can remain undetected by such schemes.
Any unbalanced fault condition will produce negative sequence current of some magnitude. Therefore a negative phase sequence overcurrent element can operate for both phase-phase and phase-earth faults.
The following section describes how negative phase sequence overcurrent protection may be applied in conjunction with standard overcurrent and earth fault protection in order to alleviate some less common application difficulties.
Negative phase sequence overcurrent elements give greater sensitivity to resistive phase to phase faults, where phase overcurrent elements may not operate.
Voltage dependent overcurrent and underimpedance protection is commonly used to provide more sensitive back-up protection for system phase faults on a generator than simple overcurrent protection. However, negative phase sequence overcurrent protection can also be used to provide sensitive back-up protection for phase-phase faults.
Note NPS overcurrent protection will not provide any system back-up protection for three-phase faults.
However, negative sequence current will be present on both sides of the transformer for any fault condition, irrespective of the transformer configuration. Therefore a negative phase sequence overcurrent element may be employed to provide time-delayed back-up protection for any uncleared asymmetrical faults downstream.
In certain applications, residual current may not be detected by an earth fault relay due to the system configuration. For example, an earth fault relay applied on the delta side of a delta-star transformer is unable to detect earth faults on the star side.
For rotating machines a large amount of negative phase sequence current can be a dangerous condition for the machine due to its heating effect on the rotor.
Therefore, a negative phase sequence overcurrent element may be applied to provide back-up protection to the negative phase sequence thermal protection that is normally applied to a rotating machine, see section 2.15 of the P34x Application
Notes chapter, P34x/EN AP .
It may be required to simply alarm for the presence of negative phase sequence currents on the system. Operators may then investigate the cause of the unbalance.
Setting Guidelines for NPS Overcurrent Protection
The current pick-up threshold must be set higher than the negative phase sequence current due to the maximum normal load unbalance on the system. This can be set practically at the commissioning stage, making use of the relay measurement function to display the standing negative phase sequence current, and setting at least 20% above this figure.
Where the negative phase sequence element is required to operate for specific uncleared asymmetric faults, a precise threshold setting would have to be based upon an individual fault analysis for that particular system due to the complexities involved. However, to ensure operation of the protection, the current pick-up setting must be set approximately
20% below the lowest calculated negative phase sequence fault current contribution to a specific remote fault condition.
Page (AP) 6-31
(AP) 6 Application Notes
2.8.2
Application of Individual Protection Functions
Note In practice, if the required fault study information is unavailable, the setting must adhere to the minimum threshold previously outlined, employing a suitable time delay for coordination with downstream devices, this is vital to prevent unnecessary interruption of the supply resulting from inadvertent operation of this element.
As stated above, correct setting of the time delay for this function is vital. It should also be noted that this element is applied primarily to provide back-up protection to other protective devices or to provide an alarm. Hence, in practice, it would be associated with a long time delay if used to provide back-up protection or an alarm. Where the protection is used for back-up protection or as an alarm it must be ensured that the time delay is set greater than the operating time of any other protective device (at minimum fault level) on the system which may respond to unbalanced faults, such as:
Phase overcurrent elements
Earth fault elements
System back-up protection - voltage dependent overcurrent/underimpedance
Broken conductor elements
Negative phase sequence influenced thermal elements
Directionalizing the Negative Phase Sequence Overcurrent Element
To determine if a phase-phase or phase-earth fault is internal or external to the machine directional control of the element should be employed.
Directionality is achieved by comparison of the angle between the inverse of the negative phase sequence voltage (-V2) and the negative phase sequence current (I2). The element may be selected to operate in either the forward or reverse direction. A suitable relay characteristic angle setting ( I2> Char Angle ) is chosen to provide optimum performance. This setting should be set equal to the phase angle of the negative sequence current with respect to the inverted negative sequence voltage (-V2), in order to be at the center of the directional characteristic.
The angle that occurs between V2 and I2 under fault conditions is directly dependent upon the negative sequence source impedance of the system. However, typical settings for the element are as follows:
For a transmission system the RCA should be set equal to -60°.
For a distribution system the RCA should be set equal to -45°.
For the negative phase sequence directional elements to operate, the relay must detect a polarizing voltage above a minimum threshold, I2> V2pol Set . This must be set in excess of any steady state negative phase sequence voltage. This may be determined during the commissioning stage by viewing the negative phase sequence measurements in the relay.
Page (AP) 6-32 P341/EN AP/G74
Application of Individual Protection Functions
2.9
2.9.1
(AP) 6 Application Notes
Earth Fault Protection (50N/51N)
The fact that both earth fault (derived) and sensitive earth fault elements may be enabled in the relay at the same time leads to a number of applications advantages. For example, the parallel transformer application previously shown in Figure 9 requires directional earth fault protection at locations R3 and R4, to provide discriminative protection. However, in order to provide back-up protection for the transformer, busbar and other downstream earth fault devices, StandBy Earth Fault (SBEF) protection is also commonly applied.
This function has traditionally been fulfilled by a separate earth fault relay, fed from a single CT in the transformer earth connection. The earth fault and sensitive earth fault elements of the P341 relay may be used to provide both the Directional Earth Fault (DEF) and SBEF functions, respectively.
Note The sensitive earth fault dynamic range is 0-2 In and so can only be used on resistance earthed systems.
Where a Neutral Earthing Resistor (NER) is used to limit the earth fault level to a particular value, it is possible that an earth fault condition could cause a flashover of the
NER and hence a dramatic increase in the earth fault current. For this reason, it may be appropriate to apply two stage SBEF protection. The first stage should have suitable current and time characteristics which coordinate with downstream earth fault protection.
The second stage may then be set with a higher current setting but with zero time delay; hence providing fast clearance of an earth fault which gives rise to an NER flashover. The remaining two stages are available for customer specific applications.
The previous examples relating to transformer feeders utilize both earth fault and sensitive earth fault elements. In a standard feeder application requiring three-phase overcurrent and earth fault protection, only one of the earth fault elements would need to be applied.
Sensitive Earth Fault (SEF) Protection Element
Sensitive Earth Fault (SEF) would normally be fed from a Core Balance Current
Transformer (CBCT) mounted around the three phases of the feeder cable. However, care must be taken in the positioning of the CT with respect to the earthing of the cable sheath. See Figure 11 below:
P341/EN AP/G74 Page (AP) 6-33
(AP) 6 Application Notes Application of Individual Protection Functions
Cable box
Cable gland/sheath earth connection
Cable gland
SEF
“Incorrect”
SEF
No operation
“Correct”
Operation
SEF
P0112ENa
Figure 11 - Positioning of core balance current transformers
If the cable sheath is terminated at the cable gland and earthed directly at that point, a cable fault (from phase to sheath) will not result in any unbalance current in the core balance CT. Prior to earthing, the connection must be brought back through the CBCT and earthed on the feeder side. This ensures correct relay operation during earth fault conditions.
Page (AP) 6-34 P341/EN AP/G74
Application of Individual Protection Functions
2.10
2.10.1
2.10.2
(AP) 6 Application Notes
Directional Earth Fault (DEF) Protection (67N)
Each of the four stages of standard earth fault protection and SEF protection may be set to be directional if required. Consequently, as with the application of directional overcurrent protection, a voltage supply is required by the relay to provide the necessary polarization.
With the standard earth fault protection element in the P341 relay, two options are available for polarization; Residual Voltage or Negative Sequence.
General Setting Guidelines for DEF
When setting the Relay Characteristic Angle (RCA) for the directional overcurrent element, a positive angle setting was specified. This was due to the fact that the quadrature polarizing voltage lagged the nominal phase current by 90º i.e. the position of the current under fault conditions was leading the polarizing voltage and hence a positive
RCA was required. With DEF, the residual current under fault conditions lies at an angle lagging the polarizing voltage. Hence, negative RCA settings are required for DEF applications. This is set in cell I>Char Angle in the relevant earth fault menu.
The following angle settings are recommended for a residual voltage polarized relay:
Resistance earthed systems 0º
Distribution systems (solidly earthed) -45º
Transmission Systems (solidly earthed) -60º
For negative sequence polarization, the RCA settings must be based on the angle of the
NPS source impedance, much the same as for residual polarizing. Typical settings would be:
Distribution systems -45º
Transmission Systems -60º
Application to Insulated Systems
The advantage gained by running a power system which is insulated from earth is the fact that during a single phase to earth fault condition, no earth fault current is allowed to flow. Consequently, it is possible to maintain power flow on the system even when an earth fault condition is present. However, this advantage is offset by the fact that the resultant steady state and transient overvoltages on the sound phases can be very high.
It is generally the case, therefore, that insulated systems will only be used in low/medium voltage networks where it does not prove too costly to provide the necessary insulation against such overvoltages. Higher system voltages would normally be solidly earthed or earthed via a low impedance.
Operational advantages may be gained by the use of insulated systems. However, it is still vital that detection of the fault is achieved. This is not possible by means of standard current operated earth fault protection. One possibility for fault detection is by means of a residual overvoltage device. This functionality is included within the P341 relays and is
P341/EN AP/G74 Page (AP) 6-35
(AP) 6 Application Notes Application of Individual Protection Functions
I a1
I b1
I R1
-jXc1
I H1
I a2
I b2
I R2
-jXc2
I H2
I a3
I b3
I
H1 +
I
H2 +
I
H3
I
R3
-jXc3
I
R3 =
I
H1 +
I
H2 +
I
H3 –
I
H3
I H3 I H1 + I H2
I R3 = I H1 + I H2
P2035ENa
Figure 12 - Current distribution in an insulated system with C phase fault
Figure 12 shows that the relays on the healthy feeders see the unbalance in the charging currents for their own feeder. The relay on the faulted feeder, however, sees the charging current from the rest of the system (IH1 and IH2 in this case), with its own feeders charging current (IH3) becoming cancelled out. This is shown by the phasor diagrams shown in Figure 13.
Page (AP) 6-36 P341/EN AP/G74
Application of Individual Protection Functions (AP) 6 Application Notes
P341/EN AP/G74
Figure 13 - Phasor diagrams for insulated system with C phase fault
Referring to the phasor diagram, it can be seen that the C phase to earth fault causes the voltages on the healthy phases to rise by a factor of √ 3. The A phase charging current
(Ia1), is then shown to be leading the resultant A phase voltage by 90º. Likewise, the B phase charging current leads the resultant Vb by 90º.
The unbalance current detected by a core balance current transformer on the healthy feeders can be seen to be the vector addition of Ia1 and Ib1, giving a residual current which lies at exactly 90º lagging the polarizing voltage (-3Vo). As the healthy phase voltages have risen by a factor of √ 3, the charging currents on these phases will also be
√ 3 times larger than their steady state values. Therefore the magnitude of residual current, IR1, is equal to 3 x the steady state per phase charging current.
The phasor diagrams indicate that the residual currents on the healthy and faulted feeders, IR1 and IR3 respectively, are in anti-phase. A directional element could therefore be used to provide discriminative earth fault protection.
If the polarizing voltage of this element, equal to -3Vo, is shifted through +90º, the residual current seen by the relay on the faulted feeder will lie within the operate region of the directional characteristic and the current on the healthy feeders will fall within the restrain region.
As previously stated, the required characteristic angle setting for the SEF element when applied to insulated systems, is +90º. This recommended setting corresponds to the relay being connected such that its direction of current flow for operation is from the source busbar towards the feeder, as would be the convention for a relay on an earthed system. However, if the forward direction for operation was set as being from the feeder into the busbar, (which some utilities may standardize on), then a -90(RCA would be required. The correct relay connections to give a defined direction for operation are shown on the relay connection diagram.
Note Discrimination can be provided without the need for directional control. This can only be achieved if it is possible to set the relay in excess of the charging current of the protected feeder and below the charging current for the rest of the system.
Page (AP) 6-37
(AP) 6 Application Notes
2.10.3
2.10.4
Application of Individual Protection Functions
Setting Guidelines - Insulated Systems
As has been previously shown, the residual current detected by the relay on the faulted feeder is equal to the sum of the charging currents flowing from the rest of the system.
Further, the addition of the two healthy phase charging currents on each feeder gives a total charging current which has a magnitude of three times the per phase value.
Therefore, the total unbalance current detected by the relay is equal to three times the per phase charging current of the rest of the system. A typical relay setting may therefore be in the order of 30% of this value, i.e. equal to the per phase charging current of the remaining system. Practically though, the required setting may well be determined on site, where suitable settings can be adopted based upon practically obtained results. The use of the P140 relays’ comprehensive measurement and fault recording facilities may prove useful in this respect.
Application to Petersen Coil Earthed Systems
Power systems are usually earthed in order to limit transient overvoltages during arcing faults and also to assist with detection and clearance of earth faults. Impedance earthing has the advantage of limiting damage incurred by plant during earth fault conditions and also limits the risk of explosive failure of switchgear, which is a danger to personnel. In addition, it limits touch and step potentials at a substation or in the vicinity of an earth fault.
If a high impedance device is used for earthing the system, or the system is unearthed, the earth fault current will be reduced but the steady state and transient overvoltages on the sound phases can be very high. Consequently, it is generally the case that high impedance earthing will only be used in low/medium voltage networks in which it does not prove too costly to provide the necessary insulation against such overvoltages. Higher system voltages would normally be solidly earthed or earthed via a low impedance.
A special case of high impedance earthing via a reactor occurs when the inductive earthing reactance is made equal to the total system capacitive reactance to earth at system frequency. This practice is widely referred to as Petersen (or resonant) Coil
Earthing. With a correctly tuned system, the steady state earth fault current will be zero, so that arcing earth faults become self extinguishing. Such a system can, if designed to do so, be run with one phase earthed for a long period until the cause of the fault is identified and rectified. With the effectiveness of this method being dependent on the correct tuning of the coil reactance to the system capacitive reactance, an expansion of the system at any time would clearly necessitate an adjustment of the coil reactance.
Such adjustment is sometimes automated.
Petersen Coil earthed systems are commonly found in areas where the power system consists mainly of rural overhead lines and can be particularly beneficial in locations which are subject to a high incidence of transient faults. Transient earth faults caused by lightning strikes, for example, can be extinguished by the Petersen Coil without the need for line outages.
Figure 14 shows a source of generation earthed through a Petersen Coil, with an earth fault applied on the A Phase. Under this situation, it can be seen that the A phase shunt capacitance becomes short circuited by the fault. Consequently, the calculations show that if the reactance of the earthing coil is set correctly, the resulting steady state earth fault current will be zero.
Page (AP) 6-38 P341/EN AP/G74
Application of Individual Protection Functions (AP) 6 Application Notes
P341/EN AP/G74
Figure 14 - Current distribution in Peterson Coil earthed system
Prior to actually applying protective relays to provide earth fault protection on systems which are earthed via a Petersen Coil, it is imperative to gain an understanding of the current distributions that occur under fault conditions on such systems. With this knowledge, it is then possible to decide on the type of relay that may be applied, ensuring that it is both set and connected correctly.
Figure 15 shows a radial distribution system having a source which is earthed via a
Petersen Coil. Three outgoing feeders are present, the lower of which has a phase to earth fault applied on the C phase.
Page (AP) 6-39
(AP) 6 Application Notes Application of Individual Protection Functions
Page (AP) 6-40
Figure 15 - Distribution of currents during a C phase to earth fault
Figure 16 (a, b and c) show vector diagrams for the previous system, assuming that it is fully compensated (i.e. coil reactance fully tuned to system capacitance), in addition to assuming a theoretical situation where no resistance is present either in the earthing coil or in the feeder cables.
Referring to the vector diagram illustrated in Figure 16a, it can be seen that the C phase to earth fault causes the voltages on the healthy phases to rise by a factor of 3. The A phase charging currents (Ia1, Ia2 and Ia3), are then shown to be leading the resultant A phase voltage by 90° and likewise for the B phase charging currents with respect to the resultant Vb.
The unbalance current detected by a core balance current transformer on the healthy feeders can be seen to be a simple vector addition of Ia1 and Ib1, giving a residual
current which lies at exactly 90° lagging the residual voltage (Figure 16b). Clearly, as the
healthy phase voltages have risen by a factor of 3, the charging currents on these phases will also be 3 times larger than their steady state values. Therefore, the magnitude of residual current, IR1, is equal to 3 x the steady state per phase charging current.
P341/EN AP/G74
Application of Individual Protection Functions (AP) 6 Application Notes
Figure 16 - Theoretical case - no resistance present in XL or Xc
Note The actual residual voltage used as a reference signal for directional earth fault relays is phase shifted by 180° and is therefore shown as -3Vo in the vector diagrams. This phase shift is automatically introduced in the relay.
On the faulted feeder, the residual current is the addition of the charging current on the healthy phases (IH3) plus the fault current (IF). The net
unbalance is therefore equal to IL-IH1-IH2, as shown in Figure 16c.
P341/EN AP/G74 Page (AP) 6-41
(AP) 6 Application Notes Application of Individual Protection Functions
Figure 17 - Zero sequence network showing residual currents
In comparing the residual currents occurring on the healthy and on the faulted feeders
(Figure 16b & Figure 16c), it can be seen that the currents would be similar in both magnitude and phase; hence it would not be possible to apply a relay which could provide discrimination.
However, as previously stated, the scenario of no resistance being present in the coil or feeder cables is purely theoretical. Further consideration therefore needs to be given to a practical application in which the resistive component is no longer ignored - consider
Figure 18.
Page (AP) 6-42 P341/EN AP/G74
Application of Individual Protection Functions (AP) 6 Application Notes
P341/EN AP/G74
Resistive component Resistive component in feeder
with resistive components a) Capacitive & inductive currents
Resistive component Resistive component in feeder
with resistive components a) Capacitive & inductive currents b) Unfaulted line
Zero torque line for 0° RCA b) Unfaulted line
Zero torque line for 0° RCA
Figure 18 - Practical case: resistance present in XL and Xc
Figure 18a shows the relationship between the capacitive currents, coil current and residual voltage. Due to the presence of resistance in the feeders, the healthy phase charging currents are now leading their respective phase voltages by less than 90°. In a similar manner, the resistance present in the earthing coil has the effect of shifting the current, IL, to an angle less than 90° lagging. The result of these slight shifts in angles can be seen in Figure 18b and Figure 18c.
The residual current now appears at an angle in excess of 90° from the polarizing voltage for the unfaulted feeder and less than 90° on the faulted feeder. Hence, a directional relay having a characteristic angle setting of 0° (with respect to the polarizing signal of -
3Vo) could be applied to provide discrimination, that is the healthy feeder residual current would appear within the restrain section of the characteristic but the residual current on the faulted feeder would lie within the operate region - as shown in Figure 18b and Figure
18c.
In practical systems, it may be found that a value of resistance is purposely inserted in parallel with the earthing coil. This serves two purposes; one is to actually increase the level of earth fault current to a more practically detectable level and the second is to increase the angular difference between the residual signals; again to aid in the application of discriminating protection.
Page (AP) 6-43
(AP) 6 Application Notes
2.10.5
2.10.5.1
2.10.5.2
Application of Individual Protection Functions
Applications to Compensated Networks
Required Relay Current and Voltage Connections
Referring to the relevant application diagram for the P341 Relay, it should be applied such that it’s direction for forward operation is looking down into the protected feeder
(away from the busbar), with a 0° RCA setting.
As shown in the relay application diagram, it is usual for the earth fault element to be driven from a Core Balance Current Transformer (CBCT). This eliminates the possibility of spill current that may arise from slight mismatches between residually connected line
CT’s. It also enables a much lower CT ratio to be applied, thereby allowing the required protection sensitivity to be more easily achieved.
Calculation of Required Relay Settings
As has been previously shown, for a fully compensated system, the residual current detected by the relay on the faulted feeder is equal to the coil current minus the sum of the charging currents flowing from the rest of the system. Further, as stated in the previous section, the addition of the two healthy phase charging currents on each feeder gives a total charging current which has a magnitude of three times the steady state per phase value. Therefore for a fully compensated system, the total unbalance current detected by the relay is equal to three times the per phase charging current of the faulted circuit. A typical relay setting may therefore be in the order of 30% of this value, i.e. equal to the per phase charging current of the faulted circuit. Practically though, the required setting may well be determined on site, where system faults can be applied and suitable settings can be adopted based upon practically obtained results.
In most situations, the system will not be fully compensated and consequently a small level of steady state fault current will be allowed to flow. The residual current seen by the relay on the faulted feeder may therefore be a larger value, which further emphasizes the fact that relay settings should be based on practical current levels, wherever possible.
The above also holds true regarding the required Relay Characteristic Angle (RCA) setting. As has been shown earlier, a nominal RCA setting of 0º is required. However, fine-tuning of this setting will require to be carried out on site in order to obtain the optimum setting in accordance with the levels of coil and feeder resistances present. The loading and performance of the CT will also have an effect in this regard. The effect of
CT magnetizing current will be to create phase lead of current. While this would assist with operation of faulted feeder relays it would reduce the stability margin of healthy feeder relays. A compromise can therefore be reached through fine adjustment of the
RCA. This is adjustable in 1° steps on the P341 relays.
Page (AP) 6-44 P341/EN AP/G74
Application of Individual Protection Functions
2.11
2.11.1.1
(AP) 6 Application Notes
Restricted Earth Fault Protection (64)
Earth faults occurring on a transformer winding or terminal may be of limited magnitude, either due to the impedance present in the earth path or by the percentage of transformer winding that is involved in the fault. In general, particularly as the size of the transformer increases, it becomes unacceptable to rely on time delayed protection to clear winding or terminal faults as this would lead to an increased amount of damage to the transformer.
A common requirement is therefore to provide instantaneous phase and earth fault protection. Applying differential protection across the transformer may fulfill these requirements. However, an earth fault occurring on the LV winding, particularly if it is of a limited level, may not be detected by the differential relay, as it is only measuring the corresponding HV current. Therefore, instantaneous protection that is restricted to operating for transformer earth faults only is applied. This is referred to as Restricted
Earth Fault or Balanced Earth Fault (REF or BEF) protection. The BEF terminology is usually used when the protection is applied to a delta winding.
When applying differential protection such as REF, some technique must be employed to give the protection stability under external fault conditions, ensuring that relay operation only occurs for faults on the transformer winding/connections. Two methods are commonly used; bias or high impedance. The biasing technique operates by measuring the level of through current flowing and altering the relay sensitivity accordingly. The high impedance technique ensures that the relay circuit is of sufficiently high impedance such that the differential voltage that may occur under external fault conditions is less than that required to drive setting current through the relay.
The REF protection in the P341 should be applied as a high impedance differential element.
Note The high impedance REF element of the relay shares the same CT input as the SEF protection. Hence, only one of these elements may be selected.
Note that CT requirements for REF protection are included in section 4 .
REF protection may also be applied to the stator winding of machines to provide earth fault protection in a similar way to that of the star winding of transformers. See the P34x
Application Notes chapter, for more information on stator winding REF applications.
Setting Guidelines for High Impedance REF Protection
From the Sens E/F Options cell, Hi Z REF must be selected to enable High Impedance
REF protection. The only setting cell then visible is IREF> Is , which may be programmed with the required differential current setting. This would typically be set to give a primary operating current of either 30% of the minimum earth fault level for a resistance earthed system or between 10 and 60% of rated current for a solidly earthed system.
The primary operating current (Iop) will be a function of the current transformer ratio, the relay operating current (IREF> Is ), the number of current transformers in parallel with a relay element (n) and the magnetizing current of each current transformer (Ie) at the stability voltage (Vs). This relationship can be expressed in three ways:
To determine the maximum current transformer magnetizing current to achieve a specific primary operating current with a particular relay operating current.
e <
1 n
x
op
CT ratio
- Gen diff REF >
To determine the maximum relay current setting to achieve a specific primary operating current with a given current transformer magnetizing current.
P341/EN AP/G74 Page (AP) 6-45
(AP) 6 Application Notes Application of Individual Protection Functions
REF s1 <
op
CT ratio
- n
To express the protection primary operating current for a particular relay operating current and with a particular level of magnetizing current.
Iop = (CT ratio) x (IREF > Is1 + nIe)
To achieve the required primary operating current with the current transformers that are used, a current setting IREF> Is must be selected for the high impedance element, as detailed in expression (ii) above. The setting of the stabilizing resistor (RST) must be calculated in the following manner, where the setting is a function of the required stability voltage setting (VS) and the relay current setting IREF> Is .
Vs
RST =
REF > s1
=
F (RCT + 2RL)
REF > s1
Note The above equation assumes negligible relay impedance.
The stabilizing resistor supplied is continuously adjustable up to its maximum declared resistance.
Use of “Metrosil” Non-Linear Resistors
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 normally able to withstand 3000 V peak.
The following formulae should be used to estimate the peak transient voltage that could be produced for an internal fault. The peak voltage produced during an internal fault will be 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.
This prospective voltage will be a function of maximum internal fault secondary current, the current transformer ratio, the current transformer secondary winding resistance, the current transformer lead resistance to the common point, the relay lead resistance and the stabilizing resistor value.
Vp = 2 2 Vk ( Vf - Vk
V f
= I' f
(R
CT
+ 2R
L
+ R
ST
)
Where:
V p
=
V
Vf k
=
=
I‘
R f
=
R
L
CT
=
R
=
ST
=
Peak voltage developed by the CT under internal fault conditions
Current transformer knee-point voltage
Maximum voltage that would be produced if CT saturation did not occur
Maximum internal secondary fault current
Current transformer secondary winding resistance
Maximum lead burden from current transformer to relay
Relay stabilizing resistor
When the value given by the formulae is greater than 3000 V peak, Metrosils should be applied. They are connected across the relay circuit and serve the purpose of shunting the secondary current output of the current transformer from the relay in order to prevent very high secondary voltages.
Metrosils are externally mounted and take the form of annular discs. Their operating characteristics follow the expression:
Where:
V = Instantaneous voltage applied to the non-linear resistor (“Metrosil”)
Page (AP) 6-46 P341/EN AP/G74
Application of Individual Protection Functions (AP) 6 Application Notes
C =
I =
Constant of the non-linear resistor (“Metrosil”)
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:
(rms) = 0.52
Vs (rms) x 2
C
4
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 non-linear resistor
(“Metrosil”) is not sinusoidal but appreciably distorted.
For satisfactory application of a non-linear resistor (“Metrosil”), its 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 30 mA rms for 1 A current transformers and approximately 100 mA rms for 5 A current transformers.
At the maximum secondary current, the non-linear resistor (“Metrosil”) should limit the voltage to 1500 V rms or 2120 V peak for 0.25 second. At higher relay voltage settings, it is not always possible to limit the fault voltage to 500 V rms, so higher fault voltages may have to be tolerated.
Table 2 and Table 3 show the typical Metrosil types that will be required, depending on relay current rating, REF voltage setting etc.
Metrosil Units for Relays with a 1 Amp CT
The Metrosil units with 1 Amp CTs have been designed to comply with these restrictions:
At the relay voltage setting, the Metrosil current should less than 30 mA rms
At the maximum secondary internal fault current the Metrosil unit should limit the voltage to 1500 V rms if possible.
The Metrosil units normally recommended for use with 1 Amp CTs are shown in Table 2:
Relay voltage setting
Nominal characteristic
Up to 125 V rms 450
125 to 300 V rms 900
C
0.25
0.25
I
Recommended Metrosil type
Single pole relay
600 A/S1/S256
600 A/S1/S1088
Table 2 - Recommended Metrosil types for 1 A CTs
Triple pole relay
600A/S3/1/S802
600A/S3/1/S1195
Note Single pole Metrosil units are normally supplied without mounting brackets unless otherwise specified by the customer
P341/EN AP/G74 Page (AP) 6-47
(AP) 6 Application Notes Application of Individual Protection Functions
Metrosil Units for Relays with a 5 Amp CT
These Metrosil units have been designed to comply with the following requirements:
At the relay voltage setting, the Metrosil current should less than 100 mA rms (the actual maximum currents passed by the units shown below their type description).
At the maximum secondary internal fault current the Metrosil unit should limit the voltage to 1500 V rms for 0.25secs. At the higher relay settings, it is not possible to limit the fault voltage to 1500 V rms hence higher fault voltages have to be tolerated (indicated by *, **, ***).
The Metrosil units normally recommended for use with 5 Amp CTs and single pole relays are shown in Table 3:
Secondary internal fault current
Amps rms
50 A
100 A
150 A
Notes
Recommended METROSIL type
Up to 200 V rms
600 A/S1/S1213 C =
540/640 35 mA rms
600 A/S2/P/S1217 C =
470/540 70 mA rms
600 A/S3/P/S1219 C =
430/500 100 mA rms
Relay voltage setting
250 V rms
600 A/S1/S1214 C =
670/800 40 mA rms
600 A/S2/P/S1215 C =
570/670
75 mA rms
600 A/S3/P/S1220 C =
520/620 100 mA rms
275 V rms
600 A/S1/S1214 C
=670/800 50 mA rms
600 A/S2/P/S1215 C =
570/670
100 mA rms
600 A/S3/P/S1221 C =
570/670** 100 mA rms
300 V rms
600A/S1/S1223 C =
740/870* 50mA rms
600 A/S2/P/S1196 C
=620/740*
100 mA rms
600 A/S3/P/S1222 C
=620/740***
100 mA rms
*2400 V peak
**2200 V peak
***2600 V peak
Table 3 - Recommended Metrosil types for 5 A CTs
In some situations single disc assemblies may be acceptable, contact Schneider Electric for detailed applications.
The Metrosil units recommended for use with 5 Amp CTs can also be applied for use with triple pole relays and consist of three single pole units mounted on the same central stud but electrically insulated for each other. To order these units please specify "Triple Pole Metrosil Type", followed by the single-pole type reference.
Metrosil units for higher relay voltage settings and fault currents can be supplied if required.
For further advice and guidance on selecting Metrosils please contact Schneider Electric.
Page (AP) 6-48 P341/EN AP/G74
Application of Individual Protection Functions
2.12
(AP) 6 Application Notes
Residual Overvoltage/Neutral Voltage Displacement Protection (59N)
On a healthy three-phase power system, the addition of each of the three-phase to earth voltages is nominally zero, as it is the vector addition of three balanced vectors at 120° to one another. However, when an earth fault occurs on the primary system this balance is upset and a ‘residual’ voltage is produced.
This could be measured, for example, at the secondary terminals of a voltage transformer having a “broken delta” secondary connection. Hence, a residual voltage measuring relay can be used to offer earth fault protection on such a system. This condition causes a rise in the neutral voltage with respect to earth that is commonly referred to as Neutral
Voltage Displacement (NVD).
Alternatively, if the system is impedance or distribution transformer earthed, the neutral displacement voltage can be measured directly in the earth path via a single-phase VT.
This type of protection can be used to provide earth fault protection irrespective of whether the generator is earthed or not, and irrespective of the form of earthing and earth fault current level.
For generator applications for faults close to the generator neutral the resulting residual voltage will be small. Therefore, as with stator earth fault protection, only 95% of the stator winding can be reliably protected. Where residual overvoltage protection is applied to a directly connected generator, such a voltage will be generated for an earth fault occurring anywhere on that section of the system and hence the NVD protection must coordinate with other earth fault protections.
Where embedded generation can be run in parallel with the external distribution system it is essential that this type of protection is provided at the interconnection with the external system. This will ensure that if the connection with the main supply system is lost due to external switching events, some type of reliable earth fault protection is provided to isolate the generator from an earth fault. Loss of connection with the external supply system may result in the loss of the earth connection, where this is provided at a distant transformer, and hence current based earth fault protection may be unreliable.
The neutral voltage displacement protection function of the P341 relay includes two stages of derived and two stages of measured neutral overvoltage protection with adjustable time delays.
Two stages are included for the derived and measured elements to account for applications that require both alarm and trip stages, for example, an insulated system. It is common in such a case for the system to have been designed to withstand the associated healthy phase overvoltages for a number of hours following an earth fault. In such applications, an alarm is generated soon after the condition is detected, which serves to indicate the presence of an earth fault on the system. This gives time for system operators to locate and isolate the fault. The second stage of the protection can issue a trip signal if the fault condition persists. .
Figure 19 and Figure 20 show the residual voltages that are produced during earth fault conditions occurring on a solid and impedance earthed power system respectively.
P341/EN AP/G74 Page (AP) 6-49
(AP) 6 Application Notes Application of Individual Protection Functions
Figure 19 - Residual voltage, solidly earthed system
The residual voltage measured by a relay for an earth fault on a solidly earthed system is solely dependent on the ratio of source impedance behind the relay to line impedance in front of the relay, up to the point of fault. For a remote fault, the Zs/Zl ratio will be small, resulting in a correspondingly small residual voltage. As such, depending on the relay setting, such a relay would only operate for faults up to a certain distance along the system. The value of residual voltage generated for an earth fault condition is given by
the general formula shown in Figure 19.
Page (AP) 6-50
Figure 20 - Residual voltage, resistance earthed system
Figure 20 shows that a resistance earthed system will always generate a relatively large degree of residual voltage, as the zero sequence source impedance now includes the
P341/EN AP/G74
Application of Individual Protection Functions
2.12.1
(AP) 6 Application Notes earthing impedance. It follows then, that the residual voltage generated by an earth fault on an insulated system will be the highest possible value (3 x phase-neutral voltage), as the zero sequence source impedance is infinite.
From the previous information it can be seen that the detection of a residual overvoltage condition is an alternative means of earth fault detection, which does not require any measurement of current. This may be particularly advantageous in high impedance earthed or insulated systems, where the provision of core balance CT’s on each feeder may be either impractical, or uneconomic.
Note Where residual overvoltage protection is applied, such a voltage will be generated for a fault occurring anywhere on that section of the system and hence the NVD protection must coordinate with other earth fault protections.
The P341 relay can internally derive this voltage from the three-phase voltage input that must be supplied from either a 5-limb or three single-phase VT’s. These types of VT design allow the passage of residual flux and consequently permit the relay to derive the required residual voltage. In addition, the primary star point of the VT must be earthed.
A three limb VT has no path for residual flux and is therefore unsuitable to supply the relay.
Setting Guidelines for Residual Overvoltage/Neutral Voltage Displacement
Protection
Stage 1 may be selected as either IDMT (inverse time operating characteristic), DT
(definite time operating characteristic) or Disabled , within the VN>1 Function cell. Stage
2 operates with a definite time characteristic and is Enabled/Disabled in the VN>2 Status cell. The time delay. ( VN>1 TMS - for IDMT curve; V>1 Time Delay , V>2 Time Delay - for definite time) should be selected in accordance with normal relay co-ordination procedures to ensure correct discrimination for system faults.
The residual overvoltage protection can be set to operate from the voltage measured at the VN input VT terminals using VN>3/4 protection elements or the residual voltage derived from the phase-neutral voltage inputs as selected using the VN>1/2 protection elements.
The voltage setting applied to the elements is dependent upon the magnitude of residual voltage that is expected to occur during the earth fault condition. This in turn is dependent upon the method of system earthing employed and may be calculated by using the formulae previously given in Figure 19 and Figure 20. It must also be ensured that the relay is set above any standing level of residual voltage that is present on the system. IDMT characteristics are selectable on the first stage of NVD in order that elements located at various points on the system may be time graded with one another.
It must also be ensured that the voltage setting of the element is set above any standing level of residual voltage that is present on the system. A typical setting for residual overvoltage protection is 5 V.
The second stage of protection can be used as an alarm stage on unearthed or very high impedance earthed systems where the system can be operated for an appreciable time under an earth fault condition.
For machine applications of neutral voltage displacement protection see the P34x
Application Notes chapter, P34x/EN AP .
P341/EN AP/G74 Page (AP) 6-51
(AP) 6 Application Notes
2.13
2.13.1
Page (AP) 6-52
Application of Individual Protection Functions
Undervoltage Protection (27)
Where the P341 relay is being used as interconnection protection the under voltage element is used to prevent power being exported to external loads at a voltage below normal allowable limits. Undervoltage protection may also be used for back-up protection for a machine where it may be difficult to provide adequate sensitivity with phase current measuring elements.
For an isolated generator, or isolated set of generators, a prolonged under voltage condition could arise for a number of reasons. This could be due to failure of Automatic
Voltage Regulation (AVR) equipment or excessive load following disconnection from the main grid supply. Where there is a risk that a machine could become disconnected from the main grid supply and energize external load it is essential that under voltage protection is used. The embedded generator must be prevented from energizing external customers with voltage below the statutory limits imposed on the electricity supply authorities.
A two stage under voltage element is provided. The element can be set to operate from phase-phase or phase-neutral voltages.
Undervoltage conditions may occur on a power system for a variety of reasons, some of which are outlined below:
Increased system loading. Generally, some corrective action would be taken by voltage regulating equipment such as AVRs or On Load Tap Changers, in order to bring the system voltage back to it’s nominal value. If the regulating equipment is unsuccessful in restoring healthy system voltage, then tripping by means of an undervoltage relay will be required following a suitable time delay.
Faults occurring on the power system result in a reduction in voltage of the phases involved in the fault. The proportion by which the voltage decreases is directly dependent upon the type of fault, method of system earthing and it’s location with respect to the relaying point. Consequently, coordination with other voltage and current-based protection devices is essential in order to achieve correct discrimination.
Complete loss of busbar voltage. This may occur due to fault conditions present on the incomer or busbar itself, resulting in total isolation of the incoming power supply. For this condition, it may be a requirement for each of the outgoing circuits to be isolated, such that when supply voltage is restored, the load is not connected.
Therefore the automatic tripping of a feeder on detection of complete loss of voltage may be required. This may be achieved by a three-phase undervoltage element.
Where outgoing feeders from a busbar are supplying induction motor loads, excessive dips in the supply may cause the connected motors to stall, and should be tripped for voltage reductions which last longer than a pre-determined time.
Setting Guidelines for Undervoltage Protection
Stage 1 may be selected as either IDMT (for inverse time delayed operation), DT (for definite time delayed operation) or Disabled , within the V<1 Function cell. Stage 2 is definite time only and is Enabled/Disabled in the V<2 Status cell. The time delay
( V<1 TMS - for IDMT curve; V<1 Time Delay , V<2 Time Delay - for definite time) should be adjusted accordingly.
The undervoltage protection can be set to operate from phase-phase or phase-neutral voltage as selected by V< Measur’t Mode . Single or three-phase operation can be selected in V<1 Operate Mode . When Any Phase is selected, the element will operate if any phase voltage falls below setting, when Three-phase is selected the element will operate when all three-phase voltages are below the setting.
P341/EN AP/G74
Application of Individual Protection Functions (AP) 6 Application Notes
In many applications, undervoltage protection is not required to operate during system earth fault conditions. If this is the case, the element should be selected in the menu to operate from a phase to phase voltage measurement, as this quantity is less affected by single-phase voltage depressions due to earth faults.
The voltage threshold setting for the undervoltage protection should be set at some value below the voltage excursions that may be expected under normal system operating conditions. This threshold is dependent upon the system in question but typical healthy system voltage excursions may be in the order of -10% of nominal value.
Similar comments apply with regard to a time setting for this element, i.e. the required time delay is dependent on the time for which the system is able to withstand a depressed voltage. If motor loads are connected, then a typical time setting may be in the order of 0.5 seconds.
Where the relay is used to provide the protection required for connecting the generator in parallel with the local electricity supply system (e.g. requirements of G59 in the UK), the local electricity supply authority may advise settings for the element. The settings must prevent the generator from exporting power to the system with voltage outside of the statutory limits imposed on the supply authority. For this mode of operation the element must be set to operate from phase to neutral voltage, which will provide an additional degree of earth fault protection. The operating characteristic would normally be set to definite time, set V<1 Function to DT . The time delay, V<1 Time Delay , should be set to coordinate with downstream protection. Additionally, the delay should be long enough to prevent unwanted operation of the under voltage protection for transient voltage dips.
These may occur during clearance of faults further into the power system or by starting of local machines. The required time delay would typically be in excess of 3 s - 5 s.
As previously stated, local regulations for operating a generator in parallel with the external electricity supply may dictate the settings used for the under voltage protection.
For example in the UK the protection is typically set to measure phase to neutral voltage and trip at 90% of nominal voltage in a time of less than 0.5 s.
The second stage can be used as an alarm stage to warn the user of unusual voltage conditions so that corrections can be made. This could be useful if the machine is being operated with the AVR selected to manual control.
To prevent operation of any under voltage stage when the CB is open “poledead” logic is included in the relay. This is facilitated by selecting V Poledead Inh to Enabled . This will ensure that when a poledead condition is detected (i.e. all phase currents below the undercurrent threshold or CB Open, as determined by an opto isolator and the PSL) the undervoltage element will be inhibited.
P341/EN AP/G74 Page (AP) 6-53
(AP) 6 Application Notes
2.14
2.14.1
Application of Individual Protection Functions
Overvoltage Protection (59)
An overvoltage condition could arise when a generator is running but not connected to a power system, or where a generator is providing power to an islanded power system.
Such an overvoltage could arise in the event of a fault with automatic voltage regulating equipment or if the voltage regulator is set for manual control and an operator error is made. Overvoltage protection should be set to prevent possible damage to generator insulation, prolonged over-fluxing of the generating plant, or damage to power system loads.
When a generator is synchronized to a power system with other sources, an over voltage could arise if the generator is lightly loaded supplying a high level of power system capacitive charging current. An overvoltage condition might also be possible following a system separation, where a generator might experience full-load rejection whilst still being connected to part of the original power system. The automatic voltage regulating equipment and machine governor should quickly respond to correct the overvoltage condition in these cases. However, overvoltage protection is advisable to cater for a possible failure of the voltage regulator or for the regulator having been set to manual control.
A two stage overvoltage element is provided. The element can be set to operate from phase-phase or phase-neutral voltages.
Setting Guidelines for Overvoltage Protection
Stage 1 may be selected as either IDMT (for inverse time delayed operation), DT (for definite time delayed operation) or Disabled , within the V>1 Function cell. Stage 2 has a definite time delayed characteristic and is Enabled/Disabled in the V>2 Status cell.
The time delay ( V>1 TMS - for IDMT curve; V>1 Time Delay , V>2 Time Delay - for definite time) should be selected accordingly.
The overvoltage protection can be set to operate from Phase-Phase or Phase-Neutral voltage as selected by V> Measur’t Mode cell. Single or three-phase operation can be selected in V> Operate Mode cell. When Any Phase is selected the element will operate if any phase voltage is above setting, when Three-phase is selected the element will operate when all three-phase voltages are above the setting.
The inclusion of the two stages and their respective operating characteristics allows for a number of possible applications:
Use of the IDMT characteristic gives the option of a longer time delay if the overvoltage condition is only slight but results in a fast trip for a severe overvoltage.
As the voltage settings for both of the stages are independent, the second stage could then be set lower than the first to provide a time delayed alarm stage if required
Alternatively, if preferred, both stages could be set to definite time and configured to provide the required alarm and trip stages
If only one stage of overvoltage protection is required, or if the element is required to provide an alarm only, the remaining stage may be disabled within the relay menu
This type of protection must be coordinated with any other overvoltage relays at other locations on the system. This should be carried out in a similar manner to that used for grading current operated devices.
Generators can typically withstand a 5% over voltage condition continuously. The withstand times for higher over voltages should be declared by the generator manufacturer.
Page (AP) 6-54 P341/EN AP/G74
Application of Individual Protection Functions (AP) 6 Application Notes
To prevent operation during earth faults, the element should operate from the phasephase voltages, to achieve this V>1 Measur’t Mode can be set to Phase-Phase with
V>1 Operating Mode set to Three-phase . The overvoltage threshold, V>1 Voltage Set , should typically be set to 100% - 120% of the nominal phase-phase voltage seen by the relay. The time delay, V>1 Time Delay , should be set to prevent unwanted tripping of the delayed overvoltage protection function due to transient over voltages that do not pose a risk to the generating plant; e.g. following load rejection where correct AVR/Governor control occurs. The typical delay to be applied would be 1 s - 3 s, with a longer delay being applied for lower voltage threshold settings.
The second stage can be used to provide instantaneous high-set over voltage protection.
The typical threshold setting to be applied, V>2 Voltage Set , would be 130 - 150% of the nominal phase-phase voltage seen by the relay, depending on plant manufacturers’ advice. For instantaneous operation, the time delay, V>2 Time Delay , should be set to
0 s.
Where the relay is used to provide the protection required for connecting the generator in parallel with the local electricity supply system (e.g. requirements of G59 in the UK), the local electricity supply authority may advise settings for the element. The settings must prevent the generator from exporting power to the system with voltages outside of the statutory limits imposed on the supply authority. For example in the UK the protection is typically set to measure phase to neutral voltage and trip at 110% of nominal voltage in a time of less than 0.5 s.
If phase to neutral operation is selected, care must be taken to ensure that the element will grade with downstream protections during earth faults, where the phase-neutral voltage can rise significantly.
P341/EN AP/G74 Page (AP) 6-55
(AP) 6 Application Notes
2.15
2.15.1
Application of Individual Protection Functions
Negative Phase Sequence (NPS) Overvoltage Protection (47)
Where an incoming feeder is supplying a switchboard that is feeding rotating plant (e.g. a motor), correct phasing and balance of the ac supply is essential. Incorrect phase rotation could result in any connected machines rotating in the wrong direction. For some hydro machines two-phases can be swapped to allow the machine to rotate in a different direction to act as a generator or a motor pumping water.
Any unbalanced condition occurring on the incoming supply will result in the presence of
Negative Phase Sequence (NPS) components of voltage. In the event of incorrect phase rotation, the supply voltage would effectively consist of 100% negative phase sequence voltage only.
For such applications the P34x relay includes a negative phase sequence overvoltage element. This element monitors the input voltage rotation and magnitude (normally from a bus connected voltage transformer). This element could be used as a check for hydro machines that the phase rotation is correct to operate the machine in the selected mode as a generator or motor.
The NPS overvoltage element can also be used to provide an additional check to indicate a phase-earth or phase-phase fault is present for voltage controlled overcurrent protection in the PSL. In this application the NPS overvoltage protection can be accelerated when the CB is closed. Typically, the operating time of the NPS overvoltage start is slowed (typical operating time is <60 ms) to prevent incorrect operation when closing the CB due to pole scattering. However, when the CB is closed there is no need to inherently slow the protection start (typical accelerated operating time is <40 ms). The
V2>1 Accelerate: DDB 554 signal connected to the CB Closed 3 Ph: DDB 1043 signal can be used to accelerate the protection start.
Setting Guidelines
As the primary concern is normally the detection of incorrect phase rotation (rather than small unbalances), a sensitive setting is not required. In addition, it must be ensured that the setting is above any standing NPS voltage that may be present due to imbalances in the measuring VT, relay tolerances etc. A setting of approximately 15% of rated voltage may be typical.
Note Standing levels of NPS voltage (V2) will be displayed in the Measurements
1 column of the relay menu, labeled V2 Magnitude.
Hence, if more sensitive settings are required, they may be determined during the commissioning stage by viewing the actual level that is present.
The operation time of the element will be highly dependent on the application. A typical setting would be in the region of 5 s.
Page (AP) 6-56 P341/EN AP/G74
Application of Individual Protection Functions
2.16
2.16.1
(AP) 6 Application Notes
Underfrequency Protection (81U)
Underfrequency operation of a generator will occur when the power system load exceeds the prime mover capability of an islanded generator or group of generators. Power system overloading can arise when a power system becomes split, with load left connected to a set of ‘islanded’ generators that is in excess of their capacity. Automatic load shedding could compensate for such events. In this case, underfrequency operation would be a transient condition. This characteristic makes underfrequency protection a simple form of “Loss of Mains” protection on system where it is expected that the islanded load attached to the machine when the grid connection fails exceeds the generator capacity. In the event of the load shedding being unsuccessful, the generators should be provided with backup underfrequency protection.
Where the P341 relay is being used as interconnection protection the underfrequency element is used to prevent power being exported to external loads at a frequency below normal allowable limits. The underfrequency protection can be used to detect a loss of mains condition where the main supply connection to the load is disconnected and there is a variation in generator speed due to the generator experiencing a step change in load.
Four independent definite time-delayed stages of underfrequency protection are provided. Two additional underfrequency stages can be provided by reconfiguring the two overfrequency protection stages as underfrequency protection using the
Programmable Scheme Logic (PSL). As well as being able to initiate generator tripping, the underfrequency protection can also be arranged to initiate local load-shedding, where appropriate. Selectable fixed scheme logic is provided to allow each stage of underfrequency protection to be disabled when the outgoing CB is open, to prevent unnecessary load tripping.
Setting Guidelines for Underfrequency Protection
Each stage of underfrequency protection may be selected as Enabled or Disabled , within the F<x Status cells. The frequency pickup setting, F<x Setting , and time delays,
F<x Time Delay , for each stage should be selected accordingly.
The protection function should be set so that declared frequency-time limits for the generating set are not infringed. Typically, a 10% underfrequency condition should be continuously sustainable.
For industrial generation schemes, where generation and loads may be under common control/ownership, the P34x underfrequency protection function could be used to initiate local system load shedding. Four stage underfrequency/load shedding can be provided.
The final stage of underfrequency protection should be used to trip the generator.
Where separate load shedding equipment is provided, the underfrequency protection should co-ordinate with it. This will ensure that generator tripping will not occur in the event of successful load shedding following a system overload. Two stages of underfrequency protection could be set-up, as shown in Figure 21, to coordinate with multi-stage system load shedding.
P341/EN AP/G74 Page (AP) 6-57
(AP) 6 Application Notes Application of Individual Protection Functions
Page (AP) 6-58
Figure 21 - Coordination of underfrequency protection function with system load shedding
To prevent operation of any underfrequency stage during normal shutdown of the generator “poledead” logic is included in the relay. This is facilitated for each stage by setting the relevant bit in F< Function Link . For example if F< Function Link is set to
0111, Stage 1, 2 and 3 of underfrequency protection will be blocked when the generator
CB is open. Selective blocking of the frequency protection stages in this way will allow a single stage of protection to be enabled during synchronization or offline running to prevent unsynchronized overfluxing of the machine. When the machine is synchronized, and the CB closed, all stages of frequency protection will be enabled providing a multistage load shed scheme if desired.
Where the relay is used to provide the protection required for connecting the generator in parallel with the local electricity supply system (e.g. requirements of G59 in the UK), the local electricity supply authority may advise settings for the element. The settings must prevent the generator from exporting power to the system with frequency outside of the statutory limits imposed on the supply authority. For example, in the UK the underfrequency protection is typically set to 47 Hz with a trip time of less than 0.5 s.
P341/EN AP/G74
Application of Individual Protection Functions
2.17
2.17.1
(AP) 6 Application Notes
Overfrequency Protection Function (81O)
Overfrequency running of a generator arises when the mechanical power input to the alternator is in excess of the electrical load and mechanical losses. The most common occurrence of overfrequency is after substantial loss of load. When a rise in running speed occurs, the governor should quickly respond to reduce the mechanical input power, so that normal running speed is quickly regained. Overfrequency protection may be required as a back-up protection function to cater for governor or throttle control failure following loss of load or during unsynchronized running.
Moderate overfrequency operation of a generator is not as potentially threatening to the generator and other electrical plant as underfrequency running. Action can be taken at the generating plant to correct the situation without necessarily shutting down the generator.
Where the P341 relay is being used as interconnection protection the overfrequency element will prevent power being exported to external loads at a frequency higher than normal allowable limits. The overfrequency protection can be used to detect a loss of mains condition where the main supply connection to the load is disconnected and there is a variation in generator speed due to the generator experiencing a step change in load.
Two independent time-delayed stages of overfrequency protection are provided.
Setting Guidelines for Overfrequency Protection
Each stage of overfrequency protection may be selected as Enabled or Disabled , within the F>x Status cells. The frequency pickup setting, F>x Setting , and time delays,
F>x Time Delay , for each stage should be selected accordingly.
The P34x overfrequency settings should be selected to coordinate with normal, transient overfrequency excursions following full-load rejection. The generator manufacturer should declare the expected transient overfrequency behavior that should comply with international governor response standards. A typical overfrequency setting would be
10% above nominal.
Where the relay is used to provide the protection required for connecting the generator in parallel with the local electricity supply system (e.g. requirements of G59 in the UK), the local electricity supply authority may advise settings for the element. The settings must prevent the generator from exporting power to the system with frequency outside of the statutory limits imposed on the supply authority. For example in the UK overfrequency protection is typically set to 50.5 Hz with a trip time of less than 0.5 s.
P341/EN AP/G74 Page (AP) 6-59
(AP) 6 Application Notes
2.18
2.18.1
2.18.2
Page (AP) 6-60
Application of Individual Protection Functions
Thermal Overload Protection (49)
Introduction
Overloads can result in stator temperature rises which exceed the thermal limit of the winding insulation. Empirical results suggest that the life of insulation is approximately halved for each 10 C rise in temperature above the rated value. However, the life of insulation is not wholly dependent upon the rise in temperature but on the time the insulation is maintained at this elevated temperature. Due to the relatively large heat storage capacity of an electrical machine, infrequent overloads of short duration may not damage the machine. However, sustained overloads of a few percent may result in premature ageing and failure of insulation.
The physical and electrical complexity of generator construction result in a complex thermal relationship. It is not possible to create an accurate mathematical model of the true thermal characteristics of the machine.
However, if a generator is considered to be a homogeneous body, developing heat internally at a constant rate and dissipating heat at a rate directly proportional to its temperature rise, it can be shown that the temperature at any instant is given by a timecurrent thermal replica characteristic.
As previously stated it is an oversimplification to regard a generator as an homogeneous body. The temperature rise of different parts or even of various points in the same part may be very uneven. However, it is reasonable to consider that the current-time relationship follows an inverse characteristic. A more accurate representation of the thermal state of the machine can be obtained through the use of Temperature Monitoring
Devices (RTDs) which target specific areas. Also, for short time overloads the application of RTDs and overcurrent protection can provide better protection.
Note The thermal model does not compensate for the effects of ambient temperature change. So if there is an unusually high ambient temperature or if the machine cooling is blocked RTDs will also provide better protection.
Thermal Replica
The P341 relay models the time-current thermal characteristic of a generator by internally generating a thermal replica of the machine.
The positive and negative sequence components of the generator current are measured independently and are combined together to form an equivalent current, Ieq, which is supplied to the replica circuit. The heating effect in the thermal replica is produced by
Ieq2 and therefore takes into account the heating effect due to both positive and negative sequence components of current.
Unbalanced phase currents will cause additional rotor heating that may not be accounted for by some thermal protection relays based on the measured current only. Unbalanced loading results in the flow of positive and negative sequence current components. Load unbalance can arise as a result of single-phase loading, non-linear loads (involving power electronics or arc furnaces, etc.), uncleared or repetitive asymmetric faults, fuse operation, single-pole tripping and reclosing on transmission systems, broken overhead line conductors and asymmetric failures of switching devices. Any negative phase sequence component of stator current will set up a reverse-rotating component of stator flux that passes the rotor at twice synchronous speed. Such a flux component will induce double frequency eddy currents in the rotor, which can cause overheating of the rotor body, main rotor windings, damper windings etc. This extra heating is not accounted for in the thermal limit curves supplied by the generator manufacturer as these curves assume positive sequence currents only that come from a perfectly balanced supply and generator design. The P34x thermal model may be biased to reflect the additional
P341/EN AP/G74
Application of Individual Protection Functions (AP) 6 Application Notes heating that is caused by negative sequence current when the machine is running. This biasing is done by creating an equivalent heating current rather than simply using the phase current. The M factor is a constant that relates negative sequence rotor resistance to positive sequence rotor resistance. If an M factor of 0 is used the unbalance biasing is disabled and the overload curve will time out against the measured generator positive sequence current.
The equivalent current for operation of the overload protection is in accordance with the following expression:
I eq
= (I
1
2
+ MI
2
2
)
I
Where:
=
I
1
2
=
M = machine
Positive sequence current
Negative sequence current
A user settable constant proportional to the thermal capacity of the
As previously described, the temperature of a generator will rise exponentially with increasing current. Similarly, when the current decreases, the temperature also decreases in a similar manner. Therefore to achieve close sustained overload protection, the P341 relay incorporates a wide range of thermal time constants for heating and cooling.
Furthermore, the thermal withstand capability of the generator is affected by heating in the winding prior to the overload. The thermal replica is designed to take account the extremes of zero pre-fault current, known as the ‘cold’ condition and the full rated prefault current, known as the ‘hot’ condition. With no pre-fault current the relay will be operating on the ‘cold curve’. When a generator is or has been running at full load prior to an overload the ‘hot curve’ is applicable. Therefore during normal operation the relay will be operating between these two limits.
P341/EN AP/G74 Page (AP) 6-61
(AP) 6 Application Notes
2.18.3
Application of Individual Protection Functions
Setting Guidelines
The current setting is calculated as:
Thermal Trip = Permissible continuous loading of the plant item/CT ratio.
The heating thermal time constant should be chosen so that the overload curve is always below the thermal limits provided by the manufacturer. This will ensure that the machine is tripped before the thermal limit is reached.
The relay setting, T-heating , is in minutes.
The cooling thermal time constant should be provided by the manufacturer. However, unless otherwise specified, the cooling time constant, T-cooling , setting should be set equal to the main heating time constant setting, T-heating . The cooling time constant is applied when the machine is running and the load current is decreasing. It is therefore practical to assume the cooling time constant is similar to the heating time constant if information is not available from the manufacturer. When the machine is not turning the machine will normally cool significantly slower than when the rotor is turning. The relay setting, T-cooling , is in minutes.
An alarm can be raised on reaching a thermal state corresponding to a percentage of the trip threshold. A typical setting might be Thermal Alarm = 70% of thermal capacity. The thermal alarm could also be used to prevent restarting of the generator until the alarm level resets. For this application a typical setting may be 20%.
The M Factor is used to increase the influence of negative sequence current on the thermal replica protection due to unbalanced currents. If it is required to account for the heating effect of unbalanced currents then this factor should be set equal to the ratio of negative phase sequence rotor resistance to positive sequence rotor resistance at rated speed. When an exact setting can not be calculated a setting of 3 should be used. This is a typical setting and will suffice for the majority of applications. If an M factor of 0 is used the unbalance biasing is disabled and the overload curve will time out against the measured generator positive sequence current.
Note The extra heating caused by unbalanced phase currents is not accounted for in the thermal limit curves supplied by the generator manufacturer as these curves assume positive sequence currents only that come from a perfectly balanced supply and generator design, so the default setting is 0.
Page (AP) 6-62 P341/EN AP/G74
Application of Individual Protection Functions
2.19
2.19.1
(AP) 6 Application Notes
Circuit Breaker Fail (CBF) Protection (50BF)
Following inception of a fault one or more main protection devices will operate and issue a trip output to the circuit breaker(s) associated with the faulted circuit. Operation of the circuit breaker is essential to isolate the fault, and prevent damage/further damage to the power system. For transmission/sub-transmission systems, slow fault clearance can also threaten system stability. It is therefore common practice to install circuit breaker failure protection, which monitors that the circuit breaker has opened within a reasonable time.
If the fault current has not been interrupted following a set time delay from circuit breaker trip initiation, Circuit Breaker Failure (CBF) protection will operate.
CBF operation can be used to back-trip upstream circuit breakers to ensure that the fault is isolated correctly. CBF operation can also reset all start output contacts, ensuring that any blocks asserted on upstream protection are removed.
Reset Mechanisms for Breaker Fail Timers
It is common practice to use low set undercurrent elements in protection relays to indicate that circuit breaker poles have interrupted the fault or load current, as required. This covers the following situations:
Where circuit breaker auxiliary contacts are defective, or cannot be relied on to definitely indicate that the breaker has tripped.
For any protection function requiring current to operate, the relay uses operation of undercurrent elements (I<) to detect that the necessary circuit breaker poles have tripped and reset the CB fail timers. However, the undercurrent elements may not be reliable methods of resetting circuit breaker fail in all applications. For example:
Where a circuit breaker has started to open but has become jammed. This may result in continued arcing at the primary contacts, with an additional arcing resistance in the fault current path. Should this resistance severely limit fault current, the initiating protection element may reset. Therefore reset of the element may not give a reliable indication that the circuit breaker has opened fully.
Where non-current operated protection, such as under/overvoltage or under/overfrequency, derives measurements from a line connected voltage transformer. Here, I< only gives a reliable reset method if the protected circuit would always have load current flowing. Detecting drop-off of the initiating protection element might be a more reliable method.
Where non-current operated protection, such as under/overvoltage or under/overfrequency, derives measurements from a busbar connected voltage transformer. Again using I< would rely upon the feeder normally being loaded.
Also, tripping the circuit breaker may not remove the initiating condition from the busbar, and hence drop-off of the protection element may not occur. In such cases, the position of the circuit breaker auxiliary contacts may give the best reset method.
P341/EN AP/G74 Page (AP) 6-63
(AP) 6 Application Notes
2.19.1.1
2.19.2
Application of Individual Protection Functions
Breaker Fail Timer Settings
Typical timer settings to use are as follows:
CB fail reset mechanism
Initiating element reset
CB open
Undercurrent elements tBF time delay
Typical delay for 2½ cycle circuit breaker
CB interrupting time + element reset time (max.) + error in tBF timer + safety margin
50 + 50 + 10 + 50 = 160 ms
CB auxiliary contacts opening/closing time (max.) + error in tBF timer + safety margin
50 + 10 + 50 = 110 ms
CB interrupting time+ undercurrent element (max.) + safety margin operating time
50 + 12 + 50 = 112 ms
Table 4 - CB fail typical timer settings
Note All CB Fail resetting involves the operation of the undercurrent elements.
Where element reset or CB open resetting is used the undercurrent time setting should still be used if this proves to be the worst case.
The examples above consider direct tripping of a 2½ cycle circuit breaker.
Note Where auxiliary tripping relays are used, an additional 10 - 15 ms must be added to allow for trip relay operation.
Breaker Fail Undercurrent Settings
The phase undercurrent settings (I<) must be set less than load current, to ensure that I< operation indicates that the circuit breaker pole is open. A typical setting for overhead line or cable circuits is 20% In, with 5% In common for generator circuit breaker CBF.
The sensitive earth fault protection (SEF) and standby earth fault (SBEF) undercurrent elements must be set less than the respective trip setting, typically as follows:
ISEF< =
IN<
(ISEF> trip)/2
= (IN>
For generator applications the undercurrent elements should be measuring current from
CTs on the terminal side of the generator. This is because for an internal fault on the generator after the CB has tripped the generator will still be supplying some fault current which will be seen by undercurrent elements measuring current from CTs on the neutral side of the generator. This could thus give false indication of a breaker fail condition.
Page (AP) 6-64 P341/EN AP/G74
Application of Individual Protection Functions
2.20
(AP) 6 Application Notes
Blocked Overcurrent Protection
Blocked overcurrent protection involves the use of start contacts from downstream relays wired onto blocking inputs of upstream relays. This allows identical current and time settings to be employed on each of the relays involved in the scheme, as the relay nearest to the fault does not receive a blocking signal and hence trips discriminatively.
This type of scheme therefore reduces the amount of required grading stages and consequently fault clearance times.
The principle of blocked overcurrent protection may be extended by setting fast acting overcurrent elements on the P341 which are then arranged to be blocked by start contacts from the relays protecting the outgoing feeders. The fast acting element is thus allowed to trip for a fault condition on the busbar but is stable for external feeder faults by means of the blocking signal. This type of scheme therefore provides much reduced fault clearance times for busbar faults than would be the case with conventional time graded overcurrent protection. The availability of multiple overcurrent and earth fault stages means that back-up time graded overcurrent protection is also provided. This is shown in
Figure 22 and Figure 23.
Figure 22 - Simple busbar blocking scheme (single incomer)
P341/EN AP/G74 Page (AP) 6-65
(AP) 6 Application Notes Application of Individual Protection Functions
Figure 23 - Simple busbar blocking scheme (single incomer)
The P140/P341 relays have start outputs available from each stage of each of the overcurrent and earth fault elements, including sensitive earth fault. These start signals may then be routed to output contacts by programming accordingly. Each stage is also capable of being blocked by being programmed to the relevant opto-isolated input.
The P341 relays provide a 50 V field supply for powering the opto-inputs. Therefore in the unlikely event of the failure of this supply, blocking of that relay would not be possible.
For this reason, the field supply is supervised and if a failure is detected, it is possible, via the relays programmable scheme logic, to provide an output alarm contact. This contact can then be used to signal an alarm within the substation. Alternatively, the relays scheme logic could be arranged to block any of the overcurrent/earth fault stages that would operate non-discriminatively due to the blocking signal failure.
For further guidance on the use of blocked overcurrent schemes refer Schneider Electric.
Page (AP) 6-66 P341/EN AP/G74
Application of Individual Protection Functions
2.21
2.21.1
2.21.2
Current Loop Inputs and Outputs
(AP) 6 Application Notes
Current Loop Inputs
Four analog (or current loop) inputs are provided for transducers with ranges of 0 - 1 mA,
0 - 10 mA, 0 - 20 mA or 4 - 20 mA. The analog inputs can be used for various transducers such as vibration monitors, tachometers and pressure transducers.
Associated with each input there are two protection stages, one for alarm and one for trip.
Each stage can be individually enabled or disabled and each stage has a definite time delay setting. The Alarm and Trip stages can be set for operation when the input value falls below the Alarm/Trip threshold Under or when the input current is above the input value Over .
Power-on diagnostics and continuous self-checking are provided for the hardware associated with the current loop inputs.
For the 4 - 20 mA input range, a current level below 4 mA indicates that there is a fault with the transducer or the wiring. An instantaneous undercurrent alarm element is available, with a setting range from 0 to 4 mA. This element controls an output signal
(CLI1/2/3/4 I< Fail Alm, DDB 390-393) which can be mapped to a user defined alarm if required.
Setting Guidelines for Current Loop Inputs
For each analog input, the user can define the following:
The current input range: 0 - 1 mA, 0 - 10 mA, 0 - 20 mA, 4 - 20 mA
The analog input function and unit, this is in the form of a 16-character input label
Analog input minimum value (setting range from -9999 to 9999)
Analog input maximum value (setting range from -9999 to 9999)
Alarm threshold, range within the maximum and minimum set values
Alarm function - over or under
Alarm
Trip threshold, range within maximum and minimum set values
Trip function - over or under
Trip
Each current loop input can be selected as Enabled or Disabled as can the Alarm and
Trip stage of each of the current loop input. The Alarm and Trip stages can be set for operation when the input value falls below the Alarm/Trip threshold Under or when the input current is above the input value Over depending on the application. One of four types of analog inputs can be selected for transducers with ranges of 0 - 1 mA, 0 -
10 mA, 0 - 20 mA or 4 - 20 mA.
The Maximum and Minimum settings allow the user to enter the range of physical or electrical quantities measured by the transducer. The settings are unit-less; however, the user can enter the transducer function and the unit of the measurement using the 16character user defined CLI Input Label. For example, if the analog input is used to monitor a power measuring transducer, the appropriate text could be
“Active Power (MW)”.
The alarm and trip threshold settings should be set within the range of physical or electrical quantities defined by the user. The relay will convert the current input value into its corresponding transducer measuring value for the protection calculation.
P341/EN AP/G74 Page (AP) 6-67
(AP) 6 Application Notes
2.21.3
2.21.4
Application of Individual Protection Functions
For example if the CLI Minimum is -1000 and the CLI Maximum is 1000 for a 0 - 10mA input, an input current of 10 mA is equivalent to a measurement value of 1000, 5 mA is 0 and 1 mA is -800. If the CLI Minimum is 1000 and the CLI Maximum is -1000 for a 0 - 10 mA input, an input current of 10 mA is equivalent to a measurement value of -1000, 5 mA is 0 and 1 mA is 800. These values are available for display in the CLIO Input 1/2/3/4 cells in the MEASUREMENTS 3 menu. The top line shows the CLI Input Label and the bottom line shows the measurement value.
Current Loop Outputs
Four analog current outputs are provided with ranges of 0 - 1 mA, 0 - 10 mA, 0 - 20 mA or
4 - 20 mA which can alleviate the need for separate transducers. These may be used to feed standard moving coil ammeters for analog indication of certain measured quantities or into a SCADA using an existing analog RTU.
The outputs can be assigned to any of the following relay measurements:
Magnitudes of IA, IB, IC, IN, IN Derived, I Sensitive
Magnitudes of I1, I2, I0
IA RMS, IB RMS, IC RMS
Magnitudes of VAB, VBC, VCA, VAN, VBN, VCN, VN Measured, VN Derived
Magnitudes of V1, V2 and V0
VAN RMS, VBN RMS, VCN RMS
Frequency
Single-phase active, reactive and apparent power, single-phase power factor
Three-phase active, reactive and apparent power, single-phase power factor
Stator thermal state
Analog
DLR ampacity and maximum ac current
The user can set the measuring range for each analog output. The range limits are defined by the Maximum and Minimum settings. This allows the user to “zoom in” and monitor a restricted range of the measurements with the desired resolution. For voltage, current and power quantities, these settings can be set in either primary or secondary quantities, depending on the CLO1/2/3/4 Set Values - Primary/Secondary setting associated with each current loop output.
Power-on diagnostics and continuous self-checking are provided for the hardware associated with the current loop outputs.
Setting Guidelines for Current Loop Outputs
Each current loop output can be selected as Enabled or Disabled . One of four types of analog output can be selected for transducers with ranges of 0 - 1 mA, 0 - 10 mA, 0 -
20 mA or 4 - 20 mA. The 4 - 20 mA range is often used so that an output current is still present when the measured value falls to zero. This is to give a fail safe indication and may be used to distinguish between the analog transducer output becoming faulty and the measurement falling to zero.
The Maximum and Minimum settings allow the user to enter the measuring range for each analog output. The range, step size and unit corresponding to the selected parameter are shown in the Operating chapter. This allows the user to “zoom in” and monitor a restricted range of the measurements with the desired resolution.
Page (AP) 6-68 P341/EN AP/G74
Application of Individual Protection Functions (AP) 6 Application Notes
For voltage, current and power quantities, these settings can be set in either primary or secondary quantities, depending on the CLO1/2/3/4 Set Values - Primary/Secondary setting associated with each current loop output.
The relationship of the output current to the value of the measurand is of vital importance and needs careful consideration. Any receiving equipment must, of course, be used within its rating but, if possible, some kind of standard should be established.
One of the objectives must be to have the capability to monitor the voltage over a range of values, so an upper limit must be selected, typically 120%. However, this may lead to difficulties in scaling an instrument.
The same considerations apply to current transducers outputs and with added complexity to watt transducers outputs, where both the voltage and current transformer ratios must be taken into account.
Some of these difficulties do not need to be considered if the transducer is only feeding, for example, a SCADA outstation. Any equipment which can be programmed to apply a scaling factor to each input individually can accommodate most signals. The main consideration will be to ensure that the transducer is capable of providing a signal right up to the full-scale value of the input, that is, it does not saturate at the highest expected value of the measurand.
P341/EN AP/G74 Page (AP) 6-69
(AP) 6 Application Notes
2.22
2.22.1
Application of Individual Protection Functions
Dynamic Line Rating (DLR) Protection (49DLR)
To meet the environmental targets laid down by governments, the distribution network is changing quickly from passive into active with a large amount of Distributed Generation
(DG) such as wind farms being connected to the network.
Wind farms tend to be located at the extremes of the distribution system where overhead lines may not be rated to carry the full output of the wind farm in all circumstances. Often a line has been designed originally to supply a relatively small load, and the installation of new wind generation may cause a large reverse power flow, causing the standard winter and summer line ratings to be exceeded. The worst case in this respect is with maximum wind generation and minimum local load. Rather than applying fixed summer and winter line ratings, load management based on a dynamically derived line rating can be adopted. This takes into account the cooling effect of the wind. Such a dynamic line rating enhancement could facilitate connection of up to 30% more generation as compared to when fixed winter/summer ratings are applied and help avoid costly network reinforcement. There are also benefits for the windfarm owner if there is a constraint on the lines in that the owner can make higher revenues with higher allowable generation connected with dynamic thermal protection than using the fixed summer/winter line ratings.
Dynamic Line Rating (DLR) Method (49 DLR)
The thermal rating, also referred to as ampacity, of an overhead line is the maximum current that a circuit can carry without exceeding it’s sag temperature or the annealing onset temperature of the conductor, whichever is lower. The sag temperature is that temperature at which the legislated height of the phase conductor above ground is met.
The present practice in many utilities is to monitor the power flow in overhead lines without knowledge of the actual conductor temperature or the height of the conductor above ground. There are many variables affecting the conductor temperature, such as wind speed and direction, ambient temperature and solar radiation. As these are difficult to predict, conservative assumptions have been made so far to always ensure public safety. The main purpose of ral time line monitoring is to achieve a better utilization of the load current capacity of overhead lines while ensuring the regulatory clearances above ground are always met. Different real time line monitoring methods have been applied and evaluated as described in various publications. There are fundamentally two different ways to derive ampacity dynamically. One is by direct measurement using sensors to determine the tension, conductor temperature, or sag. Alternatively, an indirect method can be used, by measuring ambient weather conditions, from which the ampacity can be calculated by solving standard equations in real time which is implemented in the
P341.
In the P341 DLR weather stations are employed to derive ampacity for use in the load management and back-up protection systems. Various computational methods have been developed in the past to calculate the heat transfer and ampacities of the conductors. Engineering Recommendation P27 which is based on Price’s experimental work and statistical method has been applied commonly in the UK to calculate fixed line ratings for spring/autumn, winter or summer. The ER P27 current ratings are based on the following weather conditions: wind speed 0.5 m/s, ambient temperature: winter 2°C, spring/autumn 9°C, summer 20°C and solar radiation 0 W. The two most commonly used international standards are the CIGRE 207 standard and the IEEE 738 standard for the current-temperature relationship of the line. Both the CIGRE 207 standard and the IEEE
738 algorithms are implemented in the P341 Dynamic Line Rating protection to derive the ampacity from the weather measurements.
Comparing the IEEE and the CIGRE standards the difference in the ampacity for the most common weather conditions is less than 1%. However, in some extreme situations the difference is as high as 8.5%. The IEEE method generally calculates slightly lower
Page (AP) 6-70 P341/EN AP/G74
Application of Individual Protection Functions (AP) 6 Application Notes ampacity values except for high wind speeds and for wind directions essentially parallel to the line, see Figure 24, Figure 25, Figure 26 and Figure 27.
800
Ambient temperature – Ampacity, core temp. is 50ºC
(Emissivity) = 0.5, _s(Solar Absorptivity) = 0.5
V(Wind Velocity) = 2 m/s, (Effective Wind Angle) = 20º
S(Solar Radiation) = 1000 W/m 2 , He(Line elevation) = 0 m
CIGRE 207, 2002
IEEE 738, 2006
700
600
500
400
300
200
100
-20 -10 0 10
Ta - Ambient Temperature (°C)
20 30 40
P4447ENa
Figure 24 - Comparison of ambient temperature vs ampacity for IEEE and CIGRE standards
P341/EN AP/G74 Page (AP) 6-71
(AP) 6 Application Notes Application of Individual Protection Functions
Page (AP) 6-72
Figure 25 - Comparison of wind velocity vs ampacity for IEEE and CIGRE standards
P341/EN AP/G74
Application of Individual Protection Functions (AP) 6 Application Notes
Effective Wind Angle -- Ampacity, core temp. is 50°C
(Emissivity) = 0.5, _s(Solar Absorptivitity) = 0.5
Ta(Ambient Temperature) = 20°C, V(Wind Velocity) = 2m/s
S(Solar Radiation) = 1000W/m 2 , He(Line elevation) = 0m
600
550
500
450
400
350
CIGRE 207, 2002
IEEE 738, 2006
300
0 10 20 30 40 50
- Effective Wind Angle (°)
60 70 80 90
P4449ENa
Figure 26 - Comparison of wind angle vs ampacity for IEEE and CIGRE standards
P341/EN AP/G74 Page (AP) 6-73
(AP) 6 Application Notes Application of Individual Protection Functions
Page (AP) 6-74
Figure 27 - Comparison of solar radiation vs ampacity for IEEE and CIGRE standards
In the DLR protection in the P341 relay the ampacity is calculated in real time using the
CIGRE 207 or IEEE 738 equations. When the measured line current reaches a certain percentage of the dynamically calculated ampacity one of the 6 protection stages can be operated after a time delay. These stages can be used to provide control commands to the distributed generators to hold or reduce their power output. This may be done via the energy management control system or via the relay output contacts and a communications link to the distributed generator control system. If the control actions are not successful at reducing the ampacity, possibly due to a communications failure, as a back-up the protection relay can use one of the protection stages to trip out the distributed generation or line after a time delay. Figure 28 shows a simplified diagram of the measurements and outputs of a combined load management and protection system.
In this application the load management and protection relay are both calculating the line ampacity rating from the weather station inputs.
The time delays and trip levels of the 6 protection stages are settable in the relay to provide flexibility for coordination with the load management system and other protection.
The purpose of the protection stage time delays are:
P341/EN AP/G74
Application of Individual Protection Functions (AP) 6 Application Notes
To avoid spurious tripping during temporary network faults.
To provide a possible means of grading with other protection and grading of DG control actions.
Weather station
Anenometer Thermometer
Wind speed Ambient temperature
Line current
CT
2.22.2
P341/EN AP/G74
Load management
Protection relay
Power reduction
Commands to wind generators
Signal to circuit breaker tripping wind generators
Figure 28 - Overview of weather station measurements feeding the load management and protection system
P4451ENa
Example of Ampacity as a Function of Wind and Ambient Temperature
This example demonstrates how to match the CIGRE algorithm to the Engineering
Recommendation P27 for line current ratings. ER P27 is a widely used current rating guide for overhead lines operating in the UK electricity system, published by the Energy
Networks Association.
ER P27 recommends the following weather conditions:
Wind speed 0.5 m/s
Ambient temperature
Winter: 2°C
Spring/Autumn: 9°C
Summer: 20°C
Solar radiation: nil (on the basis that in the presence of sun there will always be a minimum amount of wind.)
The above conditions result in the current rating for LYNX conductor as shown in Table 5.
Conductor type
Design core temperature C
Summer
Current rating (A)
Spring/Autumn Winter
175 mm2 LYNX
(30+7/2.79 mm)
Table 5 - ER P27 recommended current ratings for LYNX conductor
To get the most precise match to ER27 for the current rating using the CIGRE algorithm, another two parameters are required, the effective wind angle and line emissivity (these
Page (AP) 6-75
(AP) 6 Application Notes Application of Individual Protection Functions are based on the assumption that the conductor is located at sea level, which is 0 metres elevation). The closest match to ER P27 for these two parameters can be calculated when the standard deviation is at a minimum value from iteration of these two parameters.
The best matching result is when the effective wind angle is 23 (iterated from 0 to 90 with step of 1 ) and the line Emissivity is 0.94 (iterated from 0 to 1 with step of 0.01) giving a minimum standard deviation value of 0.4009. The calculated results are shown in the table below.
Conductor type
175 mm2 LYNX
(30+7/2.79 mm)
Design core temperature ºC
Summer
Current rating (A)
Spring/Autumn Winter
Standard deviation
Table 6 - CIGRE calculated current ratings to match ER P27 for LYNX conductor
For the example Lynx conductor type overhead line the dynamic ampacity as a function of wind speed is shown in Figure 29 for four different ambient temperatures, which have been calculated using the CIGRE equations with the conditions described above.
Figure 29 shows that for most wind speeds and ambient temperatures, the ampacity is larger than the ER P27 summer/winter ratings, however with higher ambient temperature and lower wind speeds the calculated ampacity is actually lower. The ampacity exhibits very high values, but in practice limitations in the rating due to other components (e.g. cables, joints, switchgear) in the circuit need to be taken into account, which is shown by the grey area. In this example the maximum current rating of the circuit is 650 A.
Page (AP) 6-76
Figure 29 - Dynamic ampacity as a function of wind speed for different ambient temperatures (Ta). P27 winter and summer ratings are also included
P341/EN AP/G74
Application of Individual Protection Functions
2.22.3
(AP) 6 Application Notes
Setting Guidelines
In configuring the relay it is necessary to enter a range of conductor data parameters, which are required for the heating and cooling calculations (PJ, PC, Pr and PS). To assist the user, the relay stores the relevant parameters of 36 types of British conductors which can be selected using the Conductor Type setting. Other conductor types can be defined if Custom is selected for the conductor type and additional settings become visible to define the conductor - NonFerrous Layer , DC Resist per km , Overall
Diameter , Outer Layer Diam , TotalArea(mm sq), and TempCoefR x0.001
. For the relay to calculate the conductor temperature the total conductor heat capacity, mc , and
Line Direction parameters are required in addition. Other conductor configuration settings are also required to define the conductor toplogy and characteristics - Solar
Absorp , Line Emissivity , Line Elevation , Line Azimuth Min , Line Azimuth Max and T
Conductor Max . Explanations of these settings are provided in the Settings chapter,
P341/EN ST.
The Line Azimuth Min and Max settings indicates the direction of the line and is used to calculate PS and PC. If the line is in one direction then the Line Azimuth Min and Max settings are the same angle. If for example the mounting direction of the anemometer 0,
360 = North and if the Line Azimuth Min and Max settings are set identical to 0 or 180 or 360 for example this indicates a line running in the same direction in the North-South direction. With a multi-direction span of a transmission line, it may be unnecessary to specify the line’s azimuth because all possible angles could be evaluated for the entire line. In this situation, the Line Azimuth Min should be set to 0 and Line Azimuth Max should be set to 180 to indicate all ranges of the effective angles between the wind direction and the conductor. In this case the effective wind angle to the line is taken as the worst case = 0 . The line azimuth significantly influences the effective angle between the wind and conductor line, which is an important variable to calculate convective cooling PC.
The Ampacity Min and Ampacity Max settings are used for the calculated ampacity.
This setting is used to avoid over calculating of the line ampacity for the protection stages. In practice the rating of other components e.g. cables, joints and switchgear may limit the maximum ampacity. There is a Drop-off Ratio setting which should be set to prevent chattering of the outputs for small variations of the ampacity around the setting.
A drop-off ratio of 98%, the default value, will achieve this in most applications. For larger variations of the ampacity around the setting to maintain a more consistent trip signal the drop-off ratio can be decreased to a lower value.
If there are measurement sensors to measure the weather conditions - Ambient
Temperature, Wind Velocity, Wind Direction or Solar Radiation then these can be assigned to one of the 4 the current loop (transducer) inputs in the DLR Channel Settings or can be disabled. If no measurement device is available and the current loop inputs for the weather station inputs are disabled or if the current loop input fails then a default value can be set in the Channel Settings for the Ambient Temperature, Wind Velocity,
Wind Direction and Solar Radiation. In some conservative applications not all the weather sensors may be used to determine the ampacity of the line. In these applications the default fixed weather parameters could be based for example on conservative standards such as P27. This approach will not provide the biggest increase in line capacity but will provide some safety margin in applications where the weather parameters are varying widely along the protected line and may not be the worst case at the weather station position. From a DLR site trial it has been shown that that the weather parameters having a significant impact on the line rating, are in the order from lowest to highest: solar radiation, ambient temperature, wind speed and wind speed + wind angle.
Note Wind angle can be variable along the length of a line, depending on the topology of the land and so using wind angle as a measured variable parameter needs to be carefully considered.
P341/EN AP/G74 Page (AP) 6-77
(AP) 6 Application Notes Application of Individual Protection Functions
To allow for shielding or shading or different line elevation affects or to give some safety margin for the measured weather parameters the ambient temperature, wind velocity, wind direction and solar radiation correction factor settings ( Ambient T Corr , Wind Vel
Corr , Wind Dir Corr and Solar Rad Corr ) can be used. As the weather station may not be sited near the most critical span or the worst case point for weather conditions then the correction factors can be used to correct the weather parameters used by the relay to allow for this.
For example the weather station elevation may not be at the same height as the conductors or the line may be at different heights above sea level along it’s length due to the varying topology of the land. Therefore there will be some variation of the ambient temperature with height above sea level which can be corrected for using the ambient temperature correction factor. Generally, the weather station will be mounted at a lower height than the conductors where the ambient temperature will be slightly lower so this gives some safety margin or can be corrected for using the correction setting. The lapse rate is defined as the rate of decrease with height for an atmospheric variable. The variable involved is temperature unless specified otherwise. The Environmental Lapse
Rate (ELR), is the rate of decrease of temperature with altitude in the stationary atmosphere at a given time and location. As an average, the International Civil Aviation
Organization (ICAO) defines an international standard atmosphere (ISA) with a temperature lapse rate of 6.49 K(°C)/1,000 m from sea level to 11 km. The standard atmosphere contains no moisture. Unlike the idealized ISA, the temperature of the actual atmosphere does not always fall at a uniform rate with height. For example, there can be an inversion layer in which the temperature increases with height.
Also, the wind speed will generally be higher at higher altitudes and also near coastal regions. There could also be sections of the line which are shielded from the wind for example in forest areas and wind speeds could be corrected for these applications using the wind speed correction factor.
The wind blows faster at higher altitudes because of the drag of the surface (sea or land) and the viscosity of the air. The variation in velocity with altitude, called wind shear, is most pronounced near the surface. Typically, in daytime the variation follows the 1/7th power law, which predicts that wind speed rises proportionally to the seventh root of altitude. In the night time, or when the atmosphere becomes stable, wind speed close to the ground usually subsides whereas at higher altitudes it does not decrease that much or may even increase. A stable atmosphere is caused by radiative cooling of the surface and is common in a temperate climate, it usually occurs when there is a (partly) clear sky at night. When the (high altitude) wind is strong (10 meter wind speed higher than approximately 6 to 7 m/s) the stable atmosphere is disrupted because of friction turbulence and the atmosphere will turn neutral. A daytime atmosphere is either neutral
(no net radiation; usually with strong winds and/or heavy clouding) or unstable (rising air because of ground heating -by the sun). Here again the 1/7th power law applies or is at least a good approximation of the wind profile.
Studies should be done to evaluate the worst case conditions for different spans of the line for the weather parameters to assess the best use of any correction factors.
The Maximum and Minimum settings (Ambient T Min/Max, Wind Vel Min/Max , Wind Dir
Min/Max , Solar Rad Min/Max) under the DLR Channel Settings allows the user to set low and high cut-off limits for the weather measurements that will be used by the DLR algorithm. If no limits are required then these settings can be set the same as the
Minimum and Maximum values for the current loop (transducer) inputs for the Ambient
Temperature, Wind Velocity, Wind Direction and Solar Radiation. These limits can be used to limit the weather sensor measurements to sensible values in case the sensors fail in such a way that they give an unrealistic value.
If the Wind Velocity, Wind Direction or Solar Radiation is changing quickly then the averaging time settings will help to smooth out the ampacity calculations. A typical setting for the averaging time is 10 minutes for these weather parameters. The conductor temperature will tend to follow the ambient temperature changes much more quickly than the cooling effect of the wind and heating effect of the current which have a thermal time
Page (AP) 6-78 P341/EN AP/G74
Application of Individual Protection Functions (AP) 6 Application Notes constant. Therefore, an averaging setting of 0 s is recommended for the ambient temperature. The averaging setting will impact the rate at which the ampacity is updated so this will affect the operating time of the protection and needs to be considered.
For the ambient temperature, wind velocity, wind direction and solar radiation the transducer (current loop input) type can be selected from four types with ranges 0-1 mA,
0-10 mA, 0-20 mA or 4-20 mA. The current loop input maximum and minimum settings
( Amb T Min/Max , WV I/P Minimum/Maximum , WD I/P Minimum/Maximum , SR I/P
Minimum/Maximum ) allow the user to enter the measurement range capability of the physical quantity measured by the transducer.
For the 4-20 mA inputs a current level below 4 mA indicates that there is a fault with the transducer or the wiring. An instantaneous undercurrent alarm element is available with a setting range 0-4 mA. This element controls an output signal (Amb T Fail Alm, Wind V
Fail Alm, Wind D Fail Alm, Solar R Fail Alm, DDB 396-399) which can be mapped to a user defined alarm if required.
There are a total of 6 trip elements, all of which will have their own threshold level as a percentage of the line ampacity and definite time delay settings. There is also an inhibit input for each protection element, which can be used to inhibit its operation in case of failures of the weather station or to inhibit one relay if another has operated first and is taking some action. These trip stages can be used to provide alarms and commands to the generation directly to HOLD or REDUCE or STOP at specific levels of ampacity below the trip level. Alternatively, they can be used for indication or alarms if a separate load management system is providing control to the generation. If the control actions are not successful at reducing the ampacity and the ampacity reaches a critical level for example
100%, possibly due to a communications failure, as a back-up the relay can use one of protection stages to trip out the distributed generation or line after a time delay. The time delay settings are used to avoid spurious tripping during transient network faults and allow discrimination with other protection functions and are also used to provide coordination with the load management system to allow time for the wind farm to take action before another DLR stage operates.
P341/EN AP/G74 Page (AP) 6-79
(AP) 6 Application Notes
3
3.1
3.1.1
Application of Non-Protection Functions
APPLICATION OF NON-PROTECTION FUNCTIONS
Check Synchronisation
Basic Principle
If a circuit breaker is closed when the generator and bus voltages are both live, with a large phase angle, frequency or magnitude difference between them, the system could be subjected to an unacceptable shock, resulting in loss of stability, and possible damage to the connected generator and generator-transformer.
System checks involve monitoring the voltages on both sides of a circuit breaker, and if both sides are live, performing a synchronism check to determine whether the phase angle, frequency and voltage magnitude differences between the voltage vectors, are within permitted limits.
The pre-closing system conditions for a given circuit breaker depend on the system configuration and for auto-reclosing depend on the selected auto-reclose program. For example, on a feeder with delayed auto-reclosing, the circuit breakers at the two line ends are normally arranged to close at different times. The first line end to close usually has a live bus and a dead line immediately before reclosing, and charges the line (dead line charge) when the circuit breaker closes. The second line end circuit breaker sees live bus and live line after the first circuit breaker has re-closed. If there is a parallel connection between the ends of the tripped feeder, they are unlikely to go out of synchronism, i.e. the frequencies will be the same, but the increased impedance could cause the phase angle between the two voltages to increase. Therefore the second circuit breaker to close might need a synchronism check, to ensure that the phase angle has not increased to a level that would cause an unacceptable shock to the system when the circuit breaker closes.
If there are no parallel interconnections between the ends of the tripped feeder, the two systems could lose synchronism, and the frequency at one end could slip relative to the other end. In this situation, the second line end would require a synchronism check comprising both phase angle and slip frequency checks.
If the second line end busbar has no power source other than the feeder that has tripped; the circuit breaker will see a live line and dead bus assuming the first circuit breaker has re-closed. When the second line end circuit breaker closes the bus will charge from the live line (dead bus charge).
For generator applications before closing the CB the frequency and voltage from the machine is varied automatically or manually until the generator voltage is in synchronism with the power system voltage. A check synchronizing relay is used to check the generator voltage is in synchronism with the system voltage in terms of voltage magnitude, voltage difference, phase angle and slip frequency before the generator CB is allowed to close.
Figure 30 - Typical connection between system and generator-transformer unit
Page (AP) 6-80 P341/EN AP/G74
Application of Non-Protection Functions
3.1.2
3.1.3
3.1.3.1
(AP) 6 Application Notes
VT Selection
The P341 has a three-phase Main VT input and a single-phase Check Sync VT input.
Depending on the primary system arrangement, the main three-phase VT for the relay may be located on either the busbar side or the generator side of the circuit breaker, with the Check Sync VT being located on the other side. Hence, the relay has to be programmed with the location of the main VT. This is done via the Main VT Location -
Gen/Bus setting in the SYSTEM CONFIG menu. This is required for the voltage monitors to correctly define the Live Gen/Dead Gen and Live Bus/Dead Bus DDBs.
The Check Sync VT may be connected to either a phase to phase or phase to neutral voltage, and for correct synchronism check operation, the relay has to be programmed with the required connection. The C/S Input setting in the CT & VT RATIOS menu should be set to A-N, B-N, C-N, A-B, B-C or C-A as appropriate.
The P341 (40TE case) uses the neutral voltage input, VNeutral, for the Check Synch VT and so the user can not use check synch and measured neutral voltage (59N) protection
(VN>3, VN>4) at the same time. The derived neutral voltage protection (VN>1, VN>2) from the 3 phase voltage input can still be used with the check synchronizing function.
The P341 (60TE case) uses a dedicated V Check Sync voltage input for the Check
Synch VT and so there are no restrictions in using the check synchronising function and other protection functions in the relay.
Voltage and Phase Angle Correction
CS VT Ratio Correction
Differences in the busbar voltage and the generator voltage magnitude may be introduced by unmatched or slightly erroneous voltage transformer or step-up transformer ratios. These differences should be small, but they may be additive and therefore be significant. In order to compensate magnitude differences between the busbar voltage and the generator voltage the generator voltage can be adjusted by a multiplying factor,
C/S V Ratio Corr to correct for any mismatch.
The voltage correction factor can be calculated as shown below:
TVR x VTG
VTB
Where:
TVR = step-up transformer voltage ratio (HV nominal /LV nominal)
VTG = generator voltage transformer ratio ( Main VT Primary/Main VT Sec’y )
VTB = busbar voltage transformer ratio ( C/S VT Prim’y/C/S VT Sec’y )
For example,
IF TVR = 38.5 kV /10.5 kV, VTG = 10 kV/100 V, VTB = 35 kV/100 V AND Vgen = VGab,
Vbus = VBab
Then, Vgen = 10500/100 = 105 V (secondary voltage), Vbus = 38500/350 = 110 V, and:
TVR x VTG
C/S V Ratio Corr = VTB = 1.0476
So: Vgen’ = Vgen x C/S V Corr = 110 V = Vbus
P341/EN AP/G74 Page (AP) 6-81
(AP) 6 Application Notes
3.1.3.2
Application of Non-Protection Functions
CS VT Vector Correction
If the generator CB is on the HV side the generator step-up transformer typically with the synch VT on the transformer HV side, the P34x uses the Main VT Vect Grp setting to compensate the phase shift between the generator VTs and the synch VT introduced by the transformer connections:
Here, N = Main VT Vector Group, N = 0, 1,…11.
The generator voltage, Vgen, compensated phase shift is . In most cases, N is
1, 11 and 0, and the corresponding compensated phase shift is +30°, -30° (330°) and 0°.
The vector group (N) is 0 for the Main VT and synch VT on the generator side of the transformer or if there is no step-up transformer.
For example, when the step-up transformer connection type is Yd11, the LV Clock Vector is at 11 o’clock, the connection and vector diagrams are as below. Usually, the Main VT is on the generator LV side of the transformer so the Main VT Vect Grp matches the vector group of the transformer, eg Main VT Vect Grp = 11 for a Yd11 transformer.
Va’ VA’
Vab
Vca
Va
Vb
*
*
Vb’ VB’
*
*
VA
VB
VAB
VCA
Vbc
Vc
*
Vc’ VC’
*
VC
VBC
VN P4005ENa
Figure 31 - Typical connection between system and generator-transformer unit
Transformer connection
3.1.4
Page (AP) 6-82
Figure 32 - Transformer vector diagram
It can been seen that , The vector is forward to 30º,so the compensated phase shift should be -30°, that is vector should be rotated 30° clockwise, Main VT Vect Grp = 11, assuming Main VT is on transformer LV side.
Voltage Monitors
The P341 System Checks function includes voltage monitors to indicate if the generator and system busbar voltages are Live or Dead. The voltage monitor signals are not usually used for the closing logic of a generator CB, the check synch logic is generally only used for this application. The voltage monitor signals are typically used in feeder
P341/EN AP/G74
Application of Non-Protection Functions
3.1.5
3.1.5.1
(AP) 6 Application Notes autoreclose applications where the first feeder CB to close may use the voltage monitor signals to check for Live Bus/Dead Line for example. The default settings are typical values, Dead = 0.2 Vn and Live = 0.5 Vn.
The voltage monitor DDBs, if required, are combined in the PSL to provide the manual
CB close check synchronizing logic, eg Dead Line/Live Gen (The P341 does not include autoreclose logic). The DDBs are connected to the Man Check Synch DDB (1362) which provides an input to the CB control logic to indicate a manual check synchronizing condition is satisfied.
The voltage monitor signals can be useful in generator applications to give indication if the generator or system busbar voltages are Live or Dead or can be used with timers in the PSL to provide additional under/overvoltage protection.
When Vgen magnitude is > Live Voltage, the generator is taken as Live (DDB 1328, Live
Gen)
When Vgen magnitude is < Dead Voltage, the generator is taken as Dead (DDB 1329,
Dead Gen)
When Vbus magnitude is > Live Voltage, the busbar is taken as Live (DDB 1330, Live
Bus)
When Vbus magnitude is < Dead Voltage, the busbar is taken as Dead (DDB 1331, Dead
Bus)
Check Synchronization
The P341 System Checks function includes 2 check synchronization elements, Check
Sync 1 and Check Sync 2. The check synch 1 OK (1332) and Check Synch 2 OK (1333)
DDBs, if required, are used in the PSL to provide the manual CB close check synchronising logic. The DDBs are connected to the Man Check Synch DDB (1362) which provides an input to the CB control logic to indicate a manual check synchronising condition is satisfied.
Each check synch element checks that the generator frequency, voltage magnitude, and phase angle match the system frequency, voltage magnitude, and phase angle before allowing the generator breaker to be closed. Each element includes settings for the phase angle difference and slip frequency between the generator and system busbar voltages.
The P341 also includes independent under/over voltage monitors for the generator and system side of the CB as well as a differential voltage monitor applicable to both the
Check Sync 1 and 2 elements. The user can select a number of under/over/differential voltage check synchronizing blocking options using the setting CS Voltage Block -
None , V< , V> , Vdiff> , V< and V> , V< and Vdiff> , V> and Vdiff> , V< V> Vdiff> .
Slip Control
The slip frequency used by Check Synch 1/2 can be calculated from the CS1/2 Phase
Angle and CS1/2 Slip Timer settings as described below or can be measured directly from the frequency measurements, slip frequency = |Fgen-Fbus|. The user can select a number of slip frequency options using the settings CS1 Slip Control - None , Timer
Only , Frequency Only , Both and CS2 Slip Control - None , Timer , Frequency , Timer
+ Freq , Freq + CB Comp .
If Slip Control by Timer or Frequency + Timer/Both is selected, the combination of CS
Phase Angle and CS Slip Timer settings determines an effective maximum slip frequency, calculated as:
2 x A
T x 360 Hz. for Check Sync. 1,
or
P341/EN AP/G74 Page (AP) 6-83
(AP) 6 Application Notes
3.1.5.2
Application of Non-Protection Functions
A
T x 360 Hz. for Check Sync. 2
A =
T =
Phase Angle setting ( )
Slip Timer setting (seconds)
For example, for Check Sync 1 with CS 1 Phase Angle setting 30 and CS 1 Slip Timer setting 3.3 sec., the “slipping” vector has to remain within 30 of the reference vector for at least 3.3 seconds. Therefore, a synchronism check output will not be given if the slip is greater than 2 x 30 in 3.3 seconds. Using the formula: 2 x 30 (3.3 x 360) = 0.0505 Hz
(50.5 mHz).
For Check Sync 2, with CS2 Phase Angle setting 10 and CS2 Slip Timer setting 0.1 sec., the slipping vector has to remain within 10 of the reference vector, with the angle decreasing, for 0.1 sec. When the angle passes through zero and starts to increase, the synchronism check output is blocked. Therefore an output will not be given if slip is greater than 10 in 0.1 second. Using the formula: 10 (0.1 x 360) = 0.278 Hz (278 mHz).
Slip control by Timer is not practical for “large slip/small phase angle” applications, because the timer settings required are very small, sometimes < 0.1 s. For these situations, slip control by Frequency is recommended.
If CS Slip Control by Frequency + Timer (CS1) or Both (CS2) is selected, for an output to be given, the slip frequency must be less than BOTH the set CS1/2 Slip Freq value and the value determined by the CS1/2 Phase Angle and CS1/2 Slip Timer settings.
CB closing time compensation
The CS2 Slip Control - Freq + Comp (Frequency + CB Time Compensation) setting modifies the Check Sync 2 function to take account of the circuit breaker closing time. By measuring the slip frequency, and using the CB Close Time setting, the relay will issue the close command so that the circuit breaker closes at the instant the slip angle is equal to the CS2 Phase Angle setting.
The equation below describes the relationship between the compensated angle and the lead time to CB closing for the circuit breaker to close at the instant the slip angle is equal to the CS2 phase angle setting, assuming the slip frequency is constant.
= Mea.Angle
= slip angle velocity
= compensated angle
= lead time to CB close
Page (AP) 6-84 P341/EN AP/G74
Application of Non-Protection Functions (AP) 6 Application Notes
Figure 33 - Check synch. 2 phase angle diagram
Unlike Check Sync 1, Check Sync 2 only permits closure for decreasing angles of slip, therefore the circuit breaker should always close within the limits defined by Check Sync
2. When CS2 phase angle = 0, the breaker should be closed just when the voltages are in phase with each other.
The CB Close Time measurement is available in the CB Condition menu for the last CB close. The relay calculates the CB Close Time from the time the close command is given to the time the CB is closed as indicated by the 3 pole dead logic. The CB close
Time measurement can be useful when setting the CB Close Time compensation setting in the System Checks menu.
3.1.5.3
P341/EN AP/G74
Figure 34 - Check synch. 2 functional diagram
Check Sync 2 and System Split
Check Sync 2 and system split functions are included for situations where the maximum permitted slip frequency and phase angle for synchronism check can change according to actual system conditions. A typical application is on a closely interconnected system, where synchronism is normally retained when a given feeder is tripped, but under some circumstances, with parallel interconnections out of service, the feeder ends can drift out of synchronism when the feeder is tripped. Depending on the system and machine characteristics, the conditions for safe circuit breaker closing could be, for example:
Condition 1: For synchronized systems, with zero or very small slip:
Page (AP) 6-85
(AP) 6 Application Notes
3.1.5.4
Application of Non-Protection Functions
Slip
Condition 2: For unsynchronized systems, with significant slip:
Slip and decreasing
By enabling both Check Sync 1, set for condition 1, and Check Sync 2, set for condition
2, the P34x can be configured to allow CB closure if either of the two conditions is detected.
For manual circuit breaker closing with synchronism check, some utilities might prefer to arrange the logic to check initially for condition 1 only. However, if a System Split is detected before the condition 1 parameters are satisfied, the relay will switch to checking for condition 2 parameters instead, based on the assumption that a significant degree of slip must be present when system split conditions are detected. This can be arranged by suitable PSL logic, using the system check DDB signals.
Generator Check Synchronizing
For generator CB closing applications generally there is only one synchronism check element required and so Check Sync 1 or Check Sync 2 is used.
The Check Sync 2 element includes CB closing time compensation and unlike Check
Sync 1, Check Sync 2 only permits closure for decreasing angles of slip.
There are several synchronizing methods that may be used to minimize the possibility of damaging a generator when closing the generator CB:
Automatic
Semi-automatic
Manual
Synchronizing check relays are often applied with all these schemes to supervise the closing of the CB.
To avoid damaging a generator during synchronizing, the generator manufacturer will generally provide synchronizing limits in terms of breaker closing angle and voltage matching. Typical limits are:
1. Breaker closing angle: ±10 electrical degrees. The closing of the circuit breaker should ideally take place when the generator and the system are at or close to zero degrees phase angle with respect to each other. To accomplish this, the breaker should be set to close in advance of the phase angle coincidence taking into account the breaker closing time.
2. Voltage matching: 0% to +5%. The voltage difference should be minimized and not exceed 5%. This aids in maintaining system stability by ensuring some VAR flow into the system. Additionally, if the generator voltage is excessively lower than the grid when the breaker is closed, sensitive reverse power relays may trip.
3. Slip frequency: <0.067 Hz. The slip frequency should be minimized to the practical control/response limitations of the given prime mover. A large frequency difference causes rapid load pickup or excessive motoring of the machine. This could cause power swings on the system and mechanical torques on the machine. Additionally, if the machine is motored, sensitive reverse power relays may trip.
Slip frequency limits applied for certain machine types are based on the ruggedness of the turbine generator under consideration and the controllability of the turbine generator and MVA.
To prevent power flow from the system to the generator, some large steam turbine generators require that a low, positive slip be present when the generator breaker is closed. In contrast, Diesel generators may require that a zero or negative slip be
Page (AP) 6-86 P341/EN AP/G74
Application of Non-Protection Functions
3.1.6
(AP) 6 Application Notes present to unload the machine shaft and crank briefly when the generator breaker is closed. The DDBs CS1/2 Slipfeq>, CS1/2 Slipfeq<, CS Ang Rot ACW and CS
Ang Rot CW can be used as interlocking signals to the ManCheck Synch DDB for these applications.
Frequency/Voltage Control
The DDBs, CS Vgen>Vbus, CS Vgen<Vbus, CS1 Fgen>Fbus, CS1 Fgen<Fbus, CS2
Fgen>Fbus and CS2 Fgen<Fbus can be used for simple frequency control and voltage control outputs or for indication purposes. Pulsed outputs can be achieved using PSL if required.
Figure 35 - Freq/Volt control functional diagram
P341/EN AP/G74 Page (AP) 6-87
(AP) 6 Application Notes
3.2
3.2.1
Application of Non-Protection Functions
VT Supervision (VTS)
The Voltage Transformer Supervision (VTS) feature is used to detect failure of the ac voltage inputs to the relay. This may be caused by internal voltage transformer faults, overloading, or faults on the interconnecting wiring to relays. This usually results in one or more VT fuses blowing. Following a failure of the ac voltage input there would be a misrepresentation of the phase voltages on the power system, as measured by the relay, which may result in mal-operation.
The VTS logic in the relay is designed to detect the voltage failure, and automatically adjust the configuration of protection elements whose stability would otherwise be compromised. A time-delayed alarm output is also available.
Setting the VT Supervision Element
The VTS Status setting Blocking/Indication determines whether the following operations will occur upon detection of VTS.
VTS set to provide alarm indication only.
Optional blocking of voltage dependent protection elements.
Optional conversion of directional overcurrent elements to non-directional protection (available when set to blocking mode only). These settings are found in the function links cell of the relevant protection element columns in the menu.
The VTS block will be latched after a user settable time delay VTS Time Delay . Once the signal has latched then two methods of resetting are available. The first is manually via the front panel interface (or remote communications) when the VTS Reset Mode is set to Manual . The second method is automatically when VTS Reset Mode is set to
Auto mode, provided the VTS condition has been removed and the 3 phase voltages have been restored above the phase level detector settings for more than 240 ms.
The VTS I> Inhibit overcurrent setting is used to inhibit the voltage transformer supervision in the event of a loss of all 3 phase voltages caused by a close up 3 phase fault occurring on the system following closure of the CB to energize the line. This element should be set in excess of any non-fault based currents on line energization
(load, line charging current, transformer inrush current if applicable) but below the level of current produced by a close up three-phase fault.
This VTS I2> Inhibit NPS overcurrent setting is used to inhibit the voltage transformer supervision in the event of a fault occurring on the system with negative sequence current above this setting
The NPS current pick-up threshold must be set higher than the negative phase sequence current due to the maximum normal load unbalance on the system. This can be set practically at the commissioning stage, making use of the relay measurement function to display the standing negative phase sequence current, and setting at least 20% above this figure.
Page (AP) 6-88 P341/EN AP/G74
Application of Non-Protection Functions
3.3
3.3.1
3.4
3.4.1
3.4.1.1
(AP) 6 Application Notes
CT Supervision (CTS)
The Current Transformer Supervision (CTS) feature is used to detect failure of one or more of the ac phase current inputs to the relay. Failure of a phase CT or an open circuit of the interconnecting wiring can result in incorrect operation of any current operated element. Additionally, interruption in the ac current circuits risks dangerous CT secondary voltages being generated.
Setting the Differential CTS Element
The residual voltage setting, CTS Vn< Inhibit and the residual current setting,
CTS In> set , should be set to avoid unwanted operation during healthy system conditions.
For example CTS Vn< Inhibit should be set to 120% of the maximum steady state residual voltage. The CTS In> set will typically be set below minimum load current. The time-delayed alarm, CTS Time Delay , is generally set to 5 seconds.
Where the magnitude of residual voltage during an earth fault is unpredictable, the element can be disabled to prevent a protection elements being blocked during fault conditions.
Circuit Breaker Condition Monitoring
Periodic maintenance of circuit breakers is necessary to ensure that the trip circuit and mechanism operate correctly, and also that the interrupting capability has not been compromised due to previous fault interruptions. Generally, such maintenance is based on a fixed time interval, or a fixed number of fault current interruptions. These methods of monitoring circuit breaker condition give a rough guide only and can lead to excessive maintenance.
Setting Guidelines
Setting the I^ Thresholds
Where overhead lines are prone to frequent faults and are protected by Oil Circuit
Breakers (OCBs), oil changes account for a large proportion of the life cycle cost of the switchgear. Generally, oil changes are performed at a fixed interval of circuit breaker fault operations. However, this may result in premature maintenance where fault currents tend to be low, and hence oil degradation is slower than expected. The I^ counter monitors the cumulative severity of the duty placed on the interrupter allowing a more accurate assessment of the circuit breaker condition to be made.
For OCBs, the dielectric withstand of the oil generally decreases as a function of
I2t. This is where ‘I’ is the fault current broken, and ‘t’ is the arcing time within the interrupter tank (not the interrupting time). As the arcing time cannot be determined accurately, the relay would normally be set to monitor the sum of the broken current squared, by setting Broken I^ = 2.
For other types of circuit breaker, especially those operating on higher voltage systems, practical evidence suggests that the value of Broken I^ = 2 may be inappropriate. In such applications Broken I^ may be set lower, typically 1.4 or 1.5. An alarm in this instance may be indicative of the need for gas/vacuum interrupter HV pressure testing, for example.
The setting range for Broken I^ is variable between 1.0 and 2.0 in 0.1 steps. It is imperative that any maintenance program must be fully compliant with the switchgear manufacturer’s instructions.
P341/EN AP/G74 Page (AP) 6-89
(AP) 6 Application Notes
3.4.1.2
3.4.1.3
3.4.1.4
Application of Non-Protection Functions
Setting the Number of Operations Thresholds
Every operation of a circuit breaker results in some degree of wear for its components.
Thus, routine maintenance, such as oiling of mechanisms, may be based upon the number of operations. Suitable setting of the maintenance threshold will allow an alarm to be raised, indicating when preventative maintenance is due. Should maintenance not be carried out, the relay can be set to lockout the auto-reclose function on reaching a second operations threshold. This prevents further reclosure when the circuit breaker has not been maintained to the standard demanded by the switchgear manufacturer’s maintenance instructions.
Certain circuit breakers, such as Oil Circuit Breakers (OCBs) can only perform a certain number of fault interruptions before requiring maintenance attention. This is because each fault interruption causes carbonizing of the oil, degrading its dielectric properties.
The maintenance alarm threshold No CB Ops Maint may be set to indicate the requirement for oil sampling for dielectric testing, or for more comprehensive maintenance.
Again, the lockout threshold No CB Ops Lock may be set to disable auto-reclosure when repeated further fault interruptions could not be guaranteed. This minimizes the risk of oil fires or explosion.
Setting the Operating Time Thresholds
Slow CB operation is also indicative of the need for mechanism maintenance. Therefore, alarm and lockout thresholds ( CB Time Maint./CB Time Lockout ) are provided and are settable in the range of 5 to 500 ms. This time is set in relation to the specified interrupting time of the circuit breaker.
Setting the Excessive Fault Frequency Thresholds
A circuit breaker may be rated to break fault current a set number of times before maintenance is required. However, successive circuit breaker operations in a short period of time may result in the need for increased maintenance. For this reason it is possible to set a frequent operations counter on the relay which allows the number of operations Fault Freq Count over a set time period Fault Freq Time to be monitored. A separate alarm and lockout threshold can be set.
Page (AP) 6-90 P341/EN AP/G74
Application of Non-Protection Functions
3.5
3.5.1
3.5.1.1
(AP) 6 Application Notes
Trip Circuit Supervision (TCS)
The trip circuit, in most protective schemes, extends beyond the relay enclosure and passes through components such as fuses, links, relay contacts, auxiliary switches and other terminal boards. This complex arrangement, coupled with the importance of the trip circuit, has led to dedicated schemes for its supervision.
Several Trip Circuit Supervision (TCS) schemes with various features can be produced with the P34x range. Although there are no dedicated settings for TCS, in the P34x, the following schemes can be produced using the Programmable Scheme Logic (PSL). A user alarm is used in the PSL to issue an alarm message on the relay front display. If necessary, the user alarm can be re-named using the menu text editor to indicate that there is a fault with the trip circuit.
TCS Scheme 1
Scheme Description
Figure 36 - TCS scheme 1
This scheme provides supervision of the trip coil with the breaker open or closed, however, pre-closing supervision is not provided. This scheme is also incompatible with latched trip contacts, as a latched contact will short out the opto for greater than the recommended DDO timer setting of 400 ms. If breaker status monitoring is required a further 1 or 2 opto inputs must be used.
Note A 52a CB auxiliary contact follows the CB position and a 52b contact is the opposite.
When the breaker is closed, supervision current passes through the opto input, blocking diode and trip coil. When the breaker is open current still flows through the opto input and into the trip coil via the 52b auxiliary contact.
P341/EN AP/G74 Page (AP) 6-91
(AP) 6 Application Notes
3.5.2
Application of Non-Protection Functions
Hence, no supervision of the trip path is provided whilst the breaker is open. Any fault in the trip path will only be detected on CB closing, after a 400 ms delay.
Resistor R1 is an optional resistor that can be fitted to prevent mal-operation of the circuit breaker if the opto input is inadvertently shorted, by limiting the current to <60 mA. The resistor should not be fitted for auxiliary voltage ranges of 30/34 volts or less, as satisfactory operation can no longer be guaranteed. The table below shows the appropriate resistor value and voltage setting ( OPTO CONFIG menu) for this scheme.
This TCS scheme will function correctly even without resistor R1, since the opto input automatically limits the supervision current to less that 10 mA. However, if the opto is accidentally shorted the circuit breaker may trip.
Auxiliary voltage (Vx) Resistor R1 (ohms)
24/27 -
30/34 -
Opto voltage setting with R1 fitted
-
-
110/250 2.5 48/54
220/250 5.0 110/125
Table 7 - Resistor values for TCS scheme 1
Note When R1 is not fitted the opto voltage setting must be set equal to supply voltage of the supervision circuit.
Scheme 1 PSL
Figure 37 shows the scheme logic diagram for the TCS scheme 1. Any of the available opto inputs can be used to indicate whether or not the trip circuit is healthy. The delay on drop off timer operates as soon as the opto is energized, but will take 400 ms to drop off/reset in the event of a trip circuit failure. The 400 ms delay prevents a false alarm due to voltage dips caused by faults in other circuits or during normal tripping operation when the opto input is shorted by a self-reset trip contact. When the timer is operated the NC
(normally closed) output relay opens and the LED and user alarms are reset.
The 50 ms delay on pick-up timer prevents false LED and user alarm indications during the relay power up time, following an auxiliary supply interruption.
Page (AP) 6-92
Figure 37 - PSL for TCS schemes 1 and 3
P341/EN AP/G74
Application of Non-Protection Functions
3.5.3
3.5.3.1
TCS Scheme 2
Scheme Description
(AP) 6 Application Notes
Figure 38 - TCS scheme 2
Much like scheme 1, this scheme provides supervision of the trip coil with the breaker open or closed and also does not provide pre-closing supervision. However, using two opto inputs allows the relay to correctly monitor the circuit breaker status since they are connected in series with the CB auxiliary contacts. This is achieved by assigning Opto A to the 52a contact and Opto B to the 52b contact. Provided the Circuit Breaker Status is set to 52a and 52b ( CB CONTROL column) and opto’s A and B are connected to CB
Aux 3ph (52a) (DDB 611) and CB Aux 3ph (52b) (DDB 612) the relay will correctly monitor the status of the breaker. This scheme is also fully compatible with latched contacts as the supervision current will be maintained through the 52b contact when the trip contact is closed.
When the breaker is closed, supervision current passes through opto input A and the trip coil. When the breaker is open current flows through opto input B and the trip coil. As with scheme 1, no supervision of the trip path is provided whilst the breaker is open. Any fault in the trip path will only be detected on CB closing, after a 400ms delay.
As with scheme 1, optional resistors R1 and R2 can be added to prevent tripping of the
CB if either opto is shorted. The resistor values of R1 and R2 are equal and can be set the same as R1 in scheme 1.
P341/EN AP/G74 Page (AP) 6-93
(AP) 6 Application Notes
3.5.4
Application of Non-Protection Functions
Scheme 2 PSL
The PSL for this scheme (Figure 39) is practically the same as that of scheme 1. The main difference being that both opto inputs must be off before a trip circuit fail alarm is given.
Figure 39 - PSL for TCS scheme 2
Page (AP) 6-94 P341/EN AP/G74
Application of Non-Protection Functions
3.5.5
3.5.5.1
TCS Scheme 3
Scheme Description
(AP) 6 Application Notes
3.5.6
Figure 40 - TCS scheme 2
Scheme 3 is designed to provide supervision of the trip coil with the breaker open or closed, but unlike schemes 1 and 2, it also provides pre-closing supervision. Since only one opto input is used, this scheme is not compatible with latched trip contacts. If circuit breaker status monitoring is required a further 1 or 2 opto inputs must be used.
When the breaker is closed, supervision current passes through the opto input, resistor
R2 and the trip coil. When the breaker is open current flows through the opto input, resistors R1 and R2 (in parallel), resistor R3 and the trip coil. Unlike schemes 1 and 2, supervision current is maintained through the trip path with the breaker in either state, thus giving pre-closing supervision.
As with schemes 1 and 2, resistors R1 and R2 are used to prevent false tripping, if the opto-input is accidentally shorted. However, unlike the other two schemes, this scheme is dependent upon the position and value of these resistors. Removing them would result in incomplete trip circuit monitoring. The table below shows the resistor values and voltage settings required for satisfactory operation.
Auxiliary voltage
(Vx)
Resistor R1 & R2
(ohms)
Resistor R3 (ohms) Opto voltage setting
48/54
110/250
220/250
1.2 k
2.5 k
5.0 k
Table 8 - Resistor values for TCS scheme 2
0.6 k
1.2 k
2.5 k
Note
24/27
48/54
110/125
Scheme 3 is not compatible with auxiliary supply voltages of 30/34 volts and below.
Scheme 3 PSL
The PSL for scheme 3 is identical to that of scheme 1 (see Figure ).
P341/EN AP/G74 Page (AP) 6-95
(AP) 6 Application Notes
3.6
3.6.1
3.6.2
Application of Non-Protection Functions
VT Connections
Open Delta (Vee-Connected) VTs
The P341 relay can be used with vee-connected VTs by connecting the VT secondaries to C19, C20 and C21 input terminals, with the C22 input left unconnected (see the
Installation chapter.
This type of VT arrangement cannot pass zero-sequence (residual) voltage to the relay, or provide any phase to neutral voltage quantities. Therefore any protection that is dependent on zero sequence voltage measurements should be disabled unless a direct measurement can be made via the measured VN input (C23 - C24). Therefore, neutral displacement protection, sensitive directional earth fault protection and CT supervision should be disabled unless the residual voltage is measured directly from the secondary of the earthing transformer or from a broken delta VT winding on a 5 limb VT.
The under and overvoltage protection can be set as phase to phase measurement with vee connected VTs. The power protection function uses phase-neutral voltage; used for detecting abnormal generator operation under a 3-phase balanced condition, therefore the 'neutral' point, although 'floating' will be approximately at the center of the three-phase voltage vectors.
The accuracy of single-phase voltage measurements can be impaired when using vee connected VT’s. The relay attempts to derive the phase to neutral voltages from the phase to phase voltage vectors. If the impedance of the voltage inputs were perfectly matched the phase to neutral voltage measurements would be correct, provided the phase to phase voltage vectors were balanced. However, in practice there are small differences in the impedance of the voltage inputs, which can cause small errors in the phase to neutral voltage measurements. This may give rise to an apparent residual voltage. This problem also extends to single-phase power measurements that are also dependent upon their respective single-phase voltages.
The phase to neutral voltage measurement accuracy can be improved by connecting 3, well matched, load resistors between the phase voltage inputs (C19, C20, C21) and neutral C22, thus creating a ‘virtual’ neutral point. The load resistor values must be chosen so that their power consumption is within the limits of the VT. It is recommended that 10 k 1% (6 W) resistors are used for the 110 V (Vn) rated relay, assuming the VT can supply this burden.
VT Single Point Earthing
The P34x range will function correctly with conventional three-phase VT’s earthed at any one point on the VT secondary circuit. Typical earthing examples being neutral earthing and yellow phase earthing.
Page (AP) 6-96 P341/EN AP/G74
Current Transformer Requirements
4
4.1
4.1.1
4.1.2
4.2
4.2.1
4.2.2
(AP) 6 Application Notes
CURRENT TRANSFORMER REQUIREMENTS
The current transformer requirements for each current input will depend on the protection function with which they are related and whether the line current transformers are being shared with other current inputs. Where current transformers are being shared by multiple current inputs, the kneepoint voltage requirements should be calculated for each input and the highest calculated value used.
The CT requirements for P341 are as shown below.
The current transformer requirements are based on a maximum prospective fault current of 50 times the relay rated current (In) and the relay having an instantaneous setting of 25 times rated current (In). The current transformer requirements are designed to provide operation of all protection 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 according to the formulae in the following sections.
Nominal rating Nominal output Accuracy class
1 A
5 A
2.5 VA
7.5 VA
10P
10P
Accuracy limited factor
20
20
Limiting lead resistance
1.3 ohms
0.11 ohms
Table 9 - CT requirements
Separate requirements for Restricted Earth Fault and reverse power protection are given in section 5.6 and 5.7.
Non-Directional Definite Time/IDMT Overcurrent & Earth Fault
Protection
Time-Delayed Phase Overcurrent Elements
V
K
≥ I cp
/2 * (R
CT
+ R
L
+ R rp
)
Time-Delayed Earth Fault Overcurrent Elements
V
K
≥ Icn/2 * (R
CT
+ 2R
L
+ R rp
+ R rn
)
Non-Directional Instantaneous Overcurrent & Earth Fault Protection
CT Requirements for Instantaneous Phase Overcurrent Elements
V
K
I sp
x (R
CT
+ R
L
+ R rp
)
CT Requirements for Instantaneous Earth Fault Overcurrent Elements
V
K
I sn
x (R
CT
+ 2R
L
+ R rp
+ R rn
)
P341/EN AP/G74 Page (AP) 6-97
4.3
4.3.1
4.3.2
4.4
4.4.1
4.4.2
4.5
4.5.1
4.5.2
4.5.3
4.5.4
4.5.5
(AP) 6 Application Notes Current Transformer Requirements
Directional Definite Time/IDMT Overcurrent & Earth Fault Protection
Time-Delayed Phase Overcurrent Elements
V
K
I cp
/2 * (R
CT
+ R
L
+ R rp
)
Time-Delayed Earth Fault Overcurrent Elements
V
K
I cn
/2 * (R
CT
+ 2R
L
+ R rp
+ R rn
)
Directional Instantaneous Overcurrent & Earth Fault Protection
CT Requirements for Instantaneous Phase Overcurrent Elements
V
K
I fp
/2 * (R
CT
+ R
L
+ R rp
)
CT Requirements for Instantaneous Earth Fault Overcurrent Elements
V
K
I fn
/2 * (R
CT
+ 2R
L
+ R rp
+ R rn
)
Non-Directional/Directional Definite Time/IDMT Sensitive Earth Fault
(SEF) Protection
Non-Directional Time Delayed SEF Protection (Residually Connected)
V
K
I cn
/2 * (R
CT
+ 2R
L
+ R rp
+ R rn
)
Non-Directional Instantaneous SEF Protection (Residually Connected)
V
K
I sn
x (R
CT
+ 2
RL
+ R rp
+ R rn
)
Directional Time Delayed SEF Protection (Residually Connected)
V
K
I cn
/2 x (R
CT
+ 2R
L
+ R rp
+ R rn
)
Directional Instantaneous SEF Protection (Residually Connected)
V
K
I fn
/2 * (R
CT
+ 2R
L
+ R rp
+ R rn
)
SEF Protection - as fed from a Core-Balance CT
Core balance current transformers of metering class accuracy are required and should have a limiting secondary voltage satisfying the formulae given below:
Directional/Non-Directional Time Delayed Element:
V
K
I cn
/2 * (R
CT
+ 2R
L
+ R
Directional Instantaneous Element: rn
)
V
K
I fn
/2 * (R
CT
+ 2R
Non-directional Element:
L
+ R rn
)
V
K
I sn
x (R
CT
+ 2R
L
+ R rn
)
Page (AP) 6-98 P341/EN AP/G74
Current Transformer Requirements
4.6
(AP) 6 Application Notes
Note In addition, it should be ensured that the phase error of the applied core balance current transformer is less than 90 minutes at 10% of rated current and less than 150 minutes at 1% of rated current.
I cp
=
I sn
=
I sp
=
R
CT
=
R
L
=
R rp
=
R rn
=
Abbreviations used in the previous formulae are explained below:
Where:
Required CT knee-point voltage (volts) V
K
=
I fn
=
I fp
=
I cn
=
Maximum prospective secondary earth fault current (amps)
Maximum prospective secondary phase fault current (amps)
Maximum prospective secondary earth fault current or 31 times
I> setting (whichever is lower) (amps)
Maximum prospective secondary phase fault current or 31 times
I> setting (whichever is lower) (amps)
Stage 2 & 3 earth fault setting (amps)
Stage 2 and 3 setting (amps)
Resistance of current transformer secondary winding (ohms)
Resistance of a single lead from relay to current transformer (ohms)
Impedance of relay phase current input at 30 In (ohms)
Impedance of the relay neutral current input at 30 In (ohms)
High Impedance Restricted Earth Fault Protection
The high impedance restricted earth fault element shall maintain stability for through faults and operate in less than 40 ms for internal faults provided the following equations are met:
R st
=
F (RCT + 2RL)
s
4 * Is * Rst V
K
Where:
V
K
R st
I f
V
K
I
S
R
(ohms)
L
=
R
CT
=
=
=
=
=
=
Required CT knee-point voltage (volts)
Value of stabilizing resistor (ohms)
Maximum secondary through fault current level (amps)
CT knee point voltage (volts)
Current setting of REF element (amps), (IREF Is)
Resistance of current transformer secondary winding (ohms)
Resistance of a single lead from relay to current transformer
Note Class x CT’s should be used for high impedance restricted earth fault applications.
P341/EN AP/G74 Page (AP) 6-99
(AP) 6 Application Notes
4.7
4.7.1
4.7.2
Current Transformer Requirements
Reverse and Low Forward Power Protection Functions
For both reverse and low forward power protection function settings greater than 3% Pn, the phase angle errors of suitable protection class current transformers will not result in any risk of mal-operation or failure to operate. However, for the sensitive power protection if settings less than 3% are used, it is recommended that the current input is driven by a correctly loaded metering class current transformer.
Protection Class Current Transformers
For less sensitive power function settings (>3%Pn), the phase current input of the P341 should be driven by a correctly loaded class 5P protection current transformer.
To correctly load the current transformer, its VA rating should match the VA burden (at rated current) of the external secondary circuit through which it is required to drive current.
Metering Class Current Transformers
For low Power settings (<3%Pn), the In Sensitive current input of the P341 should be driven by a correctly loaded metering class current transformer. The current transformer accuracy class will be dependent on the reverse power and low forward power sensitivity required. The table below indicates the metering class current transformer required for various power settings below 3%Pn.
To correctly load the current transformer, its VA rating should match the VA burden (at rated current) of the external secondary circuit through which it is required to drive current. Use of the P34x sensitive power phase shift compensation feature will help in this situation.
Reverse and low forward power settings %Pn
0.5
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
2.2
2.4
Metering CT class
0.1
0.2
0.5
2.6
2.8
3.0 1.0
Table 10 - Sensitive power current transformer requirements
Page (AP) 6-100 P341/EN AP/G74
Current Transformer Requirements
4.8
(AP) 6 Application Notes
Converting an IEC185 Current Transformer Standard Protection
Classification to a Kneepoint Voltage
The suitability of an IEC standard protection class current transformer can be checked against the kneepoint voltage requirements specified previously.
If, for example, the available current transformers have a 15 VA 5P 10 designation, then an estimated kneepoint voltage can be obtained as follows:
Vk =
VA x ALF
n
+ ALF x n x Rct
Where:
Vk
VA
=
=
ALF =
Required kneepoint voltage
Current transformer rated burden (VA)
Accuracy limit factor
I n
=
R ct
=
Current transformer secondary rated current (A)
Resistance of current transformer secondary winding ( )
If R ct is not available, then the second term in the above equation can be ignored.
Example: 400/5 A, 15 VA 5P 10, Rct = 0.2
Vk =
15 x 10
+ 10 x 5 x 0.2
5
P341/EN AP/G74 Page (AP) 6-101
(AP) 6 Application Notes
4.9
Current Transformer Requirements
Converting IEC185 Current Transformer Standard Protection
Classification to an ANSI/IEEE Standard Voltage Rating
The Px40 series protection is compatible with ANSI/IEEE current transformers as specified in the IEEE C57.13 standard. The applicable class for protection is class "C", which specifies a non air-gapped core. The CT design is identical to IEC class P, or
British Standard class X, but the rating is specified differently.
The ANSI/IEEE “C” Class standard voltage rating required will be lower than an IEC knee point voltage. This is because the ANSI/IEEE voltage rating is defined in terms of useful output voltage at the terminals of the CT, whereas the IEC knee point voltage includes the voltage drop across the internal resistance of the CT secondary winding added to the useful output. The IEC/BS knee point is also typically 5% higher than the ANSI/IEEE knee point.
Therefore:
Vc =
=
Where:
Vc =
[ Vk - Internal voltage drop ] / 1.05
[ Vk - (In . RCT . ALF) ] / 1.05
“C” Class standard voltage rating
Vk =
I n
=
R
CT
=
0.002
IEC Knee point voltage required
CT rated current = 5A in USA
CT secondary winding resistance (for 5 A CTs, the typical resistance is ohms/secondary turn)
ALF = The CT accuracy limit factor, the rated dynamic current output of a "C" class CT (Kssc) is always 20 x In
The IEC accuracy limit factor is identical to the 20 times secondary current ANSI/IEEE rating.
Therefore:
Vc = [ Vk - (100 . RCT ) ] / 1.05
Page (AP) 6-102 P341/EN AP/G74
AUXILIARY SUPPLY FUSE RATING
5
(AP) 6 Application Notes
AUXILIARY SUPPLY FUSE RATING
In the Safety section of this manual, the maximum allowable fuse rating of 16A is quoted.
To allow time grading with fuses upstream, a lower fuselink current rating is often preferable. Use of standard ratings of between 6 A and 16 A is recommended. Low voltage fuselinks, rated at 250 V minimum and compliant with IEC60269-2 general application type gG are acceptable, with high rupturing capacity. This gives equivalent characteristics to HRC "red spot" fuses type NIT/TIA often specified historically.
The table below recommends advisory limits on relays connected per fused spur. This applies to Px40 series devices with hardware suffix C and higher, as these have inrush current limitation on switch-on, to conserve the fuse-link.
Maximum number of Px40 relays recommended per fuse
Battery nominal voltage
6 A 10 A fuse 15 or 16 A fuse Fuse rating > 16 A
24 to 54 V
60 to 125 V
2
4
4
8
6
12
Not permitted
Not permitted
138 to 250 V 6 10 16 Not permitted
Table 11 - Maximum number of Px40 relays recommended per fuse
Alternatively, Miniature Circuit Breakers (MCB) may be used to protect the auxiliary supply circuits.
P341/EN AP/G74 Page (AP) 6-103
(AP) 6 Application Notes
Notes:
AUXILIARY SUPPLY FUSE RATING
Page (AP) 6-104 P341/EN AP/G74
MiCOM P341 (PL) 7 Programmable Logic
P341/EN PL/G74
PROGRAMMABLE LOGIC
CHAPTER 7
Page (PL) 7-1
(PL) 7 Programmable Logic
Hardware Suffix:
Software Version:
Connection Diagrams:
J (P341)
36 and 71 (with DLR)
10P341xx (xx = 01 to 12)
MiCOM P341
Page (PL) 7-2 P341/EN PL/G74
contents
CONTENTS
1 Programmable Scheme Logic (PSL)
GOOSE Output Signal Properties
Control Input Signal Properties
Function Key Properties (P343/4/5/6 only)
Fault Recorder Trigger Properties
Contact Conditioner Properties
2 Description of Logic Nodes
3 Default Programmable Scheme Logic (PSL)
Programmable LED Output Mapping
P341/EN PL/G74
(PL) 7 Programmable Logic
Page (PL) 7-
16
29
7
Page (PL) 7-3
(PL) 7 Programmable Logic Figures
4 P341 Programmable Scheme Logic (V36 Software)
5 P341 Programmable Scheme Logic (V71 Software)
FIGURES
Page (PL) 7-
Figure 3 - LED conditioner properties
Figure 7 - Opto Input Mappings (P341 V36)
Figure 8 - Output Relay R1, R2, R3 Mappings (P341 V36)
Figure 9 - Output Relay R4, R5, R6 and R7 (General Trip) Mappings (P341 V36) 34
Figure 10 - LEDs Mappings (3x Software) (P341 V36) 35
Figure 11 - Check Synch and Voltage Monitor Mappings (P341 V36) 36
Figure 12 - Opto Input Mappings (P341 V71)
Figure 13 - Output Relay R1, R2, R3 Mappings (P341 V71)
Figure 14 - Output Relay R4, R5, R6 and R7 (General Trip) Mappings (P341 V71) 39
Figure 15 - Output Relay Mappings (P341 V71)
Figure 16 - LEDs Mappings (3x Software) (P341 V71)
Figure 17 - Check Synch and Voltage Monitor Mappings (P341 V71)
TABLES
32
37
Table 1 - Description of available Logic Nodes
Page (PL) 7-
Page (PL) 7-4 P341/EN PL/G74
Tables
Table 3 - P341 opto inputs default mappings
Table 4 - P341 relay output contacts default mappings
Table 5 - P341 programmable LED default mappings
Table 6 - Default fault record initiation
(PL) 7 Programmable Logic
P341/EN PL/G74 Page (PL) 7-5
(PL) 7 Programmable Logic
Notes:
Tables
Page (PL) 7-6 P341/EN PL/G74
Programmable Scheme Logic (PSL)
1.1
1.2
(PL) 7 Programmable Logic
Overview
The purpose of the Programmable Scheme Logic (PSL) is to allow the relay user to configure an individual protection scheme to suit their own particular application. This is achieved through the use of programmable logic gates and delay timers.
The input to the PSL is any combination of the status of opto inputs. It is also used to assign the mapping of functions to the opto inputs and output contacts, the outputs of the protection elements, e.g. protection starts and trips, and the outputs of the fixed protection scheme logic. The fixed scheme logic provides the relay’s standard protection schemes. The PSL itself consists of software logic gates and timers. The logic gates can be programmed to perform a range of different logic functions and can accept any number of inputs. The timers are used either to create a programmable delay, and/or to condition the logic outputs, e.g. to create a pulse of fixed duration on the output regardless of the length of the pulse on the input. The outputs of the PSL are the LEDs on the front panel of the relay and the output contacts at the rear.
The execution of the PSL logic is event driven; the logic is processed whenever any of its inputs change, for example as a result of a change in one of the digital input signals or a trip output from a protection element. Also, only the part of the PSL logic that is affected by the particular input change that has occurred is processed. This reduces the amount of processing time that is used by the PSL; even with large, complex PSL schemes the relay trip time will not lengthen.
This system provides flexibility for the user to create their own scheme logic design.
However, it also means that the PSL can be configured into a very complex system, hence setting of the PSL is implemented through the PC support package S1 Studio.
S1 Studio Px40 PSL Editor
To start the Px40 PSL editor, either click the menu, select Tools > PSL PSL editor (Px40) .
icon or from the Micom S1 Studio main
The PSL Editor module enables you to connect to any device front port, retrieve and edit its PSL files and send the modified file back to a Px40 device.
P341/EN PL/G74
Figure 1 - PSL editor module
Page (PL) 7-7
(PL) 7 Programmable Logic
1.3
1.4
Programmable Scheme Logic (PSL)
How to use Px40 PSL Editor
With the Px40 PSL Module you can:
Start a new PSL diagram
Extract a PSL file from a Px40 IED
Open a diagram from a PSL file
Add logic components to a PSL file
Move components in a PSL file
Edit link of a PSL file
Add link to a PSL file
Highlight path in a PSL file
Use a conditioner output to control logic
Download PSL file to a Px40 IED
Print PSL files
For a detailed discussion on how to use these functions, please refer to S1 Studio Users
Manual.
Warnings
Checks are done before the scheme is sent to the relay. Various warning messages may be displayed as a result of these checks.
The Editor first reads in the model number of the connected relay, then compares it with the stored model number. A "wildcard" comparison is used. If a model mismatch occurs, a warning is generated before sending starts. Both the stored model number and that read-in from the relay are displayed along with the warning. However, the user must decide if the settings to be sent are compatible with the relay that is connected. Ignoring the warning could lead to undesired behavior in the relay.
If there are any potential problems of an obvious nature, a list is generated. The types of potential problems that the program attempts to detect are:
One or more gates, LED signals, contact signals, and/or timers have their outputs linked directly back to their inputs. An erroneous link of this sort could lock up the relay, or cause other more subtle problems to arise.
Inputs To Trigger (ITT) exceeds the number of inputs. A programmable gate has its
ITT value set to greater than the number of actual inputs; the gate can never activate.
Note There is no lower ITT value check. A 0-value does not generate a warning.
Too many gates. There is a theoretical upper limit of 256 gates in a scheme, but the practical limit is determined by the complexity of the logic. In practice the scheme would have to be very complex, and this error is unlikely to occur.
Too many links. There is no fixed upper limit to the number of links in a scheme.
However, as with the maximum number of gates, the practical limit is determined by the complexity of the logic. In practice the scheme would have to be very complex, and this error is unlikely to occur.
Page (PL) 7-8 P341/EN PL/G74
Programmable Scheme Logic (PSL)
1.5
1.5.1
1.5.2
1.5.3
1.5.4
1.5.5
1.5.6
1.5.7
1.5.8
(PL) 7 Programmable Logic
Toolbar and Commands
There are a number of toolbars available for easy navigation and editing of PSL.
Standard Tools
For file management and printing.
Alignment Tools
To align logic elements horizontally or vertically into groups.
Drawing Tools
To add text comments and other annotations, for easier reading of PSL schemes.
Nudge Tools
To move logic elements.
Rotation Tools
To spin, mirror and flip.
Structure Tools
To change the stacking order of logic components.
Zoom and Pan Tools
For scaling the displayed screen size, viewing the entire PSL, or zooming to a selection.
P341 Logic Symbols
This toolbar provides icons to place each type of logic element into the scheme diagram.
Not all elements are available in all devices. Icons will only be displayed for those elements available in the selected device.
P341/EN PL/G74 Page (PL) 7-9
(PL) 7 Programmable Logic Programmable Scheme Logic (PSL)
Link
Create a link between two logic symbols.
Signal
Create an opto signal.
Signal
Create an input signal.
Output
Create an output signal.
GOOSE In
Create an input signal to logic to receive an IEC 61850 GOOSE message transmitted from another IED.
Out
Create an output signal from logic to transmit an IEC 61850 GOOSE message to another
IED.
Control In
Create an input signal to logic that can be operated from an external command.
Function Key
Create a function key input signal.
Signal
Create a fault record trigger.
Signal
Create an LED input signal that repeats the status of tri-color LED.
Signal
Create an LED input signal that repeats the status of red LED.
Contact
Create a contact signal.
Conditioner
Create an LED conditioner.
Conditioner
Create a contact conditioner.
Timer
Create a timer.
AND Gate
Create an AND Gate.
Gate
Create an OR Gate.
Programmable
Create a programmable gate.
Page (PL) 7-10 P341/EN PL/G74
Programmable Scheme Logic (PSL)
1.6
1.6.1
1.6.2
PSL Logic Signals Properties
(PL) 7 Programmable Logic
Signal Properties Menu
The logic signal toolbar is used for the selection of logic signals. To use this:
Use the logic toolbar to select logic signals.
This is enabled by default but to hide or show it, select View > Logic Toolbar .
Zoom in or out of a logic diagram using the toolbar icon or select View > Zoom Percent .
Right-click any logic signal and a context-sensitive menu appears.
Certain logic elements show the Properties… option. Select this and a Component
Properties window appears. The Component Properties window and the signals listed vary depending on the logic symbol selected.
The following subsections describe each of the available logic symbols.
Link Properties
Links form the logical link between the output of a signal, gate or condition and the input to any element.
Any link that is connected to the input of a gate can be inverted. Right-click the input and select Properties… .
The Link Properties window appears.
1.6.3
Figure 2 - Link properties
Rules for Linking Symbols
An inverted link is shown with a small circle on the input to a gate. A link must be connected to the input of a gate to be inverted.
Links can only be started from the output of a signal, gate, or conditioner, and can only be ended on an input to any element.
Signals can only be an input or an output. To follow the convention for gates and conditioners, input signals are connected from the left and output signals to the right. The
Editor will automatically enforce this convention.
A link is refused for the following reasons:
An attempt to connect to a signal that is already driven. The cause of the refusal may not be obvious, since the signal symbol may appear elsewhere in the diagram.
Right-click the link and select Highlight to find the other signal. Click anywhere on the diagram to disable the highlight.
An attempt is made to repeat a link between two symbols. The reason for the refusal may not be obvious, because the existing link may be represented elsewhere in the diagram.
P341/EN PL/G74 Page (PL) 7-11
(PL) 7 Programmable Logic
1.6.4
1.6.5
1.6.6
1.6.7
1.6.8
Programmable Scheme Logic (PSL)
Opto Signal Properties
Each opto input can be selected and used for programming in PSL. Activation of the opto input drives an associated DDB signal.
For example activating opto input L1 will assert DDB 032 in the PSL.
Input Signal Properties
Relay logic functions provide logic output signals that can be used for programming in
PSL. Depending on the relay functionality, operation of an active relay function will drive an associated DDB signal in PSL.
For example, DDB 768 will be asserted in the PSL should the active earth fault 1, stage 1 protection operate/trip.
Output Signal Properties
Relay logic functions provide logic input signals that can be used for programming in
PSL. Depending on the relay functionality, activation of the output signal will drive an associated DDB signal in PSL and cause an associated response to the relay function.
For example, if DDB 548 is asserted in the PSL, it will block the sensitive earth function stage 1 timer.
GOOSE Input Signal Properties
The PSL interfaces with the GOOSE Scheme Logic using 32 virtual inputs. The Virtual
Inputs can be used in much the same way as the Opto Input signals.
The logic that drives each of the Virtual Inputs is contained within the relay’s GOOSE
Scheme Logic file. It is possible to map any number of bit-pairs, from any enrolled device, using logic gates onto a Virtual Input (see MiCOM S1 Studio Users Manual for more details).
For example, DDB 1408 will be asserted in PSL should virtual input 1 and its associated bit pair operate.
GOOSE Output Signal Properties
The PSL interfaces with the GOOSE Scheme Logic using of 32 virtual outputs. Virtual outputs can be mapped to bit-pairs for transmitting to any enrolled devices.
It is possible to map virtual outputs to bit-pairs for transmitting to any subscribed devices
(see S1 Users manual for more details).
For example if DDB 1696 is asserted in PSL, Virtual Output 32 and its associated mappings will operate.
Page (PL) 7-12 P341/EN PL/G74
Programmable Scheme Logic (PSL)
1.6.9
1.6.10
1.6.11
1.6.12
1.6.13
1.6.14
(PL) 7 Programmable Logic
Control Input Signal Properties
There are 32 control inputs which can be activated via the relay menu, ‘hotkeys’ or via rear communications. Depending on the programmed setting i.e. latched or pulsed, an associated DDB signal will be activated in PSL when a control input is operated.
For example operate control input 1 to assert DDB 1376 in the PSL.
Function Key Properties (P343/4/5/6 only)
Each function key can be selected and used for programming in PSL. Activation of the function key will drive an associated DDB signal and the DDB signal will remain active depending on the programmed setting i.e. toggled or normal. Toggled mode means the
DDB signal will remain latched or unlatched on key press and normal means the DDB will only be active for the duration of the key press.
For example operate function key 1 to assert DDB 256 in the PSL.
Fault Recorder Trigger Properties
The fault recording facility can be activated, by driving the fault recorder trigger DDB signal. For example assert DDB 623 to activate the fault recording in the PSL.
LED Signal Properties
All programmable LEDs will drive associated DDB signal when the LED is activated.
For example DDB 230 for red LED 7.
Contact Signal Properties
All relay output contacts will drive associated DDB signal when the output contact is activated. For example DDB 009 will be asserted when output R10 is activated.
LED Conditioner Properties
1. Select the LED name from the list (only shown when inserting a new symbol).
2. Configure the red LED output to be latching or non-latching
Figure 3 - LED conditioner properties
P341/EN PL/G74 Page (PL) 7-13
(PL) 7 Programmable Logic
1.6.15
Programmable Scheme Logic (PSL)
Contact Conditioner Properties
Each contact can be conditioned with an associated timer that can be selected for pick up, drop off, dwell, pulse, pick-up/drop-off, straight-through, or latching operation.
Straight-through means it is not conditioned in any way whereas Latching is used to create a sealed-in or lockout type function.
1.6.16
Figure 4 - Contact properties
1. Select the contact name from the Contact Name list (only shown when inserting a new symbol).
2. Choose the conditioner type required in the Mode tick list.
3. Set the Pick-up Time (in milliseconds), if required.
4. Set the Drop-off Time (in milliseconds), if required.
Timer Properties
Each timer can be selected for pick up, drop off, dwell, pulse or pick-up/drop-off operation.
Page (PL) 7-14
Figure 5 - Timer properties
5. Choose the operation mode from the Timer Mode tick list.
6. Set the Pick-up Time (in milliseconds), if required.
7. Set the Drop-off Time (in milliseconds), if required.
P341/EN PL/G74
Programmable Scheme Logic (PSL)
1.6.17
(PL) 7 Programmable Logic
Gate Properties
A Gate may be an AND, OR, or programmable gate.
An AND gate requires that all inputs are TRUE for the output to be TRUE.
An OR gate requires that one or more input is TRUE for the output to be TRUE.
A Programmable gate requires that the number of inputs that are TRUE is equal to or greater than its ‘Inputs to Trigger’ setting for the output to be TRUE.
, OR
Figure 6 - Gate properties
1. Select the Gate type AND, OR, or Programmable.
2. Set the number of inputs to trigger when Programmable Gate is selected.
3. Select if the output of the gate should be inverted using the Invert Output check box. An inverted output is indicated with a "bubble" on the gate output.
P341/EN PL/G74 Page (PL) 7-15
(PL) 7 Programmable Logic Description of Logic Nodes
2 DESCRIPTION OF LOGIC NODES
DDB no. English text
0
23
Output R1
(Output Label
Setting)
Output R24
(Output Label
Setting)
Source
Relay conditioner
Relay conditioner
24 to 31 Not Used
32
Input L1 (Input
Label Setting)
55
Opto Isolator Input
Input L24 (Input
Label Setting)
Opto Isolator Input
56 to 63 Not Used
64 Relay Cond 1 PSL
87 Relay Cond 24 PSL
88 to 223 Not Used
224
231
232
354
355
356
357
358
359
360
361
362
363
364
365
LED1
LED8
LED conditioner
LED conditioner
LED Cond IN 1 PSL
239 LED Cond IN 8 PSL
240 to 287 Not Used
288
303
Timer out 1
Timer out 16
Auxiliary Timer out
Auxiliary Timer out
304 to 319 Not Used
320 Timer in 1
335 Timer in 16
336 to 352 Not Used
353
PSL
PSL
F out of Range Frequency Tracking
SG-DDB Invalid Group Selection
Output Relay 1 is on
Output Relay 24 is on
Opto Input 1 is on
Opto Input 24 is on
Description
Input signal driving Relay 1 is on
Input signal driving Relay 24 is on
Programmable LED 1 is on
Programmable LED 8 is on
Input signal driving LED 1 is on
Input signal driving LED 8 is on
Output from Auxiliary Timer 1 is on
Output from Auxiliary Timer 16 is on
Input to Auxiliary Timer 1 is on
Input to Auxiliary Timer 16 is on
Frequency out of range. Frequency tracking range is 40-70 Hz.
Setting Group Selection DDB inputs have detected an invalid (disabled) settings group
Prot'n Disabled Commissioning Test Protection Disabled - typically out of service due to test mode
VT Fail Alarm VT Supervision VTS Indication alarm - failed VT (fuse blow) detected by VT supervision
CT-1 Fail Alarm CT Supervision CTS Indication Alarm for IA/IB/IC (CT supervision alarm).
CB Fail Alarm Breaker Fail
I ^ Maint Alarm CB Monitoring
Circuit Breaker Fail Alarm
Circuit Breaker cumulative broken current has exceeded the
Maintenance Alarm setting
I ^ Lockout
Alarm
CB Monitoring
CB Ops Maint. CB Monitoring
CB Ops Lockout CB Monitoring
CB Op Time
Maint.
CB Op Time
Lock
CB Monitoring
CB Monitoring
Fault Freq. Lock CB Monitoring
Circuit Breaker cumulative broken current has exceeded the
Maintenance Lockout setting
Number of Circuit Breaker trips has exceeded Maintenance Alarm setting
Number of Circuit Breaker trips has exceeded the Maintenance Lockout setting
Circuit Breaker operating time has exceeded Maintenance Alarm setting
(slow interruption time)
Circuit Breaker operating time has exceeded the Lockout Alarm setting
(too slow interruption)
Excessive Fault Frequency Lockout Alarm (too many trips in a set time)
Page (PL) 7-16 P341/EN PL/G74
Description of Logic Nodes (PL) 7 Programmable Logic
DDB no.
366
English text Source
CB Status Alarm CB Status
Description
Indication of a fault with the Circuit Breaker state monitoring - example defective auxiliary contacts
367
368
Man CB Trip
Fail
Man CB Cls.
Fail
CB Control
CB Control
Circuit Breaker failed to trip (after a manual/operator trip command)
Circuit Breaker failed to close (after a manual/operator close command)
369
Man CB
Unhealthy
CB Control
Manual Circuit Breaker Unhealthy output signal indicating that the circuit breaker has not closed successfully after a manual close command. (A successful close requires the Circuit Breaker Healthy signal to appear within the "healthy window" time)
370
371
Not Used
Gen Thermal
Alarm
372 to 378 Not Used
Thermal Alarm Thermal Alarm
379 Freq Prot Alarm PSL
380
Voltage Prot
Alarm
PSL
381 to 383 Not Used
384 CL Card I/P Fail Current Loop Inputs
385
386
387
388
389
CL Card O/P
Fail
CL Input 1
Alarm
CL Input 2
Alarm
CL Input 3
Alarm
CL Input 4
Alarm
Current Loop Outputs
Current Loop Inputs
Current Loop Inputs
Current Loop Inputs
Current Loop Inputs
F<1 Trip OR F<2 Trip OR F<3 Trip OR F>1 Trip (These DDB signals are mapped to Freq Prot Alarm in default PSL)
V<1 Trip OR V>1 Trip (These DDB signals are mapped to Voltage Prot
Alarm in default PSL)
Current Loop Input (transducer input) failure
Current Loop Output (transducer output) failure
Current Loop Input (transducer input) 1 alarm
Current Loop Input (transducer input) 2 alarm
Current Loop Input (transducer input) 3 alarm
Current Loop Input (transducer input) 4 alarm
390
391
392
393
396
397
398
399
CLI1 I< Fail Alm Current Loop Inputs
CLI2 I< Fail Alm Current Loop Inputs
CLI3 I< Fail Alm Current Loop Inputs
CLI4 I< Fail Alm Current Loop Inputs
394 to 395 Not Used
Amb T Fail Alm SW (P341 7x)
Wind V Fail Alm SW (P341 7x)
Wind D Fail Alm SW (P341 7x)
Solar R Fail Alm SW (P341 7x)
400 to 402 Not Used
Current Loop Input (transducer input) 1 undercurrent alarm (current is
<4 mA for
4-20 mA input)
Current Loop Input (transducer input) 2 undercurrent alarm (current is
<4 mA for
4-20 mA input)
Current Loop Input (transducer input) 3 undercurrent alarm (current is
<4 mA for
4-20 mA input)
Current Loop Input (transducer input) 4 undercurrent alarm (current is
<4 mA for
4-20 mA input)
Ambient Temperature Current Loop Input (transducer input) undercurrent alarm (current is <4 mA for 4-20 mA input)
Wind Velocity Current Loop Input (transducer input) undercurrent alarm
(current is <4 mA for 4-20 mA input)
Winf Direction Current Loop Input (transducer input) undercurrent alarm
(current is <4 mA for 4-20 mA input)
Solar Radiation Current Loop Input (transducer input) undercurrent alarm (current is <4 mA for 4-20 mA input)
P341/EN PL/G74 Page (PL) 7-17
(PL) 7 Programmable Logic
DDB no. English text
403
Man No
Checksync
Source
CB Control
404 System Split sys check
405
411
412
415
MR User Alarm
11
MR User Alarm
5
SR User Alarm
4
SR User Alarm
1
PSL
PSL
PSL
PSL
416 Battery Fail Self monitoring
417
418
419
420
421
Field Volts Fail Self monitoring
Rear Comms 2
Fail
InterMiCOM
GOOSE IED
Absent
UCA2
NIC Not Fitted UCA2
NIC No
Response
UCA2
NIC Fatal Error UCA2
NIC Soft Reload UCA2
422
423
424
425
426
427
Bad TCP/IP Cfg UCA2
Bad OSI Config UCA2
NIC Link Fail UCA2
NIC SW Mis-
Match
UCA2
428 IP Addr Conflict UCA2
429 to 543 Not Used
544
545
546
547
548
IN>1 Timer
Block
IN>2 Timer
Block
IN>3 Timer
Block
IN>4 Timer
Block
ISEF>1 Timer
Blk
PSL
PSL
PSL
PSL
PSL
549
550
ISEF>2 Timer
Blk
ISEF>3 Timer
Blk
PSL
PSL
551
ISEF>4 Timer
Blk
PSL
552to 575 Not Used
576 I>1 Timer Block PSL
Description of Logic Nodes
Description
Indicates that the check synchronism signal has failed to appear for a manual close
System split alarm - will be raised if the system is split (remains permanently out of synchronism) for the duration of the system split timer
User Alarm 11 (manual-resetting)
User Alarm 5 (manual-resetting)
User Alarm 4 (self-resetting)
User Alarm 1 (self-resetting)
Front panel miniature battery failure - either battery removed from slot, or low voltage.
48 V Field Voltage Failure
2nd Rear Comms Port Failure
The IED is not subscribed to a publishing IED in the current scheme.
Ethernet board not fitted
Ethernet board not responding
Ethernet board unrecoverable error
Ethernet board software reload alarm
Bad TCP/IP configuration alarm
Bad OSI configuration alarm
Ethernet link lost
Ethernet board software not compatible with main CPU
The IP address of the IED is already used by another IED
Block Earth Fault Stage 1 Time delayed trip
Block Earth Fault Stage 2 Time delayed trip
Block Earth Fault Stage 3 Time delayed trip
Block Earth Fault Stage 4 Time delayed trip
Block Sensitive Earth Fault Stage 1 Time delayed trip
Block Sensitive Earth Fault Stage 2 Time delayed trip
Block Sensitive Earth Fault Stage 3 Time delayed trip
Block Sensitive Earth Fault Stage 4 Time delayed trip
Block Phase Overcurrent Stage 1 Time delayed trip
Page (PL) 7-18 P341/EN PL/G74
Description of Logic Nodes
DDB no. English text
577
578
579
I>2 Timer Block PSL
I>3 Timer Block PSL
I>4 Timer Block PSL
580 to 581 Not Used
582 I2> Inhibit
583
584
585
I2>1 Timer
Block
I2>2 Timer
Block
I2>3 Timer
Block.
586
I2>4 Timer
Block
587 to 591 Not Used
PSL
PSL
PSL
PSL
PSL
592
593
594
595
VN>1 Timer
Block
VN>2 Timer
Block
VN>3 Timer
Block
VN>4 Timer
Block
PSL
PSL
PSL
PSL
596 to 597 Not Used
598 V>1 Timer Block PSL
599 V>2 Timer Block PSL
Source
601
602
V<1 Timer Block PSL
V<2 Timer Block PSL
603 to 625 Not Used
626 F<1 Timer Block PSL
627
628
629
630
631
F<2 Timer Block PSL
F<3 Timer Block PSL
F<4 Timer Block PSL
F>1 Timer Block PSL
F>2 Timer Block PSL
633
634
635
636
637 df/dt> Inhibit PSL df/dt>1 Tmr Blk PSL df/dt>2 Tmr Blk PSL df/dt>3 Tmr Blk PSL df/dt>4 Tmr Blk PSL
638 to 640 Not used
641
Reset
GenThermal
642
643
PSL
DLR I>1 Inhibit PSL (P341 7x)
DLR I>2 Inhibit PSL (P341 7x)
(PL) 7 Programmable Logic
Description
Block Phase Overcurrent Stage 2 Time delayed trip
Block Phase Overcurrent Stage 3 Time delayed trip
Block Phase Overcurrent Stage 4 Time delayed trip
Inhibit all Negative Sequence Overcurrent stages
Block Negative Sequence Overcurrent Stage 1 Time delayed trip
Block Negative Sequence Overcurrent Stage 2 Time delayed trip
Block Negative Sequence Overcurrent Stage 3 Time delayed trip
Block Negative Sequence Overcurrent Stage 4 Time delayed trip
Block Residual Overvoltage Stage 1 Time delayed trip
Block Residual Overvoltage Stage 2 Time delayed trip
Block Residual Overvoltage Stage 3 Time delayed trip
Block Residual Overvoltage Stage 4 Time delayed trip
Block Phase Overvoltage Stage 1 Time delayed trip
Block Phase Overvoltage Stage 2 Time delayed trip
Input to Accelerate Negative Sequence Overvoltage - (V2> Protection) instantaneous operating time
Block Phase Undervoltage Stage 1 Time delayed trip
Block Phase Undervoltage Stage 2 Time delayed trip
Block Underfrequency Stage 1 Time delayed trip
Block Underfrequency Stage 2 Time delayed trip
Block Underfrequency Stage 3 Time delayed trip
Block Underfrequency Stage 4 Time delayed trip
Block Overfrequency Stage 1 Time delayed trip
Block Overfrequency Stage 2 Time delayed trip
Inhibit df/dt Protection
Block df/dt Stage 1 Timer
Block df/dt Stage 2 Timer
Block df/dt Stage 3 Timer
Block df/dt Stage 4 Timer
Reset Thermal Overload State
Inhibit DLR Stage 1
Inhibit DLR Stage 2
P341/EN PL/G74 Page (PL) 7-19
(PL) 7 Programmable Logic
DDB no. English text
644
645
646
647
648
Source
DLR I>3 Inhibit PSL (P341 7x)
DLR I>4 Inhibit PSL (P341 7x)
DLR I>5 Inhibit PSL (P341 7x)
DLR I>6 Inhibit PSL (P341 7x)
DLR Scheme
Inh
PSL (P341 7x)
649 to 655 Not Used
656 CL1 Input 1 Blk PSL
657 CL1 Input 2 Blk PSL
658
659
CL1 Input 3 Blk PSL
CL1 Input 4 Blk PSL
660 to 671 Not Used
672 Fault REC TRIG PSL
674 Any Trip PSL
675 SG Select x1 PSL
676 SG Select 1x PSL
678
679
680
681
682
Init Trip CB PSL
Init Close CB PSL
Ext. Trip 3ph PSL
CB Aux 3ph(52-
A)
CB Aux 3ph(52-
B)
PSL
PSL
684 MCB/VTS PSL
686
687
688
Command
Blocked
Time Synch
Reset Close
Dly.
PSL
PSL
PSL
Description of Logic Nodes
Description
Inhibit DLR Stage 3
Inhibit DLR Stage 4
Inhibit DLR Stage 5
Inhibit DLR Stage 6
Inhibit DLR all stages
Block Current Loop Input (transducer input) 1
Block Current Loop Input (transducer input) 2
Block Current Loop Input (transducer input) 3
Block Current Loop Input (transducer input) 4
Trigger for Fault Recorder
Any Trip – All trip signals that are required to operate the Trip LED, initiate the breaker fail protection and initiate the CB monitoring counters are mapped to this signal in the PSL.
Setting Group Selector X1 (low bit) - selects SG2 if only DDB 624 signal is on.
SG1 is active if both DDB 624 & DDB 625 = 0
SG4 is active if both DDB 624 & DDB 625 = 1
Setting Group Selector 1X (high bit) - selects SG3 if only DDB 625 is active.
SG1 is active if both DDB 624 & DDB 625 = 0
SG4 is active if both DDB 624 & DDB 625 = 1
Commissioning Tests - automatically places relay in Test Mode which takes the relay out of service and allows secondary injection testing of the relay. For IEC60870-5-103 protocol spontaneous events and cyclic measured data transmitted whilst the relay is in test mode will have a
COT of ‘test mode’
Initiate tripping of circuit breaker from a manual command
Initiate closing of circuit breaker from a manual command
External Trip 3 phase - allows external protection to initiate breaker fail and circuit breaker condition monitoring counters.
52-A (CB closed) CB Auxiliary Input (3 phase)
52-B (CB open) CB Auxiliary Input (3 phase)
Circuit Breaker Healthy (input to manual close that the CB has enough energy to allow closing)
VT supervision input - signal from external Miniature Circuit Breaker showing MCB tripped
For IEC-870-5-103 protocol only, used for "Monitor Blocking" (relay is quiet - issues no messages via SCADA port)
For IEC-870-5-103 protocol only, used for "Command Blocking" (relay ignores SCADA commands)
Time Synchronism by Opto Input pulse
Reset Manual Circuit Breaker Close Time Delay
Page (PL) 7-20 P341/EN PL/G74
Description of Logic Nodes (PL) 7 Programmable Logic
DDB no. English text
689
Reset
Relays/LED
690
691
692
693
694
695
696
PSL
Reset Lockout PSL
Reset All Values PSL
RP1 Read Only PSL
RP2 Read Only PSL
NIC Read Only PSL
103
MonitorBlock
PSL
103
CommandBlock
PSL
697 to 767 Not used
768 IN>1 Trip
769 IN>2 Trip
770
771
772
773
IN>3 Trip
IN>4 Trip
IREF> Trip
ISEF>1 Trip
774
775
ISEF>2 Trip
ISEF>3 Trip
776 ISEF>4 Trip
777 to 799 Not used
800
801
802
I>1 Trip
I>1 Trip A
I>1 Trip B
Source Description
Reset Latched Relays & LEDs (manual reset of any latched trip contacts and LEDs)
Reset CB monitoring lockouts
Reset Circuit Breaker Condition Monitoring Values
Rear Port 1 Remote Read only
Rear Port 2 Remote Read only
Ethernet Rear Port Remote Read only
IEC 60870-5-103 Monitor Block
IEC 60870-5-103 Command Block
Earth Fault
Earth Fault
1st Stage Earth Fault Trip
2nd Stage Earth Fault Trip
Earth Fault
Earth Fault
3rd Stage Earth Fault Trip
4th Stage Earth Fault Trip
Restricted Earth Fault Restricted Earth Fault Trip
Sensitive Earth Fault 1st Stage Sensitive Earth Fault Trip
Sensitive Earth Fault 2nd Stage Sensitive Earth Fault Trip
Sensitive Earth Fault 3rd Stage Sensitive Earth Fault Trip
Sensitive Earth Fault 4th Stage Sensitive Earth Fault Trip
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
1st Stage Overcurrent Trip 3ph
1st Stage Overcurrent Trip A
1st Stage Overcurrent Trip B
825
826
827
828
829
803
804
805
806
807
808
809
810
I>1 Trip C
I>2 Trip
I>2 Trip A
I>2 Trip B
I>2 Trip C
I>3 Trip
I>3 Trip A
I>3 Trip B
811
812
813
814
I>3 Trip C
I>4 Trip
I>4 Trip A
I>4 Trip B
815 I>4 Trip C
816 to 823 Not used
824 I2>1 Trip
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
NPS Overcurrent
I2>2 Trip
I2>3 Trip
NPS Overcurrent
NPS Overcurrent
I2>4 Trip NPS Overcurrent
Bfail1 Trip 3ph Breaker Failure
Bfail2 Trip 3ph Breaker Failure
1st Stage Overcurrent Trip C
2nd Stage Overcurrent Trip 3ph
2nd Stage Overcurrent Trip A
2nd Stage Overcurrent Trip B
2nd Stage Overcurrent Trip C
3rd Stage Overcurrent Trip 3ph
3rd Stage Overcurrent Trip A
3rd Stage Overcurrent Trip B
3rd Stage Overcurrent Trip C
4th Stage Overcurrent Trip 3ph
4th Stage Overcurrent Trip A
4th Stage Overcurrent Trip B
4th Stage Overcurrent Trip C
1st Stage Negative Phase Sequence Overcurrent Trip
1st Stage Negative Phase Sequence Overcurrent Trip
1st Stage Negative Phase Sequence Overcurrent Trip
1st Stage Negative Phase Sequence Overcurrent Trip
1st Stage Breaker Fail Trip
2nd Stage Breaker Fail Trip
P341/EN PL/G74 Page (PL) 7-21
(PL) 7 Programmable Logic Description of Logic Nodes
DDB no. English text
830 to 831 Not used
832 VN>1 Trip
833 VN>2 Trip
Source
Residual O/V NVD
Residual O/V NVD
Description
1st Stage Residual Overvoltage Trip (Derived O/V)
2nd Stage Residual Overvoltage Trip (Derived O/V)
838
839
840
841
842
843
844
834
835
836
VN>3 Trip
VN>4 Trip
Not used
Residual O/V NVD
Residual O/V NVD
V>1 Trip Phase Overvoltage
V>1 Trip A/AB Phase Overvoltage
V>1 Trip B/BC Phase Overvoltage
V>1 Trip C/CA Phase Overvoltage
V>2 Trip Phase Overvoltage
V>2 Trip A/AB Phase Overvoltage
V>2 Trip B/BC Phase Overvoltage
1st Stage Residual Overvoltage Trip (VN Measured O/V)
2nd Stage Residual Overvoltage Trip (VN Measured O/V)
1st Stage Phase Overvoltage Trip 3ph
1st Stage Phase Overvoltage Trip A/AB
1st Stage Phase Overvoltage Trip B/BC
1st Stage Phase Overvoltage Trip C/CA
2nd Stage Phase Overvoltage Trip 3ph
2nd Stage Phase Overvoltage Trip A/AB
2nd Stage Phase Overvoltage Trip B/BC
V>2 Trip C/CA Phase Overvoltage
V2>1 Trip NPS Overvoltage
V<1 Trip
2nd Stage Phase Overvoltage Trip C/CA
Negative Phase Sequence Overvoltage Trip
Phase Undervoltage 1st Stage Phase Undervoltage Trip 3ph
845
846
847
848
849
850
851
852
853
854
V<1 Trip A/AB Phase Undervoltage 1st Stage Phase Undervoltage Trip A/AB
V<1 Trip B/BC Phase Undervoltage 1st Stage Phase Undervoltage Trip B/BC
V<1 Trip C/CA Phase Undervoltage 1st Stage Phase Undervoltage Trip C/CA
V<2 Trip Phase Undervoltage 2nd Stage Phase Undervoltage Trip 3ph
V<2 Trip A/AB Phase Undervoltage
V<2 Trip B/BC Phase Undervoltage
V<2 Trip C/CA Phase Undervoltage
855 to 881 Not used
882 Power 1 Trip
883
884
Power 2 Trip
Power
Power
SPower 1 Trip Sensitive Power
2nd Stage Phase Undervoltage Trip A/AB
2nd Stage Phase Undervoltage Trip B/BC
2nd Stage Phase Undervoltage Trip C/CA
1st Stage Power Trip
2nd Stage Power Trip
1st Stage Sensitive Power Trip
885 SPower 2 Trip Sensitive Power
886 to 915 Not used
916
917
F<1 Trip
F<2 Trip
Underfrequency
Underfrequency
918
919
920
F<3 Trip
F<4 Trip
F>1 Trip
Underfrequency
Underfrequency
Overfrequency
921 F>2 Trip
922 to 927 Not used
928
929 df/dt>1 Trip df/dt>2 Trip
930
931
932
933
934 df/dt>3 Trip df/dt>4 Trip
Not used
V Shift Trip
Not used
Overfrequency df/dt df/dt df/dt df/dt
Voltage Vector Shift
2nd Stage Sensitive Power Trip
1st Stage Underfrequency Trip
2nd Stage Underfrequency Trip
3rd Underfrequency Trip
4th Stage Underfrequency Trip
1st Stage Overfrequency Trip
2nd Stage Overfrequency Trip
1st Stage Rate of Change of Frequency Trip
2nd Stage Rate of Change of Frequency Trip
3rd Stage Rate of Change of Frequency Trip
4th Stage Rate of Change of Frequency Trip
Voltage Vector Shift Trip
Page (PL) 7-22 P341/EN PL/G74
Description of Logic Nodes (PL) 7 Programmable Logic
1040
1041
1042
1043
1044
1045
1046
1047
1048
989
990
991
992
993 to
1007
1008
1009
1010
1011
1012
1013
1014
1015
1016 to
1039
DDB no. English text Source
936
937 df/dt>1 Under F df/dt df/dt>1 Over F df/dt
938 to 944 Not used
945
Gen Thermal
Trip
Thermal Overload
Description
Rate of Change of Frequency Stage 1 Underfrequency
Rate of Change of Frequency Stage 1 Overfrequency
Thermal Overload Trip
946 to 951 Not used
952
953
DLR I>1 Trip
DLR I>2 Trip
DLR Ampacity Prot Trip
(P341 7x)
1st Stage DLR Ampacity Protection Trip
DLR Ampacity Prot Trip
(P341 7x)
2nd Stage DLR Ampacity Protection Trip
954
955
956
957
DLR I>3 Trip
DLR I>4 Trip
DLR I>5 Trip
DLR I>6 Trip
DLR Ampacity Prot Trip
(P341 7x)
3rd Stage DLR Ampacity Protection Trip
DLR Ampacity Prot Trip
(P341 7x)
4th Stage DLR Ampacity Protection Trip
DLR Ampacity Prot Trip
(P341 7x)
5th Stage DLR Ampacity Protection Trip
DLR Ampacity Prot Trip
(P341 7x)
6th Stage DLR Ampacity Protection Trip
958 to 986 Not used
987 CL Input 1 Trip Current Loop Inputs
988 CL Input 2 Trip Current Loop Inputs
Current Loop Input (transducer input) 1 Trip
Current Loop Input (transducer input) 2 Trip
CL Input 3 Trip Current Loop Inputs
CL Input 4 Trip Current Loop Inputs
Not used
Any Start All protection
Current Loop Input (transducer input) 3 Trip
Current Loop Input (transducer input) 4 Trip
Any Start
Not used
IN>1 Start
IN>2 Start
IN>3 Start
IN>4 Start
ISEF>3 Start
ISEF>4 Start
Not used
Earth Fault
Earth Fault
Earth Fault
Earth Fault
ISEF>1 Start Sensitive Earth Fault 1st Stage Sensitive Earth Fault Start
ISEF>2 Start Sensitive Earth Fault 2nd Stage Sensitive Earth Fault Start
Sensitive Earth Fault
Sensitive Earth Fault
1st Stage Earth Fault Start
2nd Stage Earth Fault Start
3rdt Stage Earth Fault Start
4th Stage Earth Fault Start
3rd Stage Sensitive Earth Fault Start
4th Stage Sensitive Earth Fault Start
I>1 Start
I>1 Start A
I>1 Start B
I>1 Start C
I>2 Start
I>2 Start A
I>2 Start B
I>2 Start C
I>3 Start
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
1st Stage Overcurrent Start 3ph
1st Stage Overcurrent Start A
1st Stage Overcurrent Start B
1st Stage Overcurrent Start C
2nd Stage Overcurrent Start 3ph
2nd Stage Overcurrent Start A
2nd Stage Overcurrent Start B
2nd Stage Overcurrent Start C
3rd Stage Overcurrent Start 3ph
P341/EN PL/G74 Page (PL) 7-23
(PL) 7 Programmable Logic Description of Logic Nodes
1074
1095
1096
1097
1098
1099
1100
1101
1075 to
1087
1088
1089
1090
1091
1092 to
1093
1094
1102
1103
1104
1105
1106
1107
1108
1109
1064
1065
1066
1067
1068
1069
1070
1071
DDB no. English text
1049
1050
1051
I>3 Start A
I>3 Start B
I>3 Start C
1052
1053
1054
1055
1056 to
1063
I>4 Start
I>4 Start A
I>4 Start B
I>4 Start C
Not Used
I2>1 Start
I2>2 Start
I2>3 Start
I2>4 Start
IA< Start
IB< Start
IC< Start
ISEF< Start
1073
Source
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
Phase Overcurrent
NPS Overcurrent
NPS Overcurrent
NPS Overcurrent
NPS Overcurrent
Undercurrent
Undercurrent
Undercurrent
Undercurrent
Description
3rd Stage Overcurrent Start A
3rd Stage Overcurrent Start B
3rd Stage Overcurrent Start C
4th Stage Overcurrent Start 3ph
4th Stage Overcurrent Start A
4th Stage Overcurrent Start B
4th Stage Overcurrent Start C
1st Stage Negative Phase Sequence Overcurrent Start
1st Stage Negative Phase Sequence Overcurrent Start
1st Stage Negative Phase Sequence Overcurrent Start
1st Stage Negative Phase Sequence Overcurrent Start
A phase Undercurrent Start (used in CB Fail logic)
B phase Undercurrent Start (used in CB Fail logic)
C phase Undercurrent Start (used in CB Fail logic)
Sensitive Earth Fault Undercurrent Start (used in CB Fail logic)
I> blocked overcurrent start. Start signal from all stages of I> protection for use in blocking schemes.
IN/ISEF> blocked overcurrent start. Start signal from all stages of IN> and ISEF> protection for use in blocking schemes.
I> BlockStart Phase Over Current
IN/SEF>Blk
Start
Not Used
EF & SEF
VN>1 Start
VN>2 Start
VN>3 Start
VN>4 Start
Not Used
Residual O/V NVD
Residual O/V NVD
Residual O/V NVD
Residual O/V NVD
1st Stage Residual Overvoltage Start (Derived O/V)
2nd Stage Residual Overvoltage Start (Derived O/V)
1st Stage Residual Overvoltage Start (VN1 Measured O/V)
2nd Stage Residual Overvoltage Start (VN1 Measured O/V)
V>1 Start Phase Overvoltage
V>1 Start A/AB Phase Overvoltage
V>1 Start B/BC Phase Overvoltage
V>1 Start C/CA Phase Overvoltage
V>2 Start Phase Overvoltage
1st Stage Phase Overvoltage Start 3ph
1st Stage Phase Overvoltage Start A/AB
1st Stage Phase Overvoltage Start B/BC
1st Stage Phase Overvoltage Start C/CA
2nd Stage Phase Overvoltage Start 3ph
V>2 Start A/AB Phase Overvoltage
V>2 Start B/BC Phase Overvoltage
V>2 Start C/CA Phase Overvoltage
2nd Stage Phase Overvoltage Start A/AB
2nd Stage Phase Overvoltage Start B/BC
2nd Stage Phase Overvoltage Start C/CA
V2>1 Start
V<1 Start
NPS Overvoltage Negative Phase Sequence Overvoltage Start
Phase Undervoltage 1st Stage Phase Undervoltage Start 3ph
V<1 Start A/AB Phase Undervoltage 1st Stage Phase Undervoltage Start A/AB
V<1 Start B/BC Phase Undervoltage 1st Stage Phase Undervoltage Start B/BC
V<1 Start C/CA Phase Undervoltage 1st Stage Phase Undervoltage Start C/CA
V<2 Start Phase Undervoltage 2nd Stage Phase Undervoltage Start 3ph
V<2 Start A/AB Phase Undervoltage 2nd Stage Phase Undervoltage Start A/AB
V<2 Start B/BC Phase Undervoltage 2nd Stage Phase Undervoltage Start B/BC
Page (PL) 7-24 P341/EN PL/G74
Description of Logic Nodes (PL) 7 Programmable Logic
1175
1176
1177
1178 to
1183
1184
1185
1186
1187
1188 to
1231
1232
1233
1234
1235
1236
DDB no. English text
1110
1111 to
1139
1140
1141
Not Used
Power1 Start
Power2 Start
Power
Power
Source
1st Stage Power Start
2nd Stage Power Start
Description
V<2 Start C/CA Phase Undervoltage 2nd Stage Phase Undervoltage Start C/CA
1142
1143
1144 to
1171
1172
1173
1174
SPower1 Start Sensitive Power
SPower2 Start Sensitive Power
Not Used
F<1 Start
F<2 Start
F<3 Start
F<4 Start
F>1 Start
F>2 Start
Underfrequency
Underfrequency
Underfrequency
Underfrequency
Overfrequency
Overfrequency
1st Stage Sensitive Power Start
2nd Stage Sensitive Power Start
1st Stage Underfrequency Start
2nd Stage Underfrequency Start
3rd Stage Underfrequency Start
4th Stage Underfrequency Start
1st Stage Overfrequency Start
2nd Stage Overfrequency Start
Not Used df/dt>1 Start df/dt>2 Start df/dt>3 Start df/dt>4 Start
Not Used df/dt df/dt df/dt df/dt
CLI1 Alarm Start Current Loop Inputs
CLI2 Alarm Start Current Loop Inputs
CLI3 Alarm Start Current Loop Inputs
CLI4 Alarm Start Current Loop Inputs
CLI1 Trip Start Current Loop Inputs
1st Stage Rate of Change of Frequency Start
2nd Stage Rate of Change of Frequency Start
3rd Stage Rate of Change of Frequency Start
4th Stage Rate of Change of Frequency Start
Current Loop Input (transducer input) 1 Alarm Start
Current Loop Input (transducer input) 2 Alarm Start
Current Loop Input (transducer input) 3 Alarm Start
Current Loop Input (transducer input) 4 Alarm Start
Current Loop Input (transducer input) 1 Trip Start
1237
1238
1239
1240 to
1247
CLI2 Trip Start Current Loop Inputs
CLI3 Trip Start Current Loop Inputs
CLI4 Trip Start Current Loop Inputs
Not Used
Current Loop Input (transducer input) 2 Trip Start
Current Loop Input (transducer input) 3 Trip Start
Current Loop Input (transducer input) 4 Trip Start
1248
1249
VTS Fast Block VT Supervision
VTS Slow Block VT Supervision
VT Supervision Fast Block - blocks elements which would otherwise mal-operate immediately after a fuse failure event occurs
VT Supervision Slow Block - blocks elements which would otherwise mal-operate some time after a fuse failure event occurs
1250 to
1262
Not Used
1263 CTS-1 Block CT Supervision
CT Supervision Block for IA/IB/IC (current transformer supervision).
CTS-1 Block DDBs can be used to block protection functions not automatically blocked.
1264 to
1277
1278
1279
1280
Not Used
Control Trip
Control Close
Close in Prog
CB Control
CB Control
CB Control
Control Trip
Control Close
Control Close in Progress
P341/EN PL/G74 Page (PL) 7-25
(PL) 7 Programmable Logic Description of Logic Nodes
1281
1294
1295
1296 to
1298
1299
1300
1301
1302
1303
1304 to
1313
1282
1283
1284
1285
1286
1287
1288
1289 to
1292
1293
1314
1315 to
1327
1328
1329
1330
1331
1332
DDB no.
1333
1335
1336
1337
1338
1339
1340
1341
English text
Lockout Alarm CB Monitoring
CB Open 3 ph CB Status
CB Closed 3 ph CB Status
All Poles Dead Poledead
Any Pole Dead Poledead
Pole Dead A Poledead
Pole Dead B
Pole Dead C
Poledead
Poledead
Not Used
Freq High Frequency Tracking
Freq Low Frequency Tracking
Freq Not found Frequency Tracking
Not Used
Source Description
Composite Lockout Alarm from CB Monitoring functions (I ^ Lockout
Alarm OR CB Ops Lockout OR CB Op Time Lock OR Fault Freq Lock)
Three phase Circuit breaker Open Status
Three phase Circuit breaker Closed Status
Pole dead logic detects 3 phase breaker open condition
Pole dead logic detects at least one breaker pole open
Phase A Pole Dead
Phase B Pole Dead
Phase C Pole Dead
Frequency tracking detects frequency above the allowed range
Frequency tracking detects frequency below the allowed range
Frequency Not Found by the frequency tracking
Reconnection Reconnection
Recon LOM-1 Reconnection
Recon Disable-1 Reconnection
Recon LOM Reconnection
Recon Disable Reconnection
Not Used
Blk Rmt. CB
Ops
Not Used
PSL
Reconnection Time Delay Output
Reconnect LOM (Unqualified)
Reconnect Disable (Unqualified)
Reconnect LOM
Reconnect Disable
Blocks remote CB Trip/Close commands when asserted
Live Gen
Dead Gen
Live Bus
Dead Bus
Check Sync 1
OK
Check Sync 2
OK
Voltage Monitors
Voltage Monitors
Voltage Monitors
Voltage Monitors
Indicates live generator voltage condition is detected
Indicates dead generator voltage condition is detected
Indicates live busbar voltage condition is detected
Indicates dead busbar voltage condition is detected
Check Synchronization Check synchronization stage 1 OK
Check Synchronization Check synchronization stage 1 OK
SysChks
Inactive
Check Synchronization
System checks inactive (output from the check synchronism, and other voltage checks)
CS1 Enabled Check Synchronization Check sync. stage 1 OK
CS2 Enabled Check Synchronization Check sync. stage 2 OK
SysSplit
Enabled
Check Synchronization System Split function enabled
CS1 Slipfreq> Check Synchronization
Operates when 1st stage check sync. slip frequency is above the check sync. 1 slip frequency setting
CS1 Slipfreq< Check Synchronization
CS2 Slipfreq> Check Synchronization
Operates when 1st stage check sync. slip frequency is below the check sync. 1 slip frequency setting
Operates when 2nd stage check sync. slip frequency is above the check sync. 2 slip frequency setting
Page (PL) 7-26 P341/EN PL/G74
Description of Logic Nodes (PL) 7 Programmable Logic
DDB no.
1342
1343
1344
1345
1346
1347
1348
1349
1350
1351
1352
1353
1354
1355
1356
1357
1358
1359
1360
English text
CS Vgen<
CS Vbus<
CS Vgen>
CS Vbus>
CS1 Ang Not
OK +
CS1 Ang Not
OK -
CS2 Ang Not
OK +
CS2 Ang Not
OK -
CS Ang Rot
ACW
Source
CS2 Slipfreq< Check Synchronization
Check Synchronization
Check Synchronization
Check Synchronization
Check Synchronization
CS Freq Low Check Synchronization
CS Freq High Check Synchronization
CS Vgen>Vbus Check Synchronization
CS Vgen<Vbus Check Synchronization
CS1 Fgen>Fbus Check Synchronization
CS1 Fgen<Fbus Check Synchronization
Check Synchronization
Check Synchronization
CS2 Fgen>Fbus Check Synchronization
CS2 Fgen<Fbus Check Synchronization
Check Synchronization
Check Synchronization
Check Synchronization
CS Ang Rot CW Check Synchronization
Description
Operates when 2nd stage check sync. slip frequency is below the check sync. 2 slip frequency setting
Indicates the generator voltage is less than the check sync. undervoltage setting
Indicates the busbar voltage is less than the check sync. undervoltage setting
Indicates the generator voltage is greater than the check sync. overvoltage setting
Indicates the busbar voltage is greater than the check sync. overvoltage setting
Indicates the generator frequency is less than the Gen Under Freq setting
Indicates the generator frequency is greater than the Gen Over Freq setting
Indicates that the generator voltage is greater than bus voltage + check sync. differential voltage setting
Indicates the busbar voltage is greater than line voltage + check sync. differential voltage setting
Indicates the generator frequency is greater than the busbar frequency
+ check sync. 1 slip frequency setting where check sync. 1 slip control is set to frequency
Indicates the busbar frequency is greater than generator frequency + check sync. 1 slip frequency setting where check sync. 1 slip control is set to frequency
Indicates the generator angle leads the bus angle and falls in range +
CS1 phase angle (deg.) to 180
Indicates if the line angle lags the busbar angle and falls in range - CS1 phase angle (deg.) to -180
Indicates the generator frequency is greater than the busbar frequency
+ check sync. 2 slip frequency setting where check sync. 1 slip control is set to frequency
Indicates the busbar frequency is greater than generator frequency + check sync. 2 slip frequency setting where check sync. 1 slip control is set to frequency
Indicates the generator angle leads the bus angle and falls in range +
CS2 phase angle (deg.) to 180
Indicates if the line angle lags the busbar angle and falls in range – CS2 phase angle (deg.) to -180
The direction of rotation of generator angle, using busbar as a reference, is anti-clockwise (ACW)
The direction of rotation of generator angle, using busbar as a reference, is clockwise (CW)
1361
1362
1363
CS Guard
Enabled
Man Check
Synch
CS Guard
Enable
Check Synchronization Check Synch Guard is on. Check synch is blocked.
PSL
PSL
Input to the circuit breaker control logic to indicate manual check synchronization conditions are satisfied
Check Synch Guard Enable input (CS Block input).
1364 to
1375
1376
1407
Not Used
Control Input 1 Control Input Command Control Input 1 - for SCADA and menu commands into PSL
Control Input 32 Control Input Command Control Input 32 - for SCADA and menu commands into PSL
P341/EN PL/G74 Page (PL) 7-27
(PL) 7 Programmable Logic Description of Logic Nodes
DDB no.
1408
1471
English text
Virtual Input 1
Virtual Input 64
Source
GOOSE Input
Command
GOOSE Input
Command
1472 to
1503
1504
1567
1568 to
1599
1600
1663
1664 to
1695
Not Used
Quality VIP 1 GOOSE
Quality VIP 64 GOOSE
Not Used
PubPres VIP 1 GOOSE
PubPres VIP 64 GOOSE
Not Used
1696
1759
Virtual Output
01
Virtual Output
64
GOOSE
GOOSE
1760 to
1791
1792
2047
Not Used
PSL Int 1
PSL Int 256
PSL
PSL
Table 1 - Description of available Logic Nodes
Description
Virtual Input 1 - allows binary signals that are mapped to virtual inputs to interface into PSL
Virtual Input 64 - allows binary signals that are mapped to virtual inputs to interface into PSL
GOOSE Virtual input 1 Quality bit
GOOSE Virtual input 64 Quality bit
GOOSE Virtual input 1 publisher bit
GOOSE Virtual input 64 publisher bit
Virtual Output 1 - output allows user to control a binary signal which can be mapped via SCADA protocol output to other devices
Virtual Output 64 - output allows user to control a binary signal which can be mapped via SCADA protocol output to other devices
PSL Internal Node
PSL Internal Node
Page (PL) 7-28 P341/EN PL/G74
Default Programmable Scheme Logic (PSL)
3.1
3.2
(PL) 7 Programmable Logic
P341 Model Options
The following section details the default settings of the PSL..
The P341 model options are as follows:
Model Opto inputs
P341xxxxxxxxxxJ 8-24
Table 2 - Default settings
Relay outputs
7-24
Logic Input Mapping
The default mappings for each of the opto-isolated inputs are as shown in Table 3:
21
22
23
24
17
18
19
20
13
14
15
16
6
7
8
9
10
11
12
1
4
5
2
3
Opto-Input number
P341 relay text
Input L13
Input L14
Input L15
Input L16
Input L17
Input L18
Input L19
Input L20
Input L21
Input L22
Input L23
Input L24
Input L1
Input L2
Input L3
Input L4
Input L5
Input L6
Input L7
Input L8
Input L9
Input L10
Input L11
Input L12
Function
L1 Setting Group selection
L2 Setting Group selection
L3 Block IN>3 & IN>4 Timer
L4 Block I>3 & I>4 Timer
L5 Reset Relays and LEDs
L6 Ext Prot Trip
L7 52a (CB Status)
L8 52b (CB Status)
L9 Not Used
L10 Not Used
L11 Not Used
L12 Not Used
L13 Not Used
L14 Not Used
L15 Not Used
L16 Not Used
L17 Not Used
L18 Not Used
L19 Not Used
L20 Not Used
L21 Not Used
L22 Not Used
L23 Not Used
L24 Not Used
Table 3 - P341 opto inputs default mappings
P341/EN PL/G74 Page (PL) 7-29
(PL) 7 Programmable Logic
3.3
Default Programmable Scheme Logic (PSL)
Relay Output Contact Mapping
The default mappings for each of the relay output contacts are as shown in Table 4:
1
2
3
Relay contact number
P341 relay text
Output R1
Output R2
Output R3
P341 relay conditioner
Straight-through
Straight-through
Dwell 100 ms
Function
R1 Block IN/ISEF
R2 BlockStart I>
R3 Any Protection Trip
R4 General Alarm
5 Output R5 Dwell 100 ms
17
18
19
20
13
14
15
16
21
22
23
24
7
8
9
10
11
12
Output R7
Output R8
Output R9
Output R10
Output R11
Output R12
Output R13
Output R14
Output R15
Output R16
Output R17
Output R18
Output R19
Output R20
Output R21
Output R22
Output R23
Output R24
Straight-through
Straight-through
Straight-through
Straight-through
Straight-through
Straight-through
Straight-through
Straight-through
Straight-through
Straight-through
Straight-through
Straight-through
Straight-through
Straight-through
Straight-through
Straight-through
Straight-through
Straight-through
Table 4 - P341 relay output contacts default mappings
R5 CB Fail
R6 Control Close
R7 Trip CB
R8 Not Used
R9 Not Used
R10 Not Used
R11 Not Used
R12 Not Used
R13 Not Used
R14 Not Used
R15 Not Used
R16 Not Used
R17 Not Used
R18 Not Used
R19 Not Used
R20 Not Used
R21 Not Used
R22 Not Used
R23 Not Used
R24 Not Used
Note: To generate a fault record, connect one or several contacts to the “Fault
Record Trigger” in PSL. The triggering contact should be ‘self reset’ and not a latching. If a latching contact were chosen the fault record would not be generated until the contact had fully reset.
Page (PL) 7-30 P341/EN PL/G74
Default Programmable Scheme Logic (PSL)
3.4
3.5
3.6
(PL) 7 Programmable Logic
Programmable LED Output Mapping
The default mappings for each of the programmable LEDs are as shown in Table 5 for
the P341 which have red LEDs:
LED number
LED Input connection/text
Latched P341 LED function indication
1
2
3
4
5
6
7
8
LED 1 Red
LED 2 Red
LED 3 Red
LED 4 Red
LED 5 Red
LED 6 Red
LED 7 Red
LED 8 Red
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
Earth Fault Trip -IN>1/2/3/4 Trip, ISEF>1/2/3/4 Trip,
/IREF>Trip, VN>1/2/3/4 Trip
Overcurrent Trip - I>1/2 Trip (3x software), I>1/2/3/4
Trip (7x software)
Overcurrent Trip - I>3/4 Trip (3x software), DLR
I>1/2/3/4/5/6 Trip (7x software) df/dt>1/2/3/4 Trip and V Shift Trip
Voltage Trip - V>1/2 trip, V<1/2 Trip, V2>1 Trip
Frequency Trip - F>1/2 Trip, F<1/2/3/4 Trip
Power Trip - Power 1/2 Trip, SPower 1/2 Trip
Any Start
Table 5 - P341 programmable LED default mappings
Fault Recorder Start Mapping
The default mapping for the signal which initiates a fault record is as shown Table 6:
Initiating signal
Relay 3 (DDB 002)
Table 6 - Default fault record initiation
Fault trigger
Initiate fault recording from main protection trip
PSL DATA Column
The P34x relay contains a PSL DATA column that can be used to track PSL modifications. A total of 12 cells are contained in the PSL DATA column, 3 for each setting group. The function for each cell is shown below:
Grp. PSL Ref.
18 Nov 2002
08:59:32.047
Grp. 1 PSL
ID - 2062813232
When downloading a PSL to the relay, the user will be prompted to enter which group the PSL is for and a reference identifier. The first
32 characters of the reference ID will be displayed in this cell The and keys can be used to scroll through 32 characters as only 16 can be displayed at any one time.
This cell displays the date and time when the PSL was down loaded to the relay.
This is a unique number for the PSL that has been entered. Any change in the PSL will result in a different number being displayed.
Note The above cells are repeated for each setting group.
P341/EN PL/G74 Page (PL) 7-31
(PL) 7 Programmable Logic
4
4.1
P341 Programmable Scheme Logic (V36 Software)
P341 PROGRAMMABLE SCHEME LOGIC (V36 SOFTWARE)
Input Mappings
Figure 7 - Opto Input Mappings (P341 V36)
Page (PL) 7-32 P341/EN PL/G74
P341 Programmable Scheme Logic (V36 Software)
4.2 Output Mappings
IN/ SEF> Blk Start
DDB # 1074
I > BlockStart
DDB # 1073
IN > 1 Trip
DDB #768
IN > 3 Trip
DDB #770
IREF > Trip
DDB #772
ISEF >2 Trip
DDB #774
ISEF >4 Trip
DDB #776
VN> 2 Trip
DDB #833
VN> 4 Trip
DDB #835
V< 2 Trip
DDB #851
V> 2 Trip
DDB #842
F< 2 Trip
DDB #917
F< 4 Trip
DDB #919
F> 2 Trip
DDB #921
Power 2 Trip
DDB #883
I> 2 Trip
DDB #804
I> 4 Trip
DDB #812
I2 > 2 Trip
DDB #825
I2 > 4 Trip
DDB #827
SPower 1 Trip
DDB #884
2 Trip
DDB #988
4 Trip
DDB #990 df/dt >2 Trip
DDB #929 df/dt >4 Trip
DDB #931
V Shift Trip
DDB # 933
IN> 2 Trip
DDB # 769
IN> 4 Trip
DDB # 771
ISEF > 1 Trip
DDB # 773
ISEF > 3 Trip
DDB # 775
VN> 1 Trip
DDB # 832
VN> 3 Trip
DDB # 834
V < 1 Trip
DDB # 847
V > 1 Trip
DDB # 838
F< 1 Trip
DDB # 916
F< 3 Trip
DDB # 918
F> 1 Trip
DDB # 920
Power 1 Trip
DDB # 882
I> 1 Trip
DDB # 800
I> 3 Trip
DDB # 808
I2 > 1 Trip
DDB # 824
I2 > 3 Trip
DDB # 826
V2 > 1 Trip
DDB # 846
SPower 2 Trip
DDB # 885
CL Input 1 Trip
DDB # 987
CL Input 3 Trip
DDB # 989 df /dt > 1 Trip
DDB # 928 df /dt > 3 Trip
DDB # 930
Figure 8 - Output Relay R1, R2, R3 Mappings (P341 V36)
(PL) 7 Programmable Logic
0
Straight
0
0
Straight
0
1
100
Dwell
0
Output R 1
DDB # 000
Output R 2
DDB # 001
Output R 3
DDB # 002
P2511ENa
P341/EN PL/G74 Page (PL) 7-33
(PL) 7 Programmable Logic P341 Programmable Scheme Logic (V36 Software)
Figure 9 - Output Relay R4, R5, R6 and R7 (General Trip) Mappings (P341 V36)
Page (PL) 7-34 P341/EN PL/G74
P341 Programmable Scheme Logic (V36 Software)
4.3 LEDs Mappings
(PL) 7 Programmable Logic
Figure 10 - LEDs Mappings (3x Software) (P341 V36)
P341/EN PL/G74 Page (PL) 7-35
(PL) 7 Programmable Logic
4.4 Check Synch Mappings
P341 Programmable Scheme Logic (V36 Software)
Figure 11 - Check Synch and Voltage Monitor Mappings (P341 V36)
Page (PL) 7-36 P341/EN PL/G74
P341 Programmable Scheme Logic (V71 Software)
5
5.1
(PL) 7 Programmable Logic
P341 PROGRAMMABLE SCHEME LOGIC (V71 SOFTWARE)
Input Mappings
Figure 12 - Opto Input Mappings (P341 V71)
P341/EN PL/G74 Page (PL) 7-37
(PL) 7 Programmable Logic
5.2 Output Mappings
DLR I> 2 Trip
DDB # 953
DLR I> 4 Trip
DDB # 955
DLR I> 6 Trip
DDB # 957
IN> 1 Trip
DDB #768
IN> 3 Trip
DDB #770
IREF > Trip
DDB #772
ISEF>2 Trip
DDB #774
ISEF>4 Trip
DDB #776
VN> 2 Trip
DDB #833
VN> 4 Trip
DDB #835
V< 2 Trip
DDB #851
V> 2 Trip
DDB # 842
F< 2 Trip
DDB # 917
F< 4 Trip
DDB #919
F> 2 Trip
DDB #921
Power 2 Trip
DDB #883
I> 2 Trip
DDB #804
I> 4 Trip
DDB #812
I2> 2 Trip
DDB #825
I2> 4 Trip
DDB #827
SPower 1 Trip
DDB #884
Gen Thermal Trip
DDB #945
CL Input 2 Trip
DDB # 988
CL Input 4 Trip
DDB # 990 df/dt> 2 Trip
DDB # 929 df/dt> 4 Trip
DDB # 931
Figure 13 - Output Relay R1, R2, R3 Mappings (P341 V71)
DLR I> 1 Trip
DDB # 952
DLR I> 3 Trip
DDB # 954
DLR I> 5 Trip
DDB # 956
V Shift Trip
DDB # 933
IN> 2 Trip
DDB # 769
IN> 4 Trip
DDB # 771
ISEF> 1 Trip
DDB # 773
ISEF> 3 Trip
DDB # 775
VN> 1 Trip
DDB # 832
VN> 3 Trip
DDB # 834
V < 1 Trip
DDB # 847
V > 1 Trip
DDB # 838
F< 1 Trip
DDB # 916
F< 3 Trip
DDB # 918
F> 1 Trip
DDB # 920
Power 1 Trip
DDB # 882
I> 1 Trip
DDB # 800
I> 3 Trip
DDB # 808
I2> 1 Trip
DDB # 824
I2> 3 Trip
DDB # 826
V 2> 1 Trip
DDB # 846
SPower2 Trip
DDB # 885
CL Input 1 Trip
DDB # 987
CL Input 3 Trip
DDB # 989 df/dt> 1 Trip
DDB # 928 df/dt> 3 Trip
DDB # 930
P341 Programmable Scheme Logic (V71 Software)
1
100
Dwell
0
Output R3
DDB #002
P2516ENa
Page (PL) 7-38 P341/EN PL/G74
P341 Programmable Scheme Logic (V71 Software) (PL) 7 Programmable Logic
SG- DDB Invalid
DDB # 354
VT Fail Alarm
DDB # 356
CT- 1 Fail Alarm
DDB # 357
CB Fail Alarm
DDB # 358
I ^ Maint Alarm
DDB # 359
I ^ Lockout Alarm
DDB # 360
CB Ops Maint
DDB # 361
CB Ops Lockout
DDB # 362
CB Op Time Maint
DDB # 363
CB Op Time Lock
DDB # 364
Fault Freq Lock
DDB # 365
CB Status Alarm
DDB # 366
Man CB Trip Fail
DDB # 367
Man CB Cls Fail
DDB # 368
Man CB Unhealthy
DDB # 369
F out of Range
DDB # 353
Field Volts Fail
DDB # 417
Gen Thermal Alm
DDB # 371
CL Card I/ P Fail
DDB # 384
CL Card O/ P Fail
DDB # 385
CL Input 1 Alarm
DDB # 386
CL Input 2 Alarm
DDB # 387
CL Input 3 Alarm
DDB # 388
CL Input 4 Alarm
DDB # 389
CLI 1 I< Fail Alm
DDB # 390
CLI 2 I< Fail Alm
DDB # 391
CLI 3 I< Fail Alm
DDB # 392
CLI 4 I< Fail Alm
DDB # 393
1
0
Drop-Off
500
Figure 14 - Output Relay R4, R5, R6 and R7 (General Trip) Mappings (P341 V71)
IN/SEF> Blk Start
DDB #1074
I> BlockStart
DDB #1073
Bfail 1 Trip 3ph
DDB # 828
Control Close
DDB #1279
Control Trip
DDB #1278
Figure 15 - Output Relay Mappings (P341 V71)
0
Straight
0
0
Straight
0
0
100
Dwell
0
Straight
0
0
Straight
0
Output R1
DDB #000
Output R2
DDB #001
Output R5
DDB #004
Output R6
DDB #005
Output R7
DDB #006
Output R4
DDB #003
P2517ENa
P2518ENa
P341/EN PL/G74 Page (PL) 7-39
(PL) 7 Programmable Logic P341 Programmable Scheme Logic (V71 Software)
5.3
I> 3 Trip
DDB # 808
I> 4 Trip
DDB # 812 df/ dt > 1 Trip
DDB #928 df/ dt > 3 Trip
DDB # 930
V Shift Trip
DDB # 933
V <1 Trip
DDB # 847
V> 1 Trip
DDB # 838
V2 > 1 Trip
DDB # 846
F< 1 Trip
DDB #916
F< 3 Trip
DDB #918
F> 1 Trip
DDB #920
IN > 1 Trip
DDB # 768
IN > 3 Trip
DDB # 770
ISEF > 1 Trip
DDB # 773
ISEF > 3 Trip
DDB # 775
IREF > Trip
DDB # 772
VN > 2 Trip
DDB # 833
VN > 4 Trip
DDB # 835
I> 1 Trip
DDB #800
I> 2 Trip
DDB #804
Power 1 Trip
DDB #882
SPower 1 Trip
DDB #884
Any Start
DDB #992
LED Mappings
IN> 2 Trip
DDB # 769
IN> 4 Trip
DDB # 771
ISEF > 2 Trip
DDB # 774
ISEF > 4 Trip
DDB # 776
VN > 1 Trip
DDB # 832
VN > 3 Trip
DDB # 834 df /dt > 2 Trip
DDB # 929 df / dt> 4 Trip
DDB # 931
V < 2 Trip
DDB # 851
V > 2 Trip
DDB # 842
F< 2 Trip
DDB # 917
F< 4 Trip
DDB # 919
F> 2 Trip
DDB # 921
Power 2 Trip
DDB #883
SPower 2 Trip
DDB #885
Figure 16 - LEDs Mappings (3x Software) (P341 V71)
1
1
1
1
1
1
1
Latching
Latching
Latching
Latching
Latching
Latching
Latching
Non –
Latching
LED 1
DDB # 224
LED 2
DDB #225
LED 3
DDB #226
LED 4
DDB # 227
LED 5
DDB # 228
LED 6
DDB # 229
LED 7
DDB # 230
LED 8
DDB # 231
P2519ENa
Page (PL) 7-40 P341/EN PL/G74
P341 Programmable Scheme Logic (V71 Software)
5.4 Check Synch Mappings
(PL) 7 Programmable Logic
Figure 17 - Check Synch and Voltage Monitor Mappings (P341 V71)
P341/EN PL/G74 Page (PL) 7-41
(PL) 7 Programmable Logic
Notes:
P341 Programmable Scheme Logic (V71 Software)
Page (PL) 7-42 P341/EN PL/G74
MiCOM P341 (MR) 8 Measurements and Recording
MEASUREMENTS AND RECORDING
CHAPTER 8
P341/EN MR/G74 Page (MR) 8-1
(MR) 8 Measurements and Recording
Hardware Suffix:
Software Version:
Connection Diagrams:
J (P341)
36 and 71 (with DLR)
10P341xx (xx = 01 to 12)
MiCOM P341
Page (MR) 8-2 P341/EN MR/G74
contents (MR) 8 Measurements and Recording
CONTENTS
Page (MR) 8-
1 Introduction 5
2 Event and fault records
Change of State of Opto-Isolated Inputs
Change of State of One or more Output Relay Contacts
Protection Element Starts and Trips
Resetting of Event/Fault Records
Viewing Event Records via S1 Studio Support Software
6
3 Disturbance Recorder 14
4 Measurements 16
Measured Voltages and Currents
Sequence Voltages and Currents
Measurement Display Quantities
P341/EN MR/G74 Page (MR) 8-3
(MR) 8 Measurements and Recording Tables
TABLES
Page (MR) 8-
Table 1 - Local viewing of records
Table 5 - Record control settings 12
Table 6 - Disturbance recorder settings 15
Table 8 - Measurement setup settings 18
Page (MR) 8-4 P341/EN MR/G74
Introduction (MR) 8 Measurements and Recording
1 INTRODUCTION
The P341 is equipped with integral measurements, event, fault and disturbance recording facilities suitable for analysis of complex system disturbances.
The relay is flexible enough to allow for the programming of these facilities to specific user application requirements and are discussed below.
P341/EN MR/G74 Page (MR) 8-5
(MR) 8 Measurements and Recording Event and fault records
2 EVENT AND FAULT RECORDS
The relay records and time tags up to 512 events and stores them in non-volatile (battery backed up) memory. This lets the system operator establish the sequence of events that occurred within the relay following a particular power system condition, switching sequence etc. When the available space is exhausted, the oldest event is automatically overwritten by the new one.
The real-time clock in the relay provides the time tag to each event, to a resolution of
1 ms.
The event records are available for viewing either via the frontplate LCD or remotely, via the communications ports (courier and MODBUS versions only).
Local viewing on the LCD is achieved in the menu column entitled VIEW RECORDS .
This column allows viewing of event, fault and maintenance records and is shown in
Menu text Default setting Setting range Step size
Min. Max.
Menu Cell Ref (From record)
VIEW RECORDS
Select Event 0 0 249
Setting range from 0 to 511. This selects the required event record from the possible 512 that may be stored. A value of 0 corresponds to the latest event and so on.
Latched alarm active, Latched alarm inactive, Self reset alarm active, Self reset alarm inactive, Relay contact event, Optoisolated input event, Protection event, General event, Fault record event, Maintenance record event
Indicates the type of event.
Time and Date Data
Time & Date Stamp for the event given by the internal Real Time Clock.
Event text Data.
Up to 32 Character description of the Event. See event sheet in the Relay Menu Database document, P341/EN/MD or
Measurements and Recording chapter, P341/EN MR for details.
Event Value Data.
32 bit binary string indicating ON or OFF (1 or 0) status of relay contact or opto input or alarm or protection event depending on event type. Unsigned integer is used for maintenance records. See event sheet in the Relay Menu Database document,
P341/EN/MD or Measurements and Recording chapter, P341/EN MR for details.
Select Fault 0 0 4 1
Setting range from 0 to 4. This selects the required fault record from the possible 5 that may be stored. A value of 0 corresponds to the latest fault and so on.
Faulted Phase 00000000
Displays the faulted phase as a binary string, bits 0 – 8 = Start A/B/C/N Trip A/B/C/N.
Start elements 1 00000000000000000000000000000000
32 bit binary string gives status of first 32 start signals. See Data Type G84 in the Relay Menu Database document,
P341/EN/MD
for details.
Start elements 2 00000000000000000000000000000000
32 bit binary string gives status of second 32 start signals. See Data Type G107 in the Relay Menu Database document,
P341/EN/MD
for details.
Start elements 3 00000000000000000000000000000000
32 bit binary string gives status of third 32 start signals. See Data Type G129 in the Relay Menu Database document,
P341/EN/MD for details.
Start elements 4 00000000000000000000000000000000
Page (MR) 8-6 P341/EN MR/G74
Event and fault records (MR) 8 Measurements and Recording
Menu text Default setting
Min.
Setting range
Max.
Step size
VIEW RECORDS
32 bit binary string gives status of third 32 start signals. See Data Type G131 in Menu Database chapter,
P341/EN/MD
for details.
Trip elements 1 00000000000000000000000000000000
32 bit binary string gives status of first 32 trip signals. See Data Type G85 in the Relay Menu Database document,
P341/EN/MD
for details.
Trip elements 2 00000000000000000000000000000000
32 bit binary string gives status of second 32 trip signals. See Data Type G86 in the Relay Menu Database document,
P341/EN/MD
for details.
Trip elements 3 00000000000000000000000000000000
32 bit binary string gives status of third 32 trip signals. See Data Type G130 in the Relay Menu Database document,
P341/EN/MD
for details.
Trip elements 4 00000000000000000000000000000000
32 bit binary string gives status of third 32 trip signals. See Data Type G132 in Menu Database chapter, P341/EN/MD for details.
Fault Alarms 0000001000000000
32 bit binary string gives status of fault alarm signals. See Data Type G87 in the Relay Menu Database document,
P341/EN/MD
for details.
Fault Alarms2 0000001000000000
32 bit binary string gives status of fault alarm signals. See Data Type G89 in the Relay Menu Database document,
P341/EN/MD
for details.
Data. Fault Time
Fault time and date.
Active Group Data.
Active setting group 1-4.
System Frequency
System frequency.
Fault Duration
Data
Fault duration. Time from the start or trip until the undercurrent elements indicate the CB is open.
CB Operate Time Data.
CB operating time. Time from protection trip to undercurrent elements indicating the CB is open.
Relay Trip Time Data.
Relay trip time. Time from protection start to protection trip.
The following cells provide measurement information of the fault: IA, IB, IC, VAB, VBC, VCA, VAN, VBN, VCN, VN Measured,
VN Derived, I Sensitive, IREF Diff, IREF Bias, I2, V2, 3 Phase Watts, 3 Phase VARs, 3Ph Power Factor, CLIO Input 1-4. df/dt,
DLR Ambient Temp, Wind Velocity, Wind Direction, Solar Radiation, DLR Ampacity, DLR CurrentRatio.
Select Maint 0 0 9 1
Setting range from 0 to 9. This selects the required maintenance report from the possible 10 that may be stored. A value of 0 corresponds to the latest report and so on.
Maint Text Data.
Up to 32 Character description of the occurrence. See Measurements and Recording chapter, P341/EN MR for details.
Maint Type Data.
Maintenance record fault type. This will be a number defining the fault type.
Maint Data 0 0 4 1
Error code associated with the failure found by the self monitoring. The Maint Type and Data cells are numbers representative of the occurrence. They form a specific error code which should be quoted in any related correspondence to Report Data.
Reset Indication No No, Yes N/A
P341/EN MR/G74 Page (MR) 8-7
(MR) 8 Measurements and Recording Event and fault records
Menu text Default setting
Min.
Setting range
Max.
VIEW RECORDS
Resets latched LEDs and latched relay contacts provided the relevant protection element has reset.
Step size
Table 1 - Local viewing of records
For extraction from a remote source via communications, refer to the SCADA
Communications chapter, where the procedure is fully explained.
Note A full list of all the event types and the meaning of their values is given in the Relay Menu Database document, P341/EN MD.
2.1 Types of Event
An event may be a change of state of a control input or output relay, an alarm condition, setting change etc. The following sections show the various items that constitute an event:
2.1.1
2.1.2
Change of State of Opto-Isolated Inputs
If one or more of the opto (logic) inputs has changed state since the last time the protection algorithm ran, the new status is logged as an event. When this event is selected to be viewed on the LCD, three applicable cells will become visible as shown below:
Time & date of event
“LOGIC INPUTS”
“Event Value 0101010101010101”
The Event Value is an 8, 12, 16, or 24-bit word showing the status of the opto inputs, where the least significant bit (extreme right) corresponds to opto input 1 etc. The same information is present if the event is extracted and viewed via PC.
Change of State of One or more Output Relay Contacts
If one or more of the output relay contacts have changed state since the last time that the protection algorithm ran, then the new status is logged as an event. When this event is selected to be viewed on the LCD, three applicable cells will become visible as shown below:
Time & date of event
“OUTPUT CONTACTS”
“Event Value 010101010101010101010”
The Event Value is a 7, 11, 12, 15, 16 or 20 bit word showing the status of the output contacts, where the least significant bit (extreme right) corresponds to output contact 1 etc. The same information is present if the event is extracted and viewed via PC.
2.1.3 Relay Alarm Conditions
Any alarm conditions generated by the relays will also be logged as individual events.
Table
2 shows examples of some of the alarm conditions and how they appear in the event list:
Resulting event Alarm condition
Alarm Status 1 (Alarms 1 - 32) (32 bits)
Event text Event value
Page (MR) 8-8 P341/EN MR/G74
Event and fault records (MR) 8 Measurements and Recording
Alarm condition
Setting Group Via Opto Invalid
Protection Disabled
Frequency Out of Range
VTS Alarm
CB Trip Fail Protection
Alarm Status 2 (Alarms 1 - 32) (32 bits)
SR User Alarm 1 - 4 (Self Reset)
MR User Alarm 5 - 16 (Manual Reset)
Alarm Status 3 (Alarms 1 - 32) (32 bits)
Battery Fail
Field Voltage Fail
Event text
Setting Grp Invalid ON/OFF
Prot’n Disabled ON/OFF
Freq out of Range ON/OFF
VT Fail Alarm ON/OFF
CB Fail ON/OFF
SR User Alarm 1 - 4 ON/OFF
MR User Alarm 5 - 16 ON/OFF
Resulting event
Event value
Bit position 2 in 32 bit field
Bit position 3 in 32 bit field
Bit position 13 in 32 bit field
Bit position 4 in 32 bit field
Bit position 6 in 32 bit field
Bit position 17 - 31 in 32 bit field
Bit position 16 - 27 in 32 bit field
Battery Fail ON/OFF
Field V Fail ON/OFF
Bit position 0 in 32 bit field
Bit position 1 in 32 bit field
Table 2 shows the abbreviated description that is given to the various alarm conditions and also a corresponding value between 0 and 31. This value is appended to each alarm event in a similar way as for the input and output events described previously. It is used by the event extraction software, such as S1 Studio, to identify the alarm and is therefore invisible if the event is viewed on the LCD. Either ON or OFF is shown after the description to signify whether the particular condition has become operated or has reset.
The User Alarms can be operated from an opto input or a control input using the PSL.
They can be useful to give an alarm LED and message on the LCD display and an alarm indication via the communications of an external condition, for example trip circuit supervision alarm, rotor earth fault alarm. The menu text editor in S1 Studio can be used to edit the user alarm text to give a more meaningful description on the LCD display.
2.1.4
2.1.5
Protection Element Starts and Trips
Any operation of protection elements, (either a start or a trip condition) will be logged as an event record, consisting of a text string indicating the operated element and an event value. Again, this value is intended for use by the event extraction software, such as S1
Studio, rather than for the user, and is therefore invisible when the event is viewed on the
LCD.
General Events
Several events come under the heading of General Events - an example is shown in
Table 3:
Nature of event
Displayed text in event record
Level 1 password modified, either from user interface, front or rear port.
PW1 modified UI, F, R or R2
Displayed value
0 UI=6, F=11, R=16, R2=38
Table 3 - General events
A complete list of the ‘General Events’ are given in the Relay Menu Database, P341/EN
MD .
2.1.6 Fault Records
Each time a fault record is generated, an event is also created. The event simply states that a fault record was generated, with a corresponding time stamp.
P341/EN MR/G74 Page (MR) 8-9
(MR) 8 Measurements and Recording
2.1.7
2.1.8
2.2
Event and fault records
Note 1 Viewing of the actual fault record is carried out in the Select Fault cell further down the VIEW RECORDS column, which is selectable from up to 5 records. These records consist of fault flags, fault location, fault measurements etc.
Note 2 The time stamp given in the fault record itself will be more accurate than the corresponding stamp given in the event record as the event is logged some time after the actual fault record is generated.
The fault record is triggered from the Fault REC. TRIG . signal assigned in the default programmable scheme logic to relay 3, protection trip. The fault measurements in the fault record are given at the time of the protection start. The fault recorder does not stop recording until any start (DDB 992) or the any trip signals (DDB 674) resets to record all the protection flags during the fault.
It is recommended that the triggering contact (relay 3 for example) be ‘self reset’ and not latching. If a latching contact were chosen the fault record would not be generated until the contact had fully reset.
Maintenance Reports
Internal failures detected by the self-monitoring circuitry, such as watchdog failure or field voltage failure are logged into a maintenance report. The maintenance report holds up to ten such events and is accessed from the Select Report cell at the bottom of the VIEW
RECORDS column.
Each entry consists of a self explanatory text string and a Type and Data cell, which are explained in the menu extract at the beginning of this section and in further detail in document P341/EN MD .
Each time a Maintenance Report is generated, an event is also created. The event simply states that a report was generated, with a corresponding time stamp.
Setting Changes
Changes to any setting within the relay are logged as an event. Two examples are shown in Table 4:
Type of setting change
Control/Support Setting
Group # Change
Displayed text in event record
C & S Changed
Group # Changed
Displayed value
22
#
Where # = 1 to 4
Table 4 - Setting changes
Note: Control/Support settings are communications, measurement, CT/VT ratio settings etc, which are not duplicated within the four setting groups. When any of these settings are changed, the event record is created simultaneously. However, changes to protection or disturbance recorder settings will only generate an event once the settings have been confirmed at the ‘setting trap’.
Resetting of Event/Fault Records
To delete the event, fault or maintenance reports, use the RECORD CONTROL column.
Page (MR) 8-10 P341/EN MR/G74
Event and fault records
2.3
(MR) 8 Measurements and Recording
Viewing Event Records via S1 Studio Support Software
When the event records are extracted and viewed on a PC they look slightly different than when viewed on the LCD. The following shows an example of how various events appear when displayed using S1 Studio:
Monday 08 January 2001 18:45:28.633 GMT V<1 Trip A/AB ON
Schneider Electric: MiCOM P341
Model Number: P341314B2M0360J
Address: 001 Column: 0F Row: 26
Event Type: Setting event
Event Value: 00000001000000000000000000000000
Monday 08 January 2001 18:45:28.634 GMT Output Contacts
Schneider Electric: MiCOM P341
Model Number: P341314B2M0360J
Address: 001 Column: 00 Row: 21
Event Type: Device output changed state
Event Value: 00000000001100
OFF 0 Output R1
OFF 1 Output R2
ON 2 Output R3
ON 3 Output R4
OFF 4 Output R5
OFF 5 Output R6
OFF 6 Output R7
Monday 08 January 2001 18:45:28.633 GMT Voltage Prot Alm ON
Schneider Electric: MiCOM P341
Model Number: P341314B2M0360J
Address: 001 Column: 00 Row: 22
Event Type: Alarm event
Event Value: 00001000000000000000000000000000
OFF 0 Not Used
OFF 1 Freq out of range
OFF 2 SG-opto Invalid
OFF 3 Prot'n Disabled
OFF 4 VT Fail Alarm
OFF 5 CT Fail Alarm
OFF 6 CB Fail Alarm
OFF 7 I^ Maint Alarm
OFF 8 I^ Maint Lockout
OFF 9 CB OPs Maint
OFF 10 CB OPs Lockout
OFF 11 CB Op Time Maint
OFF 12 CB Time Lockout
OFF 13 Fault Freq Lock
OFF 14 CB Status Alarm
OFF 15 CB Trip Fail
OFF 16 CB Close Fail
OFF 17 Man CB Unhealthy
OFF 18 F out of Range
OFF 19 Thermal Alarm
OFF 20 Not Used
OFF 21 Not Used
OFF 22 Not Used
OFF 23 Not Used
OFF 24 Not Used
OFF 25 Not Used
P341/EN MR/G74 Page (MR) 8-11
(MR) 8 Measurements and Recording Event and fault records
OFF 26 Not Used
ON 27 Freq Prot Alm
OFF 28 Voltage Prot Alm
OFF 29 Not Used
OFF 30 Not Used
OFF 31 Not Used
The first line gives the description and time stamp for the event, while the additional information displayed below may be collapsed via the +/– symbol.
For further information regarding events and their specific meaning, refer to relay menu database document, P341/EN MD . This is a standalone document not included in this manual.
2.4 Event Filtering
Event filtering can be disabled from all interfaces that supports setting changes. The settings that control the various types of events are in the record control column. The effect of setting each to disabled is shown in Table 5:
Menu text Default setting Available settings
RECORD CONTROL
Clear Events
Clear Faults
No
No
Selecting
Yes
will cause the existing fault records to be erased from the relay.
No or Yes
Selecting
Yes
will cause the existing event log to be cleared and an event will be generated indicating that the events have been erased.
No or Yes
No or Yes Clear Maint. No
Selecting Yes will cause the existing maintenance records to be erased from the relay.
Alarm Event Enabled Enabled or Disabled
Disabling this setting means that no event will be generated for all alarms.
Relay O/P Event Enabled Enabled or Disabled
Disabling this setting means that no event will be generated for any change in relay output contact state.
Opto Input Event Enabled Enabled or Disabled
Disabling this setting means that no event will be generated for any change in logic input state.
General Event Enabled Enabled or Disabled
Disabling this setting means that no General Events will be generated. See event record sheet in the Relay Menu Database document, P341/EN MD for list of general events.
Fault Rec Event Enabled Enabled or Disabled
Disabling this setting means that no event will be generated for any fault that produces a fault record.
Maint. Rec Event Enabled
Disabling this setting means that no event will be generated for any maintenance records.
Enabled or Disabled
Protection Event Enabled Enabled or Disabled
Disabling this setting means that no event will be generated for any operation of the protection elements.
DDB 31 - 0 11111111111111111111111111111111
32 bit setting to enable or disable the event recording for DDBs 0-31. For each bit 1 = event recording Enabled, 0 = event recording Disabled.
DDB 2047 - 2016 11111111111111111111111111111111
32 bit setting to enable or disable the event recording for DDBs 2047 - 2016. For each bit 1 = event recording Enabled, 0 = event recording Disabled. There are similar cells showing 32 bit binary strings for all DDBs from 0 – 2047. The first and last 32 bit binary strings only are shown here.
Table 5 - Record control settings
Page (MR) 8-12 P341/EN MR/G74
Event and fault records (MR) 8 Measurements and Recording
Note Some occurrences result in more than one type of event, for example a battery failure will produce an alarm event and a maintenance record event.
If the Protection Event setting is Enabled a further set of settings is revealed which allow the event generation by individual DDB signals to be enabled or disabled.
For further information regarding events and their specific meaning, refer to Relay Menu
Database document, P341/EN MD .
P341/EN MR/G74 Page (MR) 8-13
(MR) 8 Measurements and Recording Disturbance Recorder
The integral disturbance recorder has an area of memory specifically set aside for record storage. The number of records that may be stored by the relay is dependent upon the selected recording. The relay can typically store a minimum of 50 records, each of 1.5 seconds duration (8 analogue channels and 32 digital channels). VDEW relays, however, have the same total record length but the VDEW protocol dictates that only 8 records can be extracted via the rear port. Disturbance records continue to be recorded until the available memory is exhausted, at which time the oldest record(s) are overwritten to make space for the newest one.
The recorder stores actual samples that are taken at a rate of 24 samples per cycle.
Each disturbance record consists of a maximum of 8 analog data channels for P341 and thirty-two digital data channels. The relevant CT and VT ratios for the analog channels are also extracted to enable scaling to primary quantities.
Note If a CT ratio is set less than unity, the relay will choose a scaling factor of zero for the appropriate channel.
The DISTURBANCE RECORDER menu column is shown in Table 6:
Menu text Default setting
Min.
Setting range
Max.
Step size
Duration 1.5 s
DISTURB RECORDER
0.1 s 10.5 s 0.01 s
Overall recording time setting.
Trigger Position 33.3% 0 100% 0.1%
Trigger point setting as a percentage of the duration. For example, the default settings show that the overall recording time is set to 1.5 s with the trigger point being at 33.3% of this, giving 0.5 s pre-fault and 1 s post fault recording times.
Trigger Mode Single Single or Extended
If set to single
and if a further trigger occurs while a recording is taking place, the recorder will ignore the trigger. However, if this has been set to Extended , the post trigger timer will be reset to zero, thereby extending the recording time.
Analog. Channel 1 VA
Unused, VA, VB, VC, VN, IA, IB, IC, I Sensitive, Frequency,
C/S voltage
Selects any available analog input to be assigned to this channel.
Analog. Channel 2 VB As above
Analog. Channel 3 VC As above
Analog. Channel 4
Analog. Channel 5
Analog. Channel 5
VN1
IA-1
IB-1
As above
As above
As above
Analog. Channel 6
Analog. Channel 7
Inputs 1 to 32 Trigger
IC-1
I Sensitive
As above
As above
Analog. Channel 8
Digital Inputs 1 to 32
IN As above
Relays 1 to 24 and Opto’s 1 to
24
Any of O/P Contacts or Any of Opto Inputs or Internal Digital
Signals
The digital channels may be mapped to any of the opto isolated inputs or output contacts, in addition to a number of internal relay digital signals, such as protection starts, LEDs etc.
No Trigger except Dedicated
Trip Relay O/P’s which are set to Trigger L/H
No Trigger, Trigger L/H, Trigger H/L
Page (MR) 8-14 P341/EN MR/G74
Disturbance Recorder (MR) 8 Measurements and Recording
Menu text Default setting
Min.
Setting range
Max.
Step size
DISTURB RECORDER
Any of the digital channels may be selected to trigger the disturbance recorder on either a low to high (L/H) or a high to low
(H/L) transition.
Table 6 - Disturbance recorder settings
The pre and post fault recording times are set by a combination of the Duration and
Trigger Position cells. Duration sets the overall recording time and the Trigger
Position sets the trigger point as a percentage of the duration. For example, the default settings show that the overall recording time is set to 1.5 s with the trigger point being at
33.3% of this, giving 0.5 s pre-fault and 1 s post fault recording times.
If a further trigger occurs while a recording is taking place, the recorder ignores the trigger if the Trigger Mode has been set to Single . However, if this has been set to Extended , the post trigger timer will be reset to zero, thereby extending the recording time.
As can be seen from the menu, each of the analog channels is selectable from the available analog inputs to the relay. The digital channels may be mapped to any of the opto isolated inputs or output contacts, in addition to a number of internal relay digital signals, such as protection starts, LEDs etc. The complete list of these signals may be found by viewing the available settings in the relay menu or via a setting file in S1 Studio.
Any of the digital channels may be selected to trigger the disturbance recorder on either a low to high or a high to low transition, via the Input Trigger cell. The default trigger settings are that any dedicated trip output contacts (e.g. relay 3) will trigger the recorder.
It is not possible to view the disturbance records locally via the LCD; they must be extracted using suitable software such as S1 Studio. This process is fully explained in the SCADA Communications chapter.
P341/EN MR/G74 Page (MR) 8-15
(MR) 8 Measurements and Recording Measurements
4 MEASUREMENTS
The relay produces a variety of both directly measured and calculated power system quantities. These measurement values are updated on a per second basis and can be viewed in the Measurements columns (up to three) of the relay or via S1 Studio
Measurement viewer. The P341 relay is able to measure and display the following quantities as summarized.
Phase Voltages and Currents
Phase to Phase Voltage and Currents
Sequence Voltages and Currents
Slip
Power and Energy Quantities
Rms. Voltages and Currents
Peak, Fixed and Rolling Demand Values
There are also measured values from the protection functions, which are also displayed under the measurement columns of the menu; these are described in the section on the relevant protection function.
4.1
4.2
4.3
4.4
Measured Voltages and Currents
The relay produces both phase to ground and phase to phase voltage and current values.
They are produced directly from the Discrete Fourier Transform (DFT) used by the relay protection functions and present both magnitude and phase angle measurement.
Sequence Voltages and Currents
Sequence quantities are produced by the relay from the measured Fourier values; these are displayed as magnitude and phase angle values.
Slip Frequency
The relay produces a slip frequency measurement by measuring the rate of change of phase angle, between the bus and line voltages, over a one-cycle period. The slip frequency measurement assumes the bus voltage to be the reference phasor.
Power and Energy Quantities
Using the measured voltages and currents the relay calculates the apparent, real and reactive power quantities. These are produced on a phase by phase. Three-phase values based on the sum of the three individual phase values. The signing of the real and reactive power measurements can be controlled using the measurement mode setting. The four options are defined in Table 7.
Measurement mode
0
(Default)
Parameter
Export Power (Watts)
Import Power (Watts)
Lagging VArs (Import VArs)
Leading Vars (Export Vars)
+
–
+
–
Signing
Page (MR) 8-16 P341/EN MR/G74
Measurements
4.5
4.6
(MR) 8 Measurements and Recording
1
2
3
Measurement mode Parameter
Export Power (Watts)
Import Power (Watts)
Lagging VArs (Import VArs)
Leading Vars (Export Vars)
Export Power (Watts)
Import Power (Watts)
Lagging VArs (Import VArs)
Leading Vars (Export Vars)
Export Power (Watts)
Import Power (Watts)
Lagging VArs (Import VArs)
Leading Vars (Export Vars)
+
–
–
+
–
+
+
–
–
+
–
+
Signing
Table 7 - Power modes
In addition to the measured power quantities, the relay calculates the power factor phase by phase, in addition to a three-phase power factor.
These power values are also used to increment the total real and reactive energy measurements. Separate energy measurements are maintained for the total exported and imported energy. The energy measurements are incremented up to maximum values of 1000 GWhr or 1000 GVArhr at which point they will reset to zero, it is also possible to reset these values using the menu or remote interfaces using the Reset
Demand cell.
For the energy measurements exporting Watts/VArs gives forward Whr/VArhr and importing Watts/VArs gives reverse Whr/VArhr.
Rms. Voltages and Currents
Rms. phase voltage and current values are calculated by the relay using the sum of the samples squared over a cycle of sampled data.
Demand Values
The relay produces fixed, rolling and peak demand values. Using the reset demand menu cell it is possible to reset these quantities via the user interface or the remote communications.
Fixed Demand Values
The fixed demand value is the average value of a quantity over the specified interval; values are produced for each phase current and for three phase real and reactive power. The fixed demand values displayed by the relay are those for the previous interval, the values are updated at the end of the fixed demand period.
Rolling Demand Values
The rolling demand values are similar to the fixed demand values, the difference being that a sliding window is used. The rolling demand window consists of a number of smaller sub-periods. The resolution of the sliding window is the subperiod length, with the displayed values being updated at the end of each of the sub-periods.
Peak Demand Values
Peak demand values are produced for each phase current and the real and reactive power quantities. These display the maximum value of the measured quantity since the last reset of the demand values.
P341/EN MR/G74 Page (MR) 8-17
(MR) 8 Measurements and Recording Measurements
4.7 Settings
The following settings under the heading MEASUREMENT SET-UP can be used to configure the relay measurement function.
Menu text Default settings Available settings
MEASURE’T SETUP
Default Display Description
Description/Plant Reference/ Frequency/Access
Level/3Ph + N Current/3Ph Voltage/Power/Date and Time
This setting can be used to select the default display from a range of options, note that it is also possible to view the other default displays whilst at the default level using the and keys. However once the 15 minute timeout elapses the default display will revert to that selected by this setting.
Local Values Primary Primary/Secondary
This setting controls whether measured values via the front panel user interface and the front courier port are displayed as primary or secondary quantities.
Remote Values Primary Primary/Secondary
This setting controls whether measured values via the rear communication port are displayed as primary or secondary quantities.
Measurement Ref. VA VA/VB/VC/IA/IB/IC
Using this setting the phase reference for all angular measurements by the relay can be selected.
Measurement Mode 0 0 to 3 step 1
This setting is used to control the signing of the real and reactive power quantities; the signing convention used is defined in the
Measurements and Recording chapter,
P341/EN MR.
Fix Dem Period 30 minutes 1 to 99 minutes step 1 minute
This setting defines the length of the fixed demand window.
Roll Sub Period 30 minutes 1 to 99 minutes step 1 minute
The rolling demand uses a sliding/rolling window. The rolling demand window consists of a number of smaller sub periods
(Num Sub Periods). The resolution of the rolling window is the sub period length (Roll Sub Period) with the displayed values being updated at the end of each sub period.
Num Sub Periods 1
This setting is used to set the number of rolling demand sub periods.
1 to 15 step 1
Remote 2 Values Primary Primary/Secondary
This setting controls whether measured values via the 2nd rear communication port are displayed as primary or secondary quantities.
Table 8 - Measurement setup settings
4.8
4.8.1
Menu text
IA Magnitude
IA Phase Angle
IB Magnitude
IB Phase Angle
Measurement Display Quantities
The relay has three Measurement columns for viewing of measurement quantities.
These can also be viewed with S1 Studio and are shown below:
Measurements 1
Data.
Data.
Data.
Data.
Default setting
Min.
MEASUREMENTS 1
Setting range
Max.
Step size
Page (MR) 8-18 P341/EN MR/G74
Measurements
Menu text
VN Derived Mag
V1 Magnitude
V2 Magnitude
V0 Magnitude
VAN RMS
VBN RMS
VCN RMS
Frequency
I1 Magnitude
I1 Phase Angle
I2 Magnitude
I2 Phase Angle
I0 Magnitude
I0 Phase Angle
V1 Magnitude
V1 Phase Angle
IC Magnitude
IC Phase Angle
IN Derived Mag
IN Derived Angle
I Sen Magnitude
I Sen Angle
I1 Magnitude
I2 magnitude
I0 Magnitude
IA RMS
IB RMS
IC RMS
VAB Magnitude
VAB Phase Angle
VBC Magnitude
VBC Phase Angle
VCA Magnitude
VCA Phase Angle
VAN Magnitude
VAN Phase Angle
VBN Magnitude
VBN Phase Angle
VCN Magnitude
VCN Phase Angle
VN Measured Mag
VN Measured Ang
(MR) 8 Measurements and Recording
Default setting
Min.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data. VN.
Data. VN.
MEASUREMENTS 1
Data.
Data.
Data. IN = IA+IB+IC.
Data.
Data.
Data.
Data. Positive sequence current.
Data. Negative sequence current.
Data. Zero sequence current.
Data.
Data.
Data.
Data. VN = VA+VB+VC.
Data. Positive sequence voltage.
Data. Negative sequence voltage.
Data. Zero sequence voltage.
Data.
Data.
Data.
Data.
Data. Positive sequence current.
Data. Negative sequence current
Data.
Data. Zero sequence current.
Data.
Data. Positive sequence voltage.
Setting range
Max.
Step size
P341/EN MR/G74 Page (MR) 8-19
(MR) 8 Measurements and Recording
4.8.2
Menu text
A Phase Watts
B Phase Watts
C Phase Watts
A Phase VARs
B Phase VARs
C Phase VARs
A Phase VA
B Phase VA
C Phase VA
3 Phase Watts
3 Phase VARs
3 Phase VA
3Ph Power Factor
APh Power Factor
BPh Power Factor
CPh Power Factor
3Ph WHours Fwd
3Ph WHours Rev
3Ph VArHours Fwd
3Ph VArHours Rev
3Ph W Fix Demand
3Ph VAr Fix Demand
IA Fixed Demand
IB Fixed Demand
IC Fixed Demand
Menu text
V2 Magnitude
V2 Phase Angle
V0 Magnitude
V0 Phase Angle
C/S Voltage Mag
C/S Voltage Ang
CS Gen-Bus Volt
CS Gen-Bus Angle
Slip Frequency
CS Frequency
Table 9 - Measurements 1
Default setting
Min.
MEASUREMENTS 1
Data. Negative sequence voltage.
Data.
Data. Zero sequence voltage.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Setting range
Max.
Measurements 2
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Data.
Default setting
Min.
MEASUREMENTS 2
Setting range
Max.
Page (MR) 8-20
Measurements
Step size
Step size
P341/EN MR/G74
Measurements (MR) 8 Measurements and Recording
Menu text Default setting
Min.
Setting range
Max.
Step size
MEASUREMENTS 2
3Ph W Roll Demand
3Ph VAr Roll Demand
IA Roll Demand
IB Roll Demand
Data.
Data.
Data.
Data.
IC Roll Demand
3Ph W Peak Demand
3Ph VAr Peak Demand
IA Peak Demand
Data.
Data.
Data.
Data.
IB Peak Demand
IC Peak Demand
Data.
Data.
Reset Demand No No, Yes N/A
Reset demand measurements command. Can be used to reset the fixed, rolling and peak demand value measurements to 0.
Table 10 - Measurements 2
4.8.3 Measurements 3
Menu text
APh Sen Watts
APh Sen VArs
APh Power Angle
Thermal Overload
Reset Thermal O/L
CLIO Input 1
CLIO Input 2
CLIO Input 3
CLIO Input 4 df/dt
Table 11 - Measurements 3
Default setting
Min.
MEASUREMENTS 3
Data.
Data.
Data.
Data. Thermal state.
No No, Yes
Data. Current loop (transducer) input 1.
Data. Current loop (transducer) input 2.
Data. Current loop (transducer) input 3.
Data. Current loop (transducer) input 4.
Data.
Setting range
Max.
4.8.4
Menu text
Max Iac
DLR Ambient Temp
Wind Velocity
Wind Direction
Solar Radiation
Measurements 4
Default setting
Min.
Setting range
Max.
MEASUREMENTS 4
Data. Maximum phase current. (P341 7x)
Data. Ambient Temperature from current loop input. (P341 7x)
Data. Wind Velocity from current loop input. (P341 7x)
Data. Wind Direction from current loop input. (P341 7x)
Data. Solar Radiation from current loop input. (P341 7x)
N/A
Step size
Step size
P341/EN MR/G74 Page (MR) 8-21
(MR) 8 Measurements and Recording Measurements
Menu text
Effct wind angle
Pc
Pc, natural
Pc1, forced
Pc2, forced
DLR Ampacity
DLR CurrentRatio
Dyn Conduct Temp
Steady Conduct T
Time Constant
Table 12 - Measurements 4
Default setting
Min.
Setting range
Max.
Step size
MEASUREMENTS 4
Data. Effective Wind Angle. Intermediate parameter calculated when calculating the convective cooling Pc. (P341 7x)
Data. Convective cooling, takes the maximum value of ‘Pc, natural’, ‘Pc1, forced’, and ‘Pc2, forced’. (P341 7x)
Data. Natural convective cooling, an intermediate value changed according to the selected standard (CIGRE or IEEE). (P341 7x)
Data. Forced convective cooling at low wind speed, an inte