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  • Course Name: SIEMENS SAS
  • Pre-requisite training: DIGSI 4, DIGSI 5, IEC61850
  • Language: English
  • + Supporting Files
  • + Certificate of completion
  • Delivery: Face-to-face / Online
  • Duration: 8 Days
  • Trainer: Dr. Saeed Roostaee (Profile)

Substation Automation System

  • Substation Automation System-an overview
  • SIEMENS SAS In the past
  • SIEMENS SAS Nowadays
  • Network Theory (Types of Communications, Data Transmission Types, MAC Address, IP Address, Subnet Mask)
  • Fundamentals of Communication Via Ethernet Various Topologies
  • Ethernet and IEC 61850 Concepts (The EN100 Communication Module, Time Server, Switch, Network Card)
  • Important Factors for Choosing a Topology
  • Star Topology
  • Ring Topology


  • RUGGEDCOM Ethernet Switch RS900
  • RUGGEDCOM Ethernet Switch RS8000
  • RUGGEDCOM Ethernet Switch RSG2100
  • SIPROTEC Communication Modules
  • Hirschmann Switches
  • Siemens Scalance – Switches
  • Modems
  • I/O-Box 6MD61
  • Bay Controller 6MD66
  • Transformer Regulators
  • SICAM 1703 device series – TM 1703 mic
  • SICAM 1703 device series – TM 1703 ACP
  • SICAM 1703 device series – BC 1703 ACP
  • SICAM 1703 device series – AK 1703 ACP
  • Siemens Serial Modem 7XV5655
  • Siemens converter – Mini star coupler
  • Com-Expander: Comtrol Rocket Port
  • Operator Desk / Engineering PCs
  • Time receiver
  • external time masters
  • NTP-time synchronization with SICLOCK
  • Modem Splitter
  • Station Unit 6MD9101
  • SICAM PAS Station Unit

Bay Level Engineering (IEC 61850 and Modbus)

  • Sample IEC 81850 Configuration
  • Setting the Network Parameters for Ethernet Switches
  • Modbus Connection of Measuring Centers
  • Serial/Ethernet Converter (7XV5655)
  • GPS Satellite Clock
  • IEC 61850 – The Configuration Language SCL File Types at a glance
  • ICD file – IED Capability Description
  • SSD file – Substation Specification Description
  • CID file – Configured IED Description
  • SCD file – Substation Configuration Description
  • IEC 61850 Services in IEDs and SICAM PAS
  • Updating ICD – Files
  • IEC 61850 – creating PAS configuration data
  • Client/Server Communication
  • Publisher / Subscriber Communication
  • Logical Node
  • Data Objects
  • Standardizing Communication with Logical Nodes
  • Addressing control of a circuit breaker
  • Ethernet switches according to IEC61850 specification
  • Ethernet Master clocks
  • IEC61850 Engineering
  • Process of IEC61850 Engineering
  • Diagnosis Tool Networkview
  • Diagnosis Tool IEC-Browser
  • Config signals in the DIGSI 4 Matrix
  • Config signals in the DIGSI 5 IEC61850 structure
  • System Configurator in DIGSI
  • Assign IEDs to the IEC 61850 Station
  • Mapping GOOSE messages
  • Updating device parameter files
  • IEC 61850 Ethernet Medium: FO Ring
  • IEC 61850 Ethernet Configuration: Electrical Star
  • IEC 61850 Ethernet FO-Ring with RuggedCom
  • IEC 61850 Ethernet FO-Ring with optical EN100
  • IEC 61850 Ethernet – Partial Redundant FO-Ring
  • IEC 61850 Ethernet – Redundant FO-Ring
  • IEC 61850 Ethernet – with redundant PAS
  • Sample Real Projects
  • Export of Station Information
  • Import of SCD-File into the SICAM PAS

Station Level Engineering SICAM PAS

  • Introduction to SICAM PAS Automation System
  • SICAM PAS Tasks
  • Fields of Application
  • SICAM PAS Features
  • Scalability – Software and Hardware Configuration for Small to Large Applications
  • Basic Package “ Full Server”
  • Distributed system with higher performance (Full Server + DIP (Device Interface Processor))
  • High availability by Redundancy
  • High flexibility through further interfaces
  • Optional Packages (IEC 61850, Profibus FMS (SICAM/SIPROTEC specified protocols), IEC 60870-5-103, DNP V3.00, Profibus DP, Modbus, ILSA (Internal LSA protocol, OPC-Client, Automation CFC)
  • Substation Automation Functions (Control Authority, Bay Blocking, Telecontrol Blocking, Time Synchronization, Fault Recording, Redundancy)
  • SICAM PAS in Star Configuration
  • SICAM PAS in (Fiber Optic) Ring
  • SICAM PAS FO Station LAN
  • SICAM PAS Installation
  • Licensing
  • Licensing With Feature Enabler
  • SICAM PAS Basic packet and options
  • SICAM PAS Configuration User Administration Tool
  • IEC 61850 Services in IEDs and SICAM PAS
  • SICAM PAS Configuration (Working with Project Databases, Creating a New Database, Adding and Managing Systems, Adding an Application (IEC 61850 Client), Importing a SCD file, Updating One or Several Device(s), Adding ModbusApplication, Parameterizing ModbusApplication, Added EMA90 ModbusMap, Defining the Device Template (ModbusMap), Adding IEC 60870-5-101 Slave Application, Inserting the Control Center of IEC 60870-5-101 Slave, Inserting the SNMP Application, Monitoring IEC 61850 IEDs Connection Status With SNMP, Inserting a PASCC Application to Full Server System, Inserting Control Center to PASCC Application, Inserting a PASCC to a New System (DIP)
  • Creating a Full Server Computer
  • Creating an IEC101-Master to connect the RTU
  • Importing the RTU file
  • Communication IEC 60870-5-103
  • Communication OPC-Client (based on COM/DCOM)
  • Communication OPC-XML-Server
  • SICAM PAS Configuration (Topology Management, Filtering, Topology Tree Structure, Selection of Signals for Each Sub-Level, Modbus (Measuring) Signals
  • SICAM PAS Configuration (Automation (Soft PLC), Logic Processing with CFC, Info to / Com from SoftPLC (Mapping), Creating New CFC Program, Connection of Source and Destination Variables
  • Routing messages from/to SoftPLC
  • Renaming duplicated message
  • Creating a CFC file
  • CFC block
  • Inserting Variable into interconnection column
  • Grouping with a “PAS_GROUPI”-Function Block
  • Converting a Counter Differential Value to a Counter Final Value
  • Interlocking
  • Run Sequence
  • Online Mode
  • Watchlist
  • CDA (Control Data Analyzer) Necessary settings
  • Mapping an output to CDA
  • Human-Machine Control Center Mapping, Exporting of HMI1 Interface
  • How to select a group of messages
  • Normalization
  • Create a Normalization Template
  • Scaling a measured value
  • Normalization as a multiple-used template
  • Assignment of normalization in Mapping
  • Adaptation of transformer tap position indications
  • Archiving Configured Project, Un-archiving Project

SICAM PAS UI-Operation

  • Updating the System
  • Symbols in the tree view
  • Operation – functions
  • Exporting messages from PAS UI Configuration

SICAM PAS Value Viewer

  • Mapping shows the Information Volume
  • SICAM PAS Value Viewer
  • The properties of a message
  • Control function
  • Testing data
  • Important columns
  • ValueViewer: Communication diagnostics


  • Fault recording with SICAM PQS
  • SICAM PQS – Functional Overview
  • Incident Explorer
  • PQ Explorer
  • Grid Code Viewer
  • Report Browser
  • PQ Inspector


  • IEC 60870-5-101, the telecontrol profile
  • IEC 60870 – 5 – 101 The most important features
  • IEC 60870 – 5 – 101 telegram structure
  • Type Identification in monitoring direction
  • Type Identification in command direction
  • Type Identification for organization objects
  • Type Identification for parameters
  • Quality Information
  • IEC 60870-5-102, the counter profile
  • IEC 60870-5-103, the IED/protection relay profile
  • Creating an IEC103-Master and Interface
  • Communication Parameters
  • Data Units specified in IEC 60870-5-103
  • Info Identification in PAS for IEC 60870-5-103
  • IEC 60870-5-104, the network profile (based on 60870-5-101)
  • Software IECTEST
  • Settings for IEC 60870-5-104
  • IEC 60870-5-104 Slave – Control Center Simulation


  • Export of HMI information from SICAM PAS
  • Check the content of a PXD file
  • Introduction to SICAM PASCC Control Center
  • SICAM PASCC Control Center ‐ Overview
  • SICAM PASCC Components
  • SICAM PASCC Communication
  • SICAM PAS Wizard
  • WinCC Explorer
  • Graphic Objects Library
  • Switchgear Objects
  • Schwitchgear Objects – Styles and States
  • Alarm Logging – Message List
  • Control & Monitoring
  • WinCC & PASCC Licensing
  • SIMATIC WinCC / SICAM PASCC Installation Steps
  • Transfer The License Keys
  • SIMATIC WinCC / SICAM PASCC Time Synchronization & NTP
  • SICAM PASCC Starting The WinCC/PASCC Software
  • SICAM PASCC Creating/ Opening a New Project
  • SICAM PASCC Defining The Computer Properties General Tab, Startup Tab, Parameters Tab, Graphics Runtime Tab
  • Adding a Communication Driver
  • Connection Properties
  • Entering the IP Address of SICAM PAS Servers
  • SICAM PAS Wizard Opening
  • Error Log File of SICAM PAS Wizard
  • Select a Right SICAM PAS Protocol Suite
  • Set PAS IP Connection
  • Importing of the Sample Pilot Project .pxd File
  • Redefining the failed Sample Project
  • Checking Structure Tags of a New Project
  • Structure Tag Elements
  • Symbol Library
  • SICAM Administrative Internal Tags
  • Schwitchgear Objects – Tag Connection
  • Design of Graphical Objects
  • Switchgear Objects – Sychro-Check
  • Alarm Logging – Events & Alarms
  • Alarm Logging – Message Queue & Mes Ack Tags
  • Tag Logging – Measured Values
  • WinCC Horn Tools– Sound File
  • Tag Logging – Archive Configuration
  • Trends Picture
  • Topological coloring
  • Event List
  • Alarm List
  • Protection Message List
  • Horn, Alarm Acknowledgment
  • Creating an Event List in the Graphics Designer
  • How to scale analog values
  • User Administrator
  • Login-Function via key combination
  • Login via button
  • Defining level of rights
  • Entering the requested right
  • Displaying the current operator
  • Report Designer – Print Job
  • Project Archive, Duplicator
  • Automatic Start of WinCC Project
  • Recpro
  • Setting Up SICAM PAS Recpro
  • SICAM VALPRO – Graphic functions
  • Bay Blocking


  • Redundancy Definition
  • Dependency Definition
  • Redundant Communication
  • System Switchover
  • Manual Switchover
  • Redundant “Full Server – DIP” Configuration
  • Configuring a Redundant System
  • Transferring a database to a Redundant System
  • Status indication in a redundant system
  • Single Channel IEDs
  • IED Redundancy
  • System Redundancy
  • Communication with Control Center
  • Control Center with one interface
  • Control Center with 2 Interfaces
  • Communication via WAN Network

Example: Switching Authority in SICAM PAS

  • Switching Authority Group
  • Routing to PAS CC
  • Switching Authority Tag
  • SICAM PAS CC symbol library
  • Configuring Button Switching Authority
  • Test the Switching Authority

OPC Communication

  • What is OPC ?
  • OPC Applications
  • Overview of OPC data flow
  • OPC Server & Client
  • Config OPC Server in the SICAM PAS UI-Configuration
  • OPC Client
  • OPC-XML-Server
  • Difference between the OPC-XML-Server with the previous OPC
  • Creating OPC XML Server in SICAM PAS

Additional Information

  • Automation License Manager
  • Tasks to be started with the Runtime
  • Language and Key Disabling
  • Graphics Runtime
  • Data structure (monitoring/control direction)

Hardware Setup for SIEMENS SAS training

  • SIPROTEC 5 Multifunction Relay IED
  • Fiber optic to Ethernet converter
  • Ethernet Switch
  • PLC S7-1200
  • PC (IEDScout, DIGSI4, DIGSI5, SICAM PAS, WinCC, TIA Portal, SICAM SCC, Wireshark, IEC61850 Configurator …)


  • Course Name: SIPROTEC 5 and DIGSI 5 (advanced)
  • Trainer: Dr. Saeed Roostaee
  • Format: Pre-recorded videos (demo is available)
  • Course creation: June 2023
  • Last update: July 2023

Note: This course can also be held either Online or Face to face based on the request

Course Structure:

  • Module 1: SIPROTEC 5 Hardware and ordering
  • Module 2: Starting with DIGSI 5
  • Module 3: Working with SIPROTEC 5 in online mode
  • Module 4: System Functions
  • Module 5: Function Groups
  • Module 6: SIPROTEC 7SJ8
  • Module 7: SIPROTEC 7SA8
  • Module 8: SIPROTEC 7UT8
  • Module 9: SIPROTEC 7SS8
  • Module 10: SIPROTEC 7SK8
  • Module 11: SIPROTEC 7VK8
  • Module 12: SIPROTEC 7SD8
  • Module 13: SIPROTEC 7SL8
  • Module 14: SIPROTEC 7SX8
  • Module 15: SIPROTEC 7UM8
  • Module 16: SIPROTEC 7MD8
  • Module 17: Functions and Settings
  • Module 18: Signals and Masking IO
  • Module 19: CFC
  • Module 20: Control Functions
  • Module 21: Display Page configuration
  • Module 22: Functional Tests
  • Module 23: Measured Values
  • Module 24: Power Quality
  • Module 25: Supervision
  • Module 26: Communication
  • Module 27: IEC 61850
  • Module 28: Digital Twin
  • Module 29: Case Study 7UT8
  • Module 30: Case Study 7VK8
  • Module 31: Case Study 7SA8
  • Module 32: Case Study 7SS8

Course Details (Note: This part is continuously updating)

Module: SIPROTEC 5 Hardware and order

  • SIPROTEC5 Hardware
  • DIGSI 5 installation and DDD
  • General Settings
  • DIGSI 5 User interface
  • New project + Add device (Offline)
  • Modify the order code in the SIPROTEC online configurator
  • SIPROTEC 5 Online Configurator
  • Function Point
  • SIP 5 Configuration Procedure

Module: Online & Working with SIPROTEC 5

  • Connect to SIPROTEC 5
  • Indications
  • Fault Recording
  • Log
  • Reading Indications on the On-Site Operation Panel
  • Reading Indications from the PC with DIGSI 5
  • Displaying Indications
  • Operational Log
  • Fault Log
  • Switching-Device Log
  • Ground-Fault Log
  • Setting-History Log
  • User Log
  • Security Log
  • Device-Diagnosis Log
  • Communication Log
  • Communication-Supervision Log
  • Motor-Starting Log
  • Saving and Deleting the Logs
  • Spontaneous Indication Display in DIGSI 5
  • Spontaneous Fault Display on the On-Site Operation Panel
  • Stored Indications in the SIPROTEC 5 Device
  • Resetting Stored Indications of the Function Group
  • Test Mode and Influence of Indications on Substation Automation Technology
  • Changing the Transformation Ratios of the Transformer on the Device

Module: System Functions

  • Sampling-Frequency Tracking and Frequency Tracking Groups
  • Text Structure and Reference Number for Settings and Indications
  • Processing Quality Attributes
  • Protection Communication
  • Date and Time Synchronization
  • User-Defined Objects
  • Device Settings
  • Data Types
  • Function Control
  • Connection Examples
  • Chatter blocking
  • Settings-Group Switching

Module: Function Groups

  • Voltage current 3-Phase
  • Circuit-breaker
  • Process Monitor
  • Voltage-current 1-phase
  • Motor
  • Line
  • Voltage 3-Phase
  • Analog Units
  • User-Defined Function Group
  • Recording
  • Motor Monitor
  • Current-Flow Criterion
  • Circuit-Breaker Condition for the Motor
  • Closure Detection
  • Motor-State Detection
  • Cold-Load Pickup Detection
  • Thermal Replica Rotor
  • Capacitor Bank

Module: Functions and Settings

  • Power-System Data
  • Overcurrent Protection, Phases
  • Overcurrent Protection, Ground
  • Line Differential Protection
  • Stub Differential Protection
  • Restricted Ground-Fault Protection
  • Distance Protection with Reactance Method (RMD)
  • Distance Protection with Classic Method
  • Impedance Protection
  • Power-Swing Blocking
  • Teleprotection with Distance Protection
  • Universal Teleprotection with Distance Protection
  • Ground-Fault Protection for High-Resistance Ground Faults in Grounded Systems
  • Teleprotection with Ground-Fault Protection
  • Universal Teleprotection with Ground-Fault Protection
  • Echo and Tripping in the Event of Weak Infeed 874
  • Tripping with Missing or Weak Infeed According to French Specification
  • External Trip Initiation
  • Automatic Reclosing Function
  • Directional Overcurrent Protection, Phases
  • Positive-Sequence Overcurrent Protection
  • Instantaneous High-Current Tripping
  • Group Indications of Overcurrent Protection Functions
  • Overcurrent Protection, 1-Phase
  • Voltage-Dependent Overcurrent Protection, Phases
  • Sensitive Ground-Fault Detection
  • Non-Directional Intermittent Ground-Fault Protection
  • Directional Intermittent Ground-Fault Protection
  • Negative-Sequence Protection
  • Directional Negative-Sequence Protection with Current-Independent Time Delay
  • Undercurrent Protection
  • Overvoltage Protection with 3-Phase Voltage
  • Overvoltage Protection with Positive-Sequence Voltage
  • Overvoltage Protection with Negative-Sequence Voltage
  • Overvoltage Protection with Positive-Sequence Voltage and Compounding
  • Overvoltage Protection with Zero-Sequence Voltage/Residual Voltage
  • Overvoltage Protection with Any Voltage
  • Undervoltage Protection with 3-Phase Voltage
  • Undervoltage Protection with Positive-Sequence Voltage
  • Undervoltage Protection with Any Voltage
  • Rate-of-Voltage-Change Protection
  • Undervoltage-Controlled Reactive-Power Protection
  • Voltage-Comparison Supervision
  • Fault Locator
  • Fault Locator Plus
  • Over frequency Protection
  • Under frequency Protection
  • Rate of Frequency Change Protection
  • Under frequency Load Shedding
  • Phase-Sequence Switchover
  • Instantaneous Tripping at Switch onto Fault
  • Thermal Overload Protection, 3-Phase – Advanced
  • Thermal Overload Protection, 1-Phase
  • Temperature Supervision
  • Circuit-Breaker Failure Protection
  • Circuit-Breaker Restrike Protection
  • Out-of-Step Protection
  • Inrush-Current and 2nd Harmonic Detection
  • Power Protection (P, Q), 3-Phase
  • Current-Jump Detection
  • Voltage-Jump Detection
  • Vector-Jump Protection
  • Arc Protection
  • Voltage Measuring-Point Selection

Module: Specific Functions

  • Current-Unbalance Protection for Capacitors, 1-Phase
  • Peak Overvoltage Protection for Capacitors
  • Motor-Starting Time Supervision
  • Motor Restart Inhibit
  • Load-Jam Protection Motor
  • Thermal Overload Protection, Rotor

Module: Control Functions

  • Introduction
  • Switching Devices
  • Switching Sequences
  • Control Functionality
  • Synchronization Function
  • User-Defined Function Block [Control]
  • CFC-Chart Settings
  • Tap Changers
  • Voltage Controller
  • Point-on-Wave Switch

Module: Functional Tests

  • Direction Test of the Phase Quantities
  • Functional Test Protection Communication
  • Functional Test of the Line Differential Protection
  • Functional Test for Overvoltage Protection with Zero-Sequence Voltage/Displacement Voltage
  • Primary and Secondary Tests of the Circuit-Breaker Failure Protection
  • Circuit-Breaker Test
  • Out-of-Step Protection Function Test
  • Functional Test of the Inrush-Current Detection
  • Functional Test of the Trip-Circuit Supervision
  • Power-Swing Blocking Functional Test
  • Functional Test for the Phase-Rotation Reversal
  • Functional Test for Overvoltage Protection with Zero-Sequence Voltage/Residual Voltage
  • Directional Testing for Isolated or Resonant-Grounded Systems
  • Primary and Secondary Testing of the Synchronization Function
  • Commissioning Hints for Voltage Control

Module: Measured Values

  • Operational Measured Values
  • Fundamental and Symmetrical Components
  • THD and Harmonics
  • Minimum/Maximum Values
  • Average Values
  • Energy Values
  • Circuit-Breaker Monitoring
  • Statistical Values of the Primary System

Module: Power Quality

  • Voltage Variation
  • Voltage Unbalance
  • THD and Harmonics
  • Total Demand Distortion

Module: Supervision

  • Resource-Consumption Supervision
  • Supervision of the Secondary System
  • Supervision of the Device Hardware
  • Supervision of Device Firmware
  • Supervision of Hardware Configuration
  • Supervision of Communication Connections
  • Error Responses and Corrective Measures
  • Group Indications

Module: IEC 61850

  • External Signals
  • Quality Processing/Affected by the User for Received GOOSE Values
  • Quality Processing/Affected by the User in CFC Charts
  • Quality Processing/Affected by the User in Internal Device Functions

More info and update about this course: Contac us

To participate in this face-to-face / online training course: contact us

Reference Publication Type Title Value-added products Current Version

  • IEC TS 61850-1-2: 2020 TS Part 1-2: Guideline on extending IEC61850 2020
  • IEC TS 61850-1-2: 2020/AMD1:2022 TS Part 1-2: Guideline on extending IEC61850 Amendment 1 Consolidated Version 2022
  • IEC TS 61850-2: 2019 TS Part 2: Glossary 2019
  • IEC 61850-7-1: 2011/AMD 1: 2020 IS Part 7-1: Basic communication structure – Principles and models Amendment 1 Consolidated Version 2020
  • IEC 61850-7-2: 2010/AMD 1:2020 IS Part 7-2: Basic information and communication structure – Abstract communication service interface(ASCI) Amendment 1 Consolidated Version 2020
  • IEC 61850-7-3: 2010/AMD1:2020 IS Part 7-3: Basic communication structure – Common data classes Amendment 1 Consolidated Version 2020
  • IEC 61850-7-4: 2010/ AMD 1: 2020 IS Part 7-4: Basic communication structure – Compatible logical node classes and data object classes Amendment 1 Consolidated Version 2020
  • IEC TR 61850-7-5: 2021 TR Part 7-5: IEC 61850 modelling concepts 2021
  • IEC TR 61850-7-6: 2019 TR Part 7-6: Guideline for definition of Basic Application Profiles (BAPs) using IEC61850 2019
  • IEC TS 61850-7-7: 2018 TS Part 7-7: Machine processable format of IEC 61850-related data models for tools 2018
  • IEC TS 61850-7-7: 2018/ AMD 1: 2023 TS Part 7-7: Machine processable format of IEC 61850-related data models for tools Amendment 1 Consolidated Version 2023
  • IEC 61850-7-410: 2012 IS Part 7-410: Basic communication structure – Hydroelectric power plants – Communication for monitoring and control 2012
  • IEC 61850-7-410: 2012/AMD 1: 2015 IS Part 7-410: Basic communication structure – Hydroelectric power plants – Communication for monitoring and control Amendment 1 Consolidated Version 2015
  • IEC 61850-7-420: 2021 IS Part 7-420: Basic communication structure – Distributed energy resources and distribution automation logical nodes. 2021
  • IEC TR 61850-7-500: 2017 TR Part 7-500: Basic information and communication structure – Use of logical nodes for modeling application functions and related concepts and guidelines for substations. 2017
  • IEC TR 61850-7-510: 2021 TR Part 7-510: Basic communication structure – Hydroeletcric power plants, steam and gas turbines – Modelling concepts and guidelines. 2021
  • IEC 61850-8-1: 2011/AMD1:2020 IS Part 8-1: Specific communication service mapping (SCSM) – Mappings to MMS (ISO 9506-1 and ISO 9506-2) and to ISO/IEC 8802-3 Amendment 1 Consolidated Version 2020
  • IEC 61850-8-2:2018 IS Part 8-2: Specific communication service mapping (SCSM) – Mappings to extensive Messaging Presence Proptocol (XMPP). 2018
  • IEC 61850-9-2: 2011/AMD1:2020 IS Part 9-2: Specific communication service mapping (SCSM) – Sampled values over ISO/IEC 8802-3 Amendment 1 Consolidated Version 2020
  • IEC/IEEE 61850-9-3:2016 IS Part 9-3:Precision time protocol profile for power utility automation. 2016
  • IEC 61850-10: 2012 IS Part 10: Conformance testing 2012
  • IEC TR 61850-10-3:2022 TR Part 10-3: Functional testing of IEC 61850 systems. 2022
  • IEC TS 61850-80-1:2016 TS Part 80-1: Guideline to exchanging information from a CDC-based data model; using IEC 60870-5-101 or IEC 60870-5-104 2016
  • IEC TR 61850-80-3:2015 TR Part 80-3: Mapping to web protocols – Requirements and technical choices 2015
  • IEC TS 61850-80-4:2016 TS Part 80-4: Translation from the COSEM object model (IEC 62056) TO the IEC 61850 data model 2016
  • IEC TR 61850-90-1:2010 TR Part 90-1: Use of IEC 61850 for the communication between substations 2010
  • IEC TR 61850-90-2:2016 TR Part 90-2: Using IEC 61850 for communication between substations and control centres 2016
  • IEC TR 61850-90-3:2016 TR Part 90-3: Using IEC 61850 FOR condition monitoring diagnosis and analysis 2016
  • IEC TR 61850-90-4:2020 TR Part 90-4: Network engineering guidelines 2020
  • IEC TR 61850-90-5:2012 TR Part 90-4: Use of IEC 61850 to transmit synchrophasor information according to IEEE C37.118 2012
  • IEC TR 61850-90-6:2018 TR Part 90-6: Use of IEC 61850 for Distribution Automation Systems 2018
  • IEC TR 61850-90-7:2013 TR Part 90-7: Object models for power converters in dictributed energy resources (DER) systems. 2017
  • IEC TR 61850-90-8:2016 TR Part 90-8: Object model for E-mobility 2016
  • IEC TR 61850-90-9:2020 TR Part 90-9: Use of IEC 61850 for Electrical Energy Storage Systems 2020
  • IEC TR 61850-90-10:2017 TR Part 90-10: Models for scheduling 2017
  • IEC TR 61850-90-11:2020 TR Part 90-11: Methodologies for modelling of logics for IEC 61850 based applications 2020
  • IEC TR 61850-90-12:2020 TR Part 90-12: Wide area network engineering guidelines 2020
  • IEC TR 61850-90-13:2021 TR Part 90-13: Deterministic network technologies 2021
  • IEC TR 61850-90-14:2021 TR Part 90-14: Using IEC 61850 FOR facts (flexible alternate current transmission systems), HVDC (high voltage direct current) transmission and power conversion data modelling 2021
  • IEC TR 61850-90-16:2021 TR Part 90-16: Requirements of system management for Smart Energy Automation 2021
  • IEC TR 61850-90-17:2017 TR Part 90-17: Using IEC 61850 to transmit power quality data. 2017


The IEC 61850 source code library allows a fast and cost-efficient implementation of the IEC 61850 protocols (MMS, GOOSE, Sampled Values) into devices and applications. The APIs are designed to be very easy to use. The basic library is written in C (C99 compliant to provide maximum portability). Due to its hardware and platform-independent design, it can quickly deploy on any platform.

C#.NET Component

The C# library allows the creation of a managed DLL component that can easily be deployed in .NET applications. It is a wrapper of the C library. It can be used to be integrated into GUI applications, SCADA systems …

  • Compatible with .NET and Mono
  • Runs on Windows, Linux, and other platforms supported by .NET and Mono
  • Very easy-to-use API
  • Support for MMS client/server
  • Support for GOOSE/SV subscribers

Features Source Code Library

  • Easy to use IEC 61850 oriented API
  • MMS, GOOSE, and Sampled Measured Values (SMV)
  • TLS support
  • Support editions 1, 2, and 2.1 of the standards
  • Configurable generation of server data models from SCL/CID file at runtime
  • Peer-reviewed and secure source code
  • C library (C99) with C and C#/.NET API

Source codes that you see in this package:

  • MMS client/server, GOOSE (IEC 61850-8-1)
  • Sampled Values (SV – IEC 61850-9-2)
  • Support for buffered and unbuffered reports
  • Online report control block configuration
  • Data access service (get data, set data)
  • online data model discovery and browsing
  • all data set services (get values, set values, browse)
  • dynamic data set services (create and delete)
  • log service
    • flexible API to connect custom databases
    • comes with sqlite implementation
  • MMS file services (browse, get the file, set file, delete/rename the file)
    • download COMTRADE files
    • upload firmware or configuration files
  • Setting group handling
  • Service tracking (v1.5)
  • GOOSE and SV control block handling
  • TLS support

Application That can create with this library:

  • Communications in Substations (MMS/GOOSE/SV)
  • Communications for Wind Power Plants (IEC 61400-25)
  • Communications for Decentralized Energy Resources (DER – IEC 61850-420)
  • Intelligent Electronic Devices (IED)
  • Measurement Devices
  • SCADA Systems
  • Monitoring
  • Test systems

Easy programming and development of Scada and Monitoring System for protection Relays and other devices that compatible with IEC 61850 Standard with this package

Click here to enroll in the course and get the certificate of the IEC 61850 compilation course

Substation Automation System Training
Substation automation System Training digsi 4 config
Substation Automation System Training 6md bay controller
Substation Automation System Training sicam pass

6 days of training at your place by Dr. Saeed Roostaee

  • ABB relays history
  • PCM and connectivity pack installation
  • An overview of the PCM 600 functionality
  • Establish communication between the physical IED and PCM 600
  • Manage project with PCM 600
  • Hardware configuration
  • Application configuration tool
  • Read and write the tool in the PCM 600
  • IED online monitoring and signal monitoring
  • Event viewer and disturbance handling
  • signal matrix editor tool
  • Parameter setting tool in the PCM 600
  • Writing configuration into IED
  • Interlocking between application configuration and signals matrix tool in PCM600
  • function blocks and naming based on IEC 61850 standard, IEC symbol, and ANSI code
  • Distance protection function configuration
  • 67N protection function configuration
  • How to test ABB relays

  • How to install DIGSI 4
  • Introduction to SIPROTEC Relay families
  • wiring connection
  • start with DIGSI 4
  • Archive, import, export
  • Masking I/O
  • Default and Control Display
  • CFC
  • Power system data 1
  • Setting Group
  • Oscillographic Fault Recorders
  • General Device Settings
  • SIPROTEC 5 – Devices and Fields of Application
  • The basic function of SIPROTEC 5
  • Installing DIGSI 5
  • DIGSI Device Drivers
  • Add new device
  • The online SIPROTEC 5 configurator
  • DIGSI 5 User interface and general setting
  • Distance relay configuration
  • Display Page configuration
  • CFC Configuration
  • busbar configuration
  • How to test SIPROTEC relays

  • An introduction to IEC 61850 & how to learn it effectively
  • Overview of the main features of IEC 61850
  • IEC 61850 data structure and data format
  • IEC 61850 station in DIGSI 5 and IEC 61850 System Configurator
  • GOOSE configuration and the publisher/subscriber LNs
  • GOOSE simulation via IEDScout
  • GOOSE configuration and simulation between different relays
  • Time synchronization settings and SNTP configuration
  • IEC 61850 configuration in DIGSI 4

IP communication is being extensively introduced into the operation of the Electrical Power Utility. The substation IP network environment has evolved from acting as an extension of the office LAN to a state, where it is carrying multiple services, including the transport of critical and sensitive data.
IP communication, being a one-platform solution that relieves you from designing and maintaining more than one
network, is not a one-technology solution. Therefore, the implementation of an IP network needs to be carefully planned to achieve the expected scalability and performance.
This Technical Brochure includes the following:

  • A compilation of user requirements and expectations concerning existing and envisaged services in the new
  • networked environment of the substation.
  • A description of possible network migration processes
  • Guidelines on how to choose an optimum network architecture
  • A description of important parameters to be considered for each relevant technology.
  • Six case studies describing project and process experiences

Communication Architecture for IP-Based Substation Applications Download

– Anyone knows why we are using this diode and what it uses
1) Normal Diode allows current to flow in forwarding bias.
2) Zenner Diode allows current to flow in reverse bias only.

-Two phases show negative values but one phase shows positive values, how?
– Depend on load, may you try to trace 3 line diagram until load (wiring internal of load equipment). Depending on load, may you try to trace 3 line diagram until load (wiring internal of load equipment)
– If the vts at 3phases are exposed to fault what is the overcurrent protection behavior on this circuit? If all the electrical protections failed at the substation and just the physical protection operate what is the problem with this substation?

1), how we can detect CT saturation in the case of Low Impedance Relays?
2). Why is it essential to detect CT saturation only in case of low impedance Relays?
– I need a proper to the point response (no white paper/presentation please) for my proper understanding of this CT saturation detection technique.

– Can anyone tell me about the 400kV Busbar protection type?

– What is the main Function of the CSD relay?
– Controlled switching device (either implemented using a point on wave device or pre-insertion resistors in circuit breakers) helps achieve switching at either voltage zero or current zero (depending on the equipment to be switched) for instance a capacitor bank you would switch at voltage zero whereas for an inductor you would switch at current zero. CSD is typically applied in long transmission lines, filter banks, or converter transformers. By using CSD in the above cases it helps to prevent switching overvoltages or high inrush currents in the transformers.
– Can I use it for Breaker controlling?
– Basically, that’s what it does it controls the breaker to close or open at a certain point on the current or voltage waveform.

– What is the main purpose of reactors in the Power grid?
– Used for Reactive power compensation and to reduce Ferrantic effect, Reduce THD. also means Total harmonic distortion. Maintains Stable voltage profile by reducing Ferranti effect

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– What is the purpose of node VT Inside GIS, It’s 500kV?
– In 400kV or above voltage in line bay PT is also used. So this node PT is considered as line PT

– Maybe he’s asking what is the function of Node VT in SLD installed.
– I believe this PT is used for high metering and protection purposes at 500kV. Yes function of node VT in 500 kV GIS. Protection and metering at line side income. please see also of another VT in here At each bay Line and ATR or is considered for differential protection?
– try to find the secondary wire
– I think this is right: Synch + OV Protection in EHV system As a voltage Synchron check

– How to calculate 1ph & 3ph pickup for T60 relay
– Better refer to T60 Manual. The formula was given to calculate 1ph and 3 ph pickup. Check GE website

– What is the difference between Earthing transformer and NGR?
– Earthing transformer is used to provide grounding to the ungrounded electrical system or delta-connected system.
Whereas NGR is a grounding system, which is used to limit Earth fault current at a certain value.
– Where it is used widely?
– It is used for Generators, motors. This means wherever rotating machines are there we can use NGR to limit the earth fault current for preventing stator core to get damaged.
– NGR is a neutral grounding reactor. It is used to cancel the capacitive current during fault. It’s effective in single-phase fault when a fault occurs on one phase and capacitive current flows from normal phases. NRG causes reactive to neutralize the capacitive Current from healthy phases.

– Can anyone let me know how to monitor the I/O IN CFC online mode the actual values in CFC?
– Siemens relay
– which logic do you want to monitor?
– Any logic I want to monitor the actual IO values
– Same as in MICOM
– want to see the values in SIEMENS CFC logic
– Watch ON in Siemens software is not activated
– Resistor and reactor are both different components, the reactor is basically used on long TX lines where single-phase tripping is allowed.
– For controlling fault current of very low magnitude, a resistor should be chosen. However, where you need to limit the fault current of the magnitude of thousands of amps, you must choose a quality power reactor.
– NGR is never a Neutral Grounding Reactor.
It is always a Neutral Grounding Resistor (NGR). NGR is installed to a) limit the earth fault current below the full load current of transformer/ Generator to protect its lamination
b). This earth fault current must be greater than the capacitive current in the system (generated through the Bus-ducts, cables ) so that Arcing fault doesn’t take place across the NGR.
– Resistance and Reactor are resistors.

– In my company has a 14.24MW generator. Generator rotor resistance is changing continuously from 20 to 60 Kohm. What would be the reason behind it?
– Because of this rotor earth fault stage 1 operated because the setting is about 25kohm
– We also measure the current in earthing cable which is connected to the rotor shaft with slipring
– Temperature also changing?
– Not measured
– Resistance related to isolation, isolation related to temperature

– I want to know how to configure AR Block in P841. I have assigned one output contact and it is continuously high.
– If you are assigning AR block output contact with AR block DDB then it will remain high as long as the AR func is enabled, Use your conditions in the OR gate for AR block output contact. Not the DDB
– The output is continuously high either the function is off or on!
– Yep I remember. It will remain high. As its, the DDB used for other purposes during AR function
– Use your blocking conditions in OR gate for Output contact, not this DDB
– Anyone can share the procedure of the bump test motor.

– In a one and a half breaker scheme, the current magnitude from Q1 CB is different from Q3 CB, Can anyone explain this reason? The line is terminating between Q1 and Q3 CB. Also, there is a neutral current of 40A flowing from these CBS
– alarm is on both governors
– You may be done to check Fuel Management of that Turbine
– That looks like using PID & Close loop control system
A governor is a system that is used to maintain the mean speed of an engine, within certain limits, under fluctuating load conditions. It does this by regulating and controlling the amount of fuel supplied to the engine. The governor hence limits the speed of the engine when it is running at the no-load condition, i.e it governs the idle speed, and ensures that the engine speed does not exceed the maximum value as specified by the manufacturers.

– All marine vessels need a speed control system to control and govern the speed of the propulsion plant being used onboard, as there can be a large number of variations that arise on engine load, which may damage the engine and cause loss of life and equipment. The variations in the load on the engine may arise due to several factors such as rough seas, rolling and pitching of the vessel, compromised ship structure, changes in weight of the ship among others. what could be the reason for fuel management?
– And usually for power generation (coupling to generator) also considering the internal turbine/engine/generator/auxiliary condition. All speed control systems
almost use logic gate Proportional Integral Derivative.
– Safety and performance reasons.
– An increase in the load decreases engine speed. In this case, the flyweights move inwards, and that the governor spindle moves downward under the action of the force of the speeder spring. This movement lowers the pilot control valve which directs oil to the underside of the power piston.
As the hydraulic pressure on the piston overcomes the spring force acting on it, the piston moves upward and the fuel supply to the system engine is increased. hence increasing its speed. Once the RPM of the engine increases, the control valve rises back to its initial position that blocks the delivery of hydraulic fluid to the power piston.
On the other hand, as the load on the engine is decreased and its speed increases, the outward movement of the flyweights under the action of the additional centrifugal force causes subsequent upward movement of the spindle and hence the pilot control valve rises as well. This opens the port such that the hydraulic oil in the system flows to the oil sump from under the power piston through a drainage passage. The power piston then moves downwards under the action of the spring force and reduced hydraulic pressure and hence reducing the amount of fuel supplied to the engine is decreased. This reduces the engine speed and consequently, the forces on the flyweights are balanced once again. When operating generator synchronized, speed control merged with load sharing control system.
-Internal and external parameters are being calculation to the desire of speed of the engine/turbine.
– An Electronic governor provides engine speed adjustment from no-load condition to full load. It consists of a Controller, an Electro-Magnetic Pickup (MPU), and an actuator (ACT) to carry out the necessary speed control and regulation. The MPU is a micro-generator and has a magnetic field. It consists of a permanent magnet with an external coil winding. As shown in the diagram, the MPU is installed above the flywheel teeth, and depending upon its distance from the gear teeth or slot, the magnetic field of the MPU varies from a maximum to minimum respectively.
Due to the constantly changing internal magnetic field, an AC voltage and frequency are generated in the outer conducting coil. This AC voltage follows the speed of the flywheel. This is the most important aspect of the electronic control system as the governor controller converts the obtained frequency into a DC voltage signal. It then compares this with a set voltage. The results are calculated by a PID control (Proportional-integral-differential) and finally, the output reaches the actuator which implements the required corrections on the fuel supply to the engine.

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– we have 2 generators running in parallel. Parallel operating should be using load-sharing control mode or speed droop control mode to desire speed control of the engine.
– Yes
– Anyway, What are the model of both turbines?
– You will see at the logic control real-time/configuration software. That mentions dead band value. Then that will answer your question.
– have you manual of this 505 governor?
– Almost all types of governors are fitted with a flyweight assembly. Two or Four flyweights are mounted on a rotating ball head that is driven directly by the engine shaft, using a gear drive assembly. The rotation of the ball heads creates a centrifugal force that acts on the flyweights of the assembly and causes them to move outward, away from their axis of rotation. As the speed of rotation is increased and the degree of outward movement of the flyweights also increases, and vice versa, and hence the movement of the flyweights depends on the engine speed.
A spring is installed to counteract the centrifugal force generated on the flyweights and force them towards their initial position. This spring is known as the speeder spring. The position of the flyweights and their outward movement is transmitted to a spindle (this may be done through a collar), which is free to move in a reciprocating fashion. The movement of this spindle, which forms the control sleeve, actuates a linkage to the fuel pump control and ultimately controls the amount of fuel injected.
– Under normal operational circumstances, i.e. constant speed and loads, the control sleeve remains stationary as the force on the flyweights is balanced by the counteracting force exerted by the speeder spring.
As the load on the engine is increased, the speed of the engine reduces and the control sleeve moves downward, as the force exerted on it by the speeder spring overcomes the force exerted by the flyweights.
The downward movement of the sleeve is linked to the fuel control racks such that there is an increase the fuel delivery and thus the power generated by the engine. The force on the flyweights increases with the engine RPM and once again the system comes back to equilibrium.
As the load on the engine is decreased, its speed increases. The flyweights move outward and in turn, the control sleeve moves up as the centrifugal force overcomes the speeder spring force. The movement of the sleeve actuates the fuel pump, fuel delivery is lowered, thus the speed of the engine is reduced and the system comes into equilibrium.

– I’m exporting the ICD file for GE’s L90 but the IED name seems to be exported as a template. Does anyone know the reason?
– These are the server configurations with the IED name.
– What are the Commissioning procedures of HV/EHV equipment and different types of tests required before and After Energising the new lines/feeders, Transformers/Reactors?
-I need help to analyze this Disturbance Fault Record whether it is due to Lighting or Flash
– It was fault on Line Diff and Reclose on Phase R support team: Protection Relay Discussion Group invitation link:

– how to know the wave of the current and voltage whether it was short on an insulator or due to the lightning strike?
– SF6 is good? Contact Resistance of CB checked during commissioning?
– I think CB operates at the right time.
– I think is not about a simultaneous issue, but probably a contact point issue. This is a disturbance record from a relay right?
– How can you say it is a lightning strike?
– We check it by climbing on the tower located from the Fault Locator relay.
– What is the full form STUB?
– Stub is the noun itself. No full form
– When the isolator is open, keeping CBS closed in one and a half, this whole arrangement is known as stub bus. The stub is in one and a half breaker scheme

– Micom p841 auto recloser does not save disturbance record. Can anyone state what could be the reason?
– You tried to extract from disturbance records Or Check whether the fault trigger is triggered by all BI & BO?
– When I try to extract from the relay, it shows no disturbance record found
– That means, please check your PSL file
– Nothing triggered
– Change duration, trigger position. Input 1 trigger, change to L/H
– I have the p443 relay installed and its DR is working fine and configured as shown below. Likewise, change all digital inputs as per your requirement, Then check your PSL file.
– Both P441 and P841 PSL, how fault trigger input assigned?

– Relay is switching off when connecting with the SELC662 cable. Any idea on this issue?
– The main reason that can cause switching off of an IED upon touching it is normally related to the power supply card. Can you check if there is not loose contact with the power supply?
– Rear connection is fine

– How to reset lockout alarm in auto recloser relay using FnKey?
– LEDs get reset through FnKey configuration but not lockout. I have to insert a password for resetting it.
– Check your binary inputs. Whether all tripping and lockout relays are reset
– It gets resettled after the password but I want to bypass the password and reset the lockout through the push button or FnKey
– Assign a binary input (either FNkey or PB) to relay. According to connect in PSL. Could you please check Lockout reset instead of Rst CB1 lockout and Rst CB2 lockout?
– You can try to clear through supervision or From view records, reset indication .this will clear everything

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– As we know grid substations always have future scopes. If a very narrow margin of safety factor is given due to documentary error, how can we negotiate with them? We need standard
– I don’t think any standards are available about margin factor to be considered

– What is biased current in differential prot?
– I bias =( I1+I2) /2 or load current. I1 for HV and I2 for LV As per Micom p643 For Transformer diff protection
– It is available also for line and bus bar protection

– How to export settings in pdf Easergy studio?
– Open every carpet and select all that You need ( ctrl +clic) and after go to printer And click print as PDF

I just want to send a goose signal which block I should use for any user-defined signal in pcm600 2.10. What do u mean by block?
– Simply add the signal with OR gate in the input of Goose block
– Which block is used for goose send?
– You can use all these depending on your input type
– Is your input is the double point?
– The goose block in the Tx relay should be the same in the Rx relay for the 670 series
-Single point single
– I have 615 series

– In 30 kV switchgear if I put the incoming circuit breaker open and in service position I read voltage (700 V) in the relay. Is it new or it has been existing? Just to know whether this has just come up all of a sudden?
– I’m thinking that you may check the ratio set in a relay or if VTs are located on the cable side check whether no back feed, otherwise check whether there is a CB pole that is not opening wholly.
– It is a new MV switchgear and after tests, we tried to put it in service but when we put the incoming CB in test position we read voltage in the protection despite the CB being open.
– VT is located before the Breaker towards the incoming Cable, then check Relay power Data & compare it with SLD CT/VT data.
– There is no VT in the cable the VT is in the bus bare

– In measured is the earth fault current measured by the earth fault current coil of the relay? In derived is the earth fault current derived in relay by summation of Irph+ Iyph+Ibph currents?
– Sensitive protection will be used if the desired protection settings are very low for earth fault eg 0.001 x In.especially where the system is NGR earthed
– Vn derived is open delta voltage derived by relay during summation of Vr+Vy+Vb voltage. this is done when the 4th coil is not available in the relay. the summation is the vector summation
– This is a Neutral Displacement Relay.
– Yes, CBCT is used as sensitive protection (while earth fault current is very low).
– This is the Rated Operating Sequence (Duty Cycle) of the circuit breaker. This denotes the sequence of opening and closing operations which the circuit breaker can perform under specified conditions. The operating sequence is as follows: O-t-CO-T-CO
– since CB is already charged it will take t= 0.3 s to close but next reclose order CB has to recharge its operating mechanism and it will take T= 3 min to recharge its spring or hydraulic system and then be able to reclose. And 0.3 s is required for Arc Quenching medium such as oil, SF6, etc to regain its properties after tripping of the CB.
– What is the consideration to choose the reclaim time for CB reclosure by 3 min?
– Maybe Mechanical charging movement to avoid failure in the system when fail to reclose at 1st order. While 3 minutes is enough to decide what you have to do.
– In the case of 220kv Substation, when both lines are charged, then why bus coupler is closed?
– Ring Bus System (Loop). Is more dependable?
– Voltage collision may happen when the bus coupler is closed. You have to use Synchron check relay to close the bus couple breaker during both of buses is energizing
– By the use of only a syn check relay, the problem will be solved.
-What is the problem?
– Sequence, interlock, protection, synchronizer.
– yes I agree. It concerns mechanical charging i.e spring charge and also its insulation media, But isn’t 3 min is too long?

– I am trying to trace a fault on the Transformer that trips on differential protection. I conducted an IR test, it shows okay. I need advice
– Check the CT. CT Polarity & CT ratio should be the same. Please check the CT connection.
– No, sometimes when a problem is at 1st order, you need to check all anatomy and the condition while that’s 3 min.

– As a thumb rule -Alternatively, the set differential relay shall have an offset of 20 per event of transformer full load current. This is just a thumb rule. U need to use ur judgment
– As the Last option, can u please carry out a stability check for through fault current condition?
– These are the three options available to verify differential relays. The most event is CT has saturated.
– Yes, one CT gets saturated due to through fault current in low impedance differential relays.
– Are u commissioning a new transformer (first charging), or is it a transformer that is already in service?
– It ready for service
– there is induction near the primary CT but, we are trying to isolate the area
– I have found the cause of tripping. It’s LV side VT
– What Vt is causing to trip?
– There is a breakdown of insulation between the HV side of the VT to ground

– What is the process of relay setting
– At first, you have to download the manual instruction. Then read it. And then you do copy the section of the setting & configure it in your own format of Work Instruction.
After that is done, you will get the answer.
– We carry out an Insulation resistance test on each terminal equipment and finally found that the IR of VT is >10 kilo-ohms. We try to restore the Transformer but it is still tripping on differential protection after 3seconds
– It’s 7.5 MVA 132/33kV Transformer, CTR: pri = 100/1A sec=100/1A
– VT has primary terminal A-N. try to remove N which is connected to the body of the VT, and try the IR test. Secondary terminal a-n. Remove n from the earth and perform the following IR test.

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After all, the connection is installed properly, comprehensive CT needs to check, and or inject the current test for the relay.
And also Transformer Ratio check.
-3 seconds is a lot of probability, I guess it was suspected since knee CT/saturated or relay accurate has been out of spec. Except for cable connection.
– 3 seconds means 3000 mili seconds. This is too much.

– We have a problem with our plant. the design is based on 30MW for each power gen steam turbine and 4MW from the grid all protection and study state. know we bring 30MW from grid and 15MW for each TG we face à lot of problem like blackout when grid disturbance. the restudy is requested? and I need your advice, please
– There is a problem with relay coordination. you need to get your relay settings reviewed.
– Is ur plant getting islanded for grid disturbances?
– Yes
– Speed control check also
– Load share I mean Or speed droop?
– If ur plant gets islanded and TG’s are detecting the islanding. then TG sets should survive. since u are importing 30MW from the grid. please check the balance load on TG after islanding also
– What is the voltage level When I Will be on-site I Will share it With u SLD?
– 60kv
– Island mode means autonom Without external source 60 kv
– What is the EDG rating (MW rating) and the other source details which u intend to run in parallel while carrying out EDG testing. what is the short circuit rating of a 6.6KV bus? how much time u intend to run in parallel. as we understand EDG is generally used for a black start may not continuously be in the circuit.
– Putting a reactor will increase the problem as it will be difficult for voltage control. That reason makes it interesting.
– Nothing related between Busbar rating with short circuit except failure in insulation, its mean busbar failure
– Maybe reactor installation initiated during EDG Chosphi gone to capacitive area. That problem in load share control/speed droop.

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– In Siprotec 4, the default password is 000000
– Hello friends anyone knows how to recover siemens relay 7sJ801 from monitor mode?
– Just turn off DC supply and turn on
– Just In Monitor Mode, you can see the reset option in the drop-down list, please reset the relay and it will recover to the original. If It happened after the FW update, You have to initialize the device

– plz tell me about PSB protection operated in brief.
– PSB function avoid a huge load of fault. as a matter of fact metering, DZ/DT.since a fault is high speed but a load is a low speed or DZ/DT
– Performance monitoring reporting system In the MICOM Transformer relay manual it is mentioned that 41% of winding (Say 20% setting of In if CT secondary is 1 Amp) will be covered under differential protection and balance 59% will be covered in REF protection for star winding connection transformer. My Query is how much winding will be covered in differential protection if transformer windings are delta connected Dd1.
– Is there any document available to understand how the current flows inside each branch of delta winding during the health conditions, during Phase to Phase fault, and during Phase to Earth faults.
– Please can you help out by briefly explaining, how the problem was resolved?
– if it is Dd Connection then REF can not be applied unless you use a zigzag transformer as a grounding transformer. if so then you will use the same percentage
– Hope License is the problem, please try with a Genuine License Number. but I did put a genuine key when asked during the DIGSI installation
– Hope, License might be utilized before and it might not be multiple user License. Please check with Siemens.

– I’m getting an error while installing DIGSI 4.91 in Windows 8.1 saying the operating system is not supported
– C&S make MRR1 rotor Earth fault relay is not giving any alarm when output is not connected but it’s giving alarm as soon as output wire is connected, What can be the cause
– is it a dry contact?
– Yes
– maybe the internal relay is powered by the control voltage itself. does it happen in other relays also?
– No
What type of relay is this? Try to avoid this type of msgs
– Output relay testing procedure is here in this manual

– Anyone experienced in MPD 600 for PD measurement
– Hi, how pilot advance transformer (PAT) works? How its connections will be? These transformers are used in rural agricultural feeders to ensure 3 phase power during non-peak hours and single-phase supply during peak hours. (single-phase supply for rural houses and three-phase for agricultural motors in farms).

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– Dear, someone Will have the IEC 60480 standard
– PSL in micom relay, areva ,Siemens, Abb, and SEL?!
– Micom
– And for other brands?
– 1. Areva, Schneider, Alstom, GE – are using Micom products-PSL-Programmable scheme logic
2.Siemens-CFC- Continuous function chart
3. Abb-ACT- Application configuration tool
-And SEL?
– Psv
– Please sir do you have a procedure on how to commission RPH3?

– could you share about the SOTF function in distance Relays?
– Switch on to Fault
– If ur going to energize one feeder in that feeder has a fault is existing and we gave a closing command to Breaker, then in that case SOTF protection will immediately trip the Breker.

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– Please explain the time synch process in Simense relay using SNTP.
– Anti-pump relay
– Anti pumping to protect the closing coil

– Some switches come from the factory but you can also design logic.
– Some power switches.
– please anyone, how to read the ICD file for abb relay?
– Go to parameter settings then click on the file from the menu bar after that select export parameters and select which type of file you want to export
– Siemens 7sj8011, how can we change it?
– Through DIGSI Software
– Use DIGSI. Only by software DIGDI

– What is pre-close and post-close in trip circuit supervision, can anyone explain?
– This is for the trip circuit supervisor relay concept. Pre-close before closing the breaker trip circuit in healthy condition. Post close means after closing the breaker trip circuit healthy condition. This trip circuit supervisor relay check the trip circuit coil must be healthy in pre-close & post-close conditions. If the trip circuit fails protection relay give any trip commend it will not operate. That is why the protection scheme has two number trip circuit schemes. This is called pre-close & post-close.

– Please I looking for ABB RED 615 file setting for comparison.
– How to set Directional overcurrent protection?
– Very nice, also when mechanical protection operates. it will send the trip command directly to lockout without going through the main relay.
– Breaker is not working automatically. we need to press it manually for the operation of the pump.

– Breaker or contactor?
– Contactor
– we need the schematic diagram for the rectification
– Quickly check the float switch by force, if the supply is not reaching up to the contactor coil, then there may be a problem in the loop or float switch itself.

– Download the S1 studio password hash generator
– And set a password
– Please explain the function of resistor connected series in tripping coil
– It’s the trip circuit supervision circuit. It limits the current through the trip coil below the pickup value.
– A diagram is not clear!
– Can we use single pole ac MCB in DC Circuit in negative polarity where positive polarity is grounded, dc system voltage is -48V. If the answer is yes then why?
– Brother MCB has nothing to do with voltage. In your specific circuit, whatever the voltage is, doesn’t affect MCB.
Any kind of circuit breaker works on Current and it will work fine unless your circuit is designed ok. Even then it wouldn’t be a circuit breaker that would be an issue but the design of the circuit.
– But I am asking about dc and ac MCB difference. Whether the can be used interchangeably
-Yes they can, I have used them But it depends on the insensitivity of your circuit as well.
if an MCB is designed for AC, it will trip sooner if used on DC, in case of fault. In normal conditions, it works fine
– What I think is all breakers are rated to work with all types of voltages in ac and dc.
– Only the short circuit capacity will change according to the voltage
– Some are dedicated to DC, their coil doesn’t get heated as fast as AC.
– Yes those are special breakers

To know more details about this package, click on the picture

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– Where,s the protection system in these cases?
– Hi. Is there anybody who has tested abb SwitchSync relay L183 Or any other SwitchSync relay from other manufactures like SIEMENS?
– Synchro-check relay SPAU 140 C
– but SPAU 140 C is a synchro check relay, not a sync switch relay
– Switchsync PWC600 is ABB
RPH3 ALSTOM. Controlled Switching with the Siemens Phase Synchronizing Device (PSD) the MCS025 Sync-Check Module Schneider

– Would you please give me test procedures or settings that have worked for testing these relays
– Anyone has a good document to understand ABTS and TOP.

– Engine with a power of 250 kW 1500 rpm and a 1500 kW 1500 rpm engine
– Anyone working or heard abt a company called Valmet?
– Hi, There is an opening in Schneider Electric, Chennai, India for a Commissioning Engineer with 5 to 7 Years’ experience.
Candidate must know on
1) Commissioning of Numerical protection relays ( Distance, Differential, Busbar, Overcurrent & E/f )
2) Hands-on experience in configuration and testing different make protection relays with Omicron 356 / Double testing kits.
3) Provided setting calculations for the above-said protections including CT & VT sizing.
Candidates may need to travel Global sites if required for commissioning & Training customers.

– Could you share any data about the DCS systems in substations?
– What kind of DCS do you want?
– Siemens,Arefa ,Abb, Vatec, Wincc or sicampas
-User: zivercom, Password: 0000, another password: Ziv

– What is the equivalent model of RED670 in SIEMENS?
– 7SA52
– For Siemens relays 7SD…. means Line Differential Protection. 7SA Distance Protection as the main protection function. Depending on the device type distance or line diff is available as the main 2 functions.
7SL … Line and Distance Protection. (SIPROTEC 5)

– In Micom relays can I upload the revised PSL while the relay is in service?
– Will there be any maloperation?
– PSL uploading may result in Pick up of BI/BO and then output contact.
– Check the connection Or disconnect the DC from the relay for a while and try again

– Has anyone done distance and differential relay calculation in excel?
– Anybody has a calculation sheet in excel for voltage drop and current carrying capacity of cables
Is it password protected?

– Anybody knows how to protect the three-phase ground earth fault?
For MV network. For single-phase, there are many ways but for a three-phase, we have a problem.

– I want to config distance relay model VAMP 259 but there is no option to enable fault locator. I can see the related option under the distance menu but nothing is submitted (in KM or Ohm), is there any way to enable fault locator?
– Three-phase to the ground will not detect as earth fault because no zero sequence or no current will flow in the neutral. It is just an over-current.

– A 132 kV SF6 circuit breaker rated for 220 volts aux. Voltage is to be used in a substation where 110 volts DC voltage is available. Please advise which changes are necessary to be made to the Circuit breaker.
– If you want to modify the equipment in the circuit breaker for 110v you need to change more equipment. Better try to connect the two 110v supplies in series
– When the available voltage is 110VDC, Change the following parts
1-closing coil one unit
2-tripping coil two units
3-all the dc contact relay.
Otherwise wise Manage 220VDC Indication Lamp

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– I am trying to export Micom 442 set file into xrio format by using Schnider s1 studio, but IML cannot find xrio option in the export menu.

– You can go to setting file on the right side of software, and press right-click by mouse, and go to export setting, Rio
– I did it this way, but xrio option was not available. I think the software version does not have this option. But I am not sure.
– Anyone has a good document to understand ABTS and TOP.
– Anyone has a Method of statement For Transformer stability and Generator stability?

– Can you give me transformer testing IEC standards? If the SF6 in HV CBs becomes very low. What is the standard action in this case? does the CB trip or does it must be locked out? If it is locked out does any breaker failure must be initiated?
– Stage 1 alarm, stage 2 block. Block gas pressure <•5 Mpa. Block is no more operation, open or close.
If fault then if it is line Tele protection will activate if trafo feeder or normal feeder BF will operate.
– In 500 KV if stage 2 appears the breaker immediately trips! Is it correct or need discussion?
– In our scheme at 500 kV level, if stage 2 appears the breaker immediately trips, in my opinion, CB lockout must take place rather than the trip! Am I right?
– I have only experience up to 400 kv Siemens CB, second stage not trip from CB scheme. But PSB functions can make trips. I do not know PSD (Phase Synchronizing Device)

– We are getting Generator Rotor Earth Fault in Relay. How can we ensure that it is a false alarm
– this is dangerous to trip the CB in case of stage 2 appears. it may not be able to quench the arc properly as sf6. pressure is low. so it’s advised to block tripping in case stage 2 operates.
– If sf6 gas content is reduced breaker trip
– Level 1 OTTER TAIL
– Stage 2 trip must be a lockout, which means Breaker will trip and shouldn’t Close until SF6 Gas is refilled to the specified pressure.

– Lockout means one needs to reset the Lockout relay before closing Breaker.
But don’t reset until the gas is refilled to the required pressure. Nominal pressure for 132kV is 5.6 bars absolute.

– Does Micom P741 and P742 need separate software for the PSL edition?
– No, s1 studio can do it.
– but if I want to edit a single-line map of the substation?
– In this case, you must use topology editor for Mmicom
– Do you have any applications for that?
– IEC 60076
– If you want to go with diagnostic testing for transformer please refer to C37.152
22/abb, 23:02 – abb: Can any tell me about IEC standards for GIS, MV switchgear, transformer, protection schemes, and IED testing and commissioning

– NIC NO RESPONSE in Micom p142 and p143
What to do to solve this problem and what is the cause for it? Problem with the hardware.
-restart the IED, the alarm will disappear and after some days alarm will come again.
Permanent solution: Need to change the network interface card and update the respective nic file to that board.
– Plz share Rio/PTL file for P44T relay Alstom make,

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– anybody has a serial number for the Micom topology editor or can edit SDL for Micom p741?
– In Micom S1 studio, while uploading PSL files to relay, we get three options, the First is Enhanced logic only, the second Logic only, third Full form. My question is what is the difference between these three options?
– The difference is in the settings updated with the PSL update.

– In the below attachment, the Generator Stator earth fault is detected by connecting Neutral side NGT secondary voltage in series with Phase side open delta voltage which is derived through external IVT. The query is how this works and what will be the output voltage of this combination which is measured by the MICOMP345 relay.
– Someone had omicron test templates cmc356, for overcurrents, differential, etc, and also some good bibliography for generator protection.

– Does anybody have a protection relay testing handbook
– As you notice this book is volume 4 in the series. I would appreciate it if you send volumes 1-3

Here is one of the other video training courses, ABB PCM 600. You can see detail by clicking on the picture.

– I have a problem with the earth’s fault. We have used Siemens o/c relay which is functioning very well for o/c,e/f, and s/c. For the earth fault whenever it’s happened either one or two phases it’s working, but whenever it’s 3phase. the relay is not working.
– Always trips with 3phase faults?
– For another fault it’s ok but the 3 phase Earth fault is not detected by primary current injections each phase individually functioning.
– What are the magnitudes and angles of the 3 phase currents you injected for the test?
– What SIEMENS OC relay model?
-7SJ601, Version 3
– The earth fault setting for stage one I> 15A. If faults are even 20A no functioning. 3 phase fault is not an earth fault. even if 3 phases to earth will not detect by earth fault protection.
– If you inject three equal magnitudes with 0,120,-120. the earth’s fault will not function even if it is more than the earth’s fault setting. While you are injecting current, check relay measurements and make sure that the neutral current exceeds the setting value (15A). If the current exceeds the setting then you have to check whether the directional function is enabled or not. Also sometimes you need to check the earth fault calculation method if it’s measured or calculated. Finally check the current connection to the relay. Make sure that the current circuit loop is closed
– balance values will not initiate the earth fault function.
– I agree that the balance magnitude will not result in earth fault. Check the neutral current flow
– The 3phase fault is considered a balance three-phase fault so no earth fault will detect, you need active o/c protection. Even if E/F operates with a three-phase fault it will be due to unbalance not a real earth fault.
– Just reduce the setting for testing purposes and inject the current in all three phases monitor the neutral current flow now increase the current value in only one phase until the neutral current value reaches your setting value it will trip according to the curve. Check the setting whether it is nondirectional.
– Hope you are testing the directional earth fault. Check the voltage magnitude which you are injecting into the relay.. it shouldn’t be zero. Most relays require a minimum of 3Volt for sensing the right direction suggest giving 10V in the Y and B phase and 5V in the R phase and injecting the fault current above the setting.
– if the three currents are not shifted between them by 120 degrees, even if they have the same amplitude, it will trip because the vector sum of the three phases becomes different from zero. (Io # 0A)

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– I am facing a problem with Siemens 7SJ8041 When Relay Trips on Under Voltage and Voltage comes back to normal and I try to reset the Relay Binary outputs and Leds then the relay does not reset. I have to go into the Test and diagnostic menu and have to reset the whole relay from there. any solution?
– check the drop-out ratio of the relay. normal drop out is 1.2 for under-voltage.

– Secondly in 7s8041 Relay does not trip on Reverse Power
– check additional functions available or not?
-Yes available and setting at 166.5W. It is available in u/v settings. But you need a Laptop and active additional settings

– If anyone this relay manual English electric, CDG31FF8051JL(M), electromagnetic relay kindly reply me
– If a transformer is protected with both REF (64REF) and Differential (87) as we know REF is more sensitive than 87 and operate for the unprotected winding near the neutral side. My question: is any 87 trip means also a REF trip at the same time?
– No, REF only responds for earth faults inside the zone. if the fault is not related to the earth then the only differential will operate in the case of earth faults, both can trip the transformer( the faster will trip first), and if the transformer has high impedance grounding, the earth fault near the star point ( less than 40% of winding) may not initiate 87 ( when you apply slope and operation and restraint) in this case, only REF will operate. Right?
– Yes, this is right. And this is why we use REF together with Diff protection.

– What is the difference between high impedance and low impedance when dealing with Differential and REF protections?
– The high impedance method uses an impedance in series with the operating coil of the relay. The impedance value is chosen to damp the current of the relay under setting current in the case of the worst fault (a fault near cts with one ct saturated). The low impedance method uses a restraint coil to dampen the current of the operating coil in the case of the worst fault. The relay will trip when the operating coil current is maximum than the restraint coil current.
– In which condition the operation of 52PD, pole discordance protection will be blocked?
– the pole discrepancy is an arrangement of controls, typical of the power switch.
– It is already blocked by time. if PD happens it must operate after 2.5 seconds.

– In which cases and configuration I must install and program “inter trip signal protection “in case of transformer protection?

– PD trip function is normally blocked by any pre-scheduled single-pole operation of CB like single pole auto reclosing or manual opening of a single pole of CB.
– in the monopolar switch the discrepancy time must exceed the reclosing time.

– I have a 7sj62 Siemens relay and it’s going to monitor mode then I tried to initialize the Dex file not succeed and activated device reset from the HMI after that it’s gone again monitor mode and relay restarting automatically when power on
– Hopefully by upgrading Firmware Version, it may work fine, kindly contact Siemens and ask for an updated firmware version. you must initialize the device with the digsi.
– Please share experiences and knowledge about “power swing blocking” in distance protection
– Hi guys, I need help setting up an auto recloser on the Sepam series 20 relays. In double bus bar protection, what is the difference between single CT and Double CT methods for bus coupler

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– What is the use of Line CVT in relays?
– Synchro Check

– How do you test relay GE SR3, Thermal Overload function with alarm and trip?
– in DIGSI4 4.92, when I wanted to archive a file, this window was displayed and required a password And got this log file
– There are some requirements for installing DIGSI like c++, have you installed them?
– I need 12 units of the above to relay Fro where to get it?

– How distance protection is functioning in HVDC transmission?
– Transposing is required in long-distance HV cables Or cross bonding is enough?
– Both will be required
– Conventional distance protection is not applicable in the HVDC system as the reactive part of the impedance is absent due to zero frequency
– Cross bonding is required to reduce the induced voltage, and transposing is required to make C mutual equal between three phases. This job shall be done each 400 meters and cross bonding shall be connected with the earth by the special box or with SVL + earth
– SVL mean shield voltage limiter

– When I tried to extract XML files from DIGSI, this error came. Kindly advise
– It depends on how u extracted
– There are 2 ways to extract
– Which one was yours?
– Both ways same error

How to tackle DC-link over Voltage faults In VFD. Application HVAC chilled pumps. G120

  1. increase the DC overvoltage fault limit to 130%. default is 125%. but this solution may lead to stress VFD which may lead to some future issues.
  2. Update ur firmware to the latest. It will work right away
    – old versions are not prone to motor oscillations which in case u free run a motor may oscillate. in which frequency band u r facing overvoltage?
    – Really I just retrieved data from the customer. But from where I can find it
    – siemens website.
    – No, frequency band
    – run the motor. increase speed slowly. you’ll start hearing sizzling sound in a particular band

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– I cannot modify the protection setting on ABB REF 542 plus manually or online through cable. I always got “setting not saved properly”. Can anyone help?

– Hi. I used the key to change the protection mode to SET. Is this enough? Should it be used also to change a setting?
– Please anyone can help me with the password viewer for ABB Red 615. We are facing one error while installing ABB PCM 60. Can anyone help?
– Try to Separately download and install SQL server and then install PCM
– anyone knows about this error while exporting in. XML extension?
– This is the 1600A breaker feeding the Chillar. Could anyone please tell me what would be the setting of this Breaker for Long, Short, Inst. & Ground? DLL file is missing. Copy the DLL file from another working laptop(C drive) or reinstall the software. For long char. Settings are 1.0 and time is 3.0. Switch not clear but for L =1 and T=144s ;S=1.8;I=8;G=.4
– Can anybody tell whats the max current in which we can use MCCB only for load break?
– Cable size 300sq mm
– That’s due to thermal effects. The thermal tripping point would go down after each tripping and if tripping takes place at 370 A after 2 hours, the MCCB might trip at 350 or even below (may) after every one and a half hours or even earlier
– Then what solutions shall we change this MCCB if yes what would be the rating. any other solution instead of MCCB because it’s placed in between transformer secondary side and LT panel.
– Check the tightness of each bolt Properly torque it.
– Phase sequence is ok my site is running fine load is 240 kw. 240 kW? rate amp is 408 amp. This is a connected load but running is 225 kW
– Can you test the MCCB By primary injection?
-383 amp
– There is an overload, short circuit, instantaneous, and ground fault by doing the method of primary injection?
– Yes I am doing by primary injection only
– Can u tell me which combinations for overload test in primary injection? Single-phase or phase to phase?
– You can use Phase to phase and phase to neutral for overload, instantaneous and short circuit. And phase to neutral for ground fault.

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I can’t open the IEC61850 station in DIGSI 4.88
– Maybe the target digsi file version differs.
– What should I do?
– Install Digsi4.91 & try.
– Anyone who has Digsi 4.88 update?
– It use Siemens-Configurator-Version”>
– Create Siemens User ID & u can download it on the Siemens webpage

– what is the maximum length for a line that can use Teleproection in distance relay?
– Which relay? All relays have different limits
– Siemens
– 400km, 300km, 200km,100km, I talking about the distance I can use Teleproection in distance relay?

– Hi everybody, does ABB REL 511 have an under frequency and over frequency protection?
– No
– Is there any way to activate this feature in this relay?

– What is the default password for Easergy Studio 7.1.0?
– In Easergy studio 8.0.0 the procedure to connect to relay is different, has anyone been able to use that?
– Thanks but it does not accept
– Use the Micom studio hashtag for crack.

– How to calculate maximum through fault current to set the relay stable in bus bar protections? Say voltage is 400kV.
– It was based upon your load
– If exact load details are not available?
– I don’t have a clear idea but have a suggestion u can decide regarding your CT primary, But the normal load current may be less than the CT rating
– How to create CID & ICD files to ZIV 87T(CGL make) relay for integration with SAS?
– You can get a rough idea of the maximum CTR of all the CTs connected to the bus.

– Please I need to communicate with argus 1 relay over current reyrolle by rs 485
– You can not extract. The only vendor that can give you
– You can edit in ziver cid
– Sir I don’t have CID, then how can I edit?
– Arrange to take from the vendor. If you don’t have CID then get it from ziver CID soft. You can Extract the CID via ZiverCid software. It will create the file, And btw you should not be touching ZIV relay if you do not have a basic idea of Ziv software Because there are chances you will make the firmware corrupt For which you have to make it a hard reset, which is also not an easy process, short but risky. So please contact your senior on-site & inform him about the situation. Otherwise once the relay is gone into the dead mode, it won’t be even hard to reset by calendar method
– I have ZiverCID software then how can I extract there is an option?
– I think to go to ziver complus and then setting and then edit. This file will automatically open in ziver CID. If he has CID module installed

– Hi, Is anybody familiar with the F650 GErelay?
– What do you want to know?
– About Plc logic configuration
– Can we write the logic for transformers changeover
-How do you want to make it work as a changeover?
– You must have that. Download use Filezilla to extract CID. For extract, you don’t need any credentials With the definition of CB status and timer. For download username: Ziv And password: *ziv#

– I have a problem with my fault recorder, 7ke85 siemens. The Disgi5 software show fault in port E, the front panel is active run (green), and error (red) Led. I can’t communicate
– This fault locator is not functional As long as the error led is glowing.
– what is the solution?
– This problem has no solution
-Yes in CFC, the ladder is having a signal which is not masked
– Remove that
– I can not inspect the relay, I can not communicate
– Relay is in error mode means the software is having inconsistency between source & destination
– If you have a backup check CFC and send it to the relay. And if you are new to siemens relay, better do as I say, right away
– When I want to communicate with the relay for local or remote but in two situation does not allow any communication the relay
– That’s because of an ERROR in the relay’s file. This relay requires Re-Flashing of firmware

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– hi, I was wondering if anyone could please tell me how to check the measurement of 2nd harmonic content in the 7UT85 Siprotec 5 device?
– In RET 670 transformer differential relay. I want to check the diff and bias current I found Please solve my problem related to NR relay.
-When AR has been operated in 400kv line then one end AR successful while other end line became trip while both ends have AR-enabled. then why?
– On other end, it is operating in Pole discrepancy or AR lockout?
-No. Direct trip
-Check all conditions for AR in other ends
– On other end, it is operated in Zone 1 or Zone 2?
– Zone -1
– CB’s health status is ok?
– It means?
– No PD and AR lockout operated trip command goes to the breaker
– I suppose u assigned any DT to send a signal to the remote end? While AR From the local end
– Check the time setting at both ends Of the AR
– 86 Operated?
– At one end it may be 1sec n other end 350ms
– So by the time at one end AR operated it sent DT signal to other end
– Then you check the logic for 86. 86 should not operate for zone 1 single-phase fault
– Due to which 86 operated. DT received in the remote end?
– Carrier received at other end And carrier send by our end?
– No DT received and send by both end
– Carrier aided tripping sent from your end
– No this is not correct.86 operated for single-phase fault
-Ok. On the remote end, 86 is operated or not?
– Yes. Then check the logic for 86 in the remote end. I think in the remote end 86 is assigned for all faults. Check the time setting at both ends for AR. Both end Fault in Zone 1 then ZCOM Trip will not happen. That is not necessary.

– Anybody has 500MVA 400kV/220kV/33kV T&R Make Autotransformer 8 Channels FO-based Tempr Hotspot details Based on FBG?

– Please help, what type of fault it’s showing? This relay connected with 3 phase motor
– STS light blinking. The motor run for a while and the stopped Resistors are rated in ohms and wattage. How to identify the short time withstanding wattage of resistor which is available in hand? Generally, how much will be the short time withstanding capacity of the resistor for rated capacity? Working in System Protection as Manager Power System Engineering.
– We are providing all the testing and commissioning services in Electrical switch gears.
– How did this one become a big day?
– We have to think before using electricity. Go green. Think before use
– What are FPFM and FPSM in Line protection relay?
– FPFM. This is meaning feeder protection is the first main. FPSM This is meaning: Feeder protection second main
– Set-1 and Set-2 right ?
– Yes

– we need support for setting calculations for the transformer feeder which fed on 13.8 kv.
– here in Saudi Arabia we used feeder protection (Line) 2 relays, both make the same function, have the same setting

– As per your requirement, he is having more contacts regarding purchase.
– I want to synchronize my server with a Meinberg GPS in SICAM PAS .anybody can help me?
– Which model of GPS are you using for time sync?
– M300
– Yes I can not start NTP on my server
– Why don’t u try SNTP?
– What’s the networking protocol you are working on?
– As far as I remember M300 is compatible with NTP & SNTP both
– Firmware MUST be updated
– Oh, my network protocol is Ethernet

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– Siemens Siprotec 7SS52 Busbar Bay Unit in error & alarm mode, after removing & Connecting Aux., DC supply, it will come in Run mode & after 30min again the BBU goes to error mode. What is the solution to this problem?

– Initialize main unit and bay unit from software or menu.
– Reset MCU still having the same problem

-Hello need some help with this error Relay P643 Alstom make. Communication error
– First, check the Test Connection and then proceed. In the test, the connection selects the correct port to which your serial cable is connected.
– Port is verified but still, the error shows while communicating.
– We had used 2-3 converters but the same error was observed. Then change the port and try once
– Which converter you are using?
– BAFO And another is a local make
– Try with a different port once
– This error comes only when you are sending right?
– Yes
– Select only settings and not psl then send.
– Tried but not working.
– Sir, the port changed but the same error occurred.
– Try to use a different converter other than you have
– We have 2 converters same error for both the converter
– If it has ethernet on the backside of the relay you can use that also
– Which software you are using?
– Agile v1.3.1
– New relay or an old one?
– New relay
– Try with Easergy
– Changed port advance settings. Solved now


– anyone informs that Schneider which software is available for checking the Goose (IEC-61850) Signal?
– The password of protection relay type p143 has been modified? is there any way to restore the default password.
– why when the change between some tabs in kvgc relay is blocked?
– NIC Card faulty
– Replace with a new one
– Reason for this problem is IEC61850 Support configuration file is not available in the relay at the moment.
-I want to start NTP on my server but the system shows an error. anybody can help me?

– Can anyone define “breaker abnormal alarm” in the signal list?
– Cb abnormal can be given by spring not charges, or Sf6 pressure or TC not healthy
– Make or gate & give final op as CB abnormal
-+Local selector
– Polo discrement
– When programming Nondirectional overcurrent test in Omicron getting Out of range error. How do I correct it?
– CT Secondary 5 Amps
– I guess you write the wrong number to CT primary/secondary ratio at device settings. Check again pls.
– Use CMC 356. I think 256+ will not deliver this much.
– Check the max amps settings in test object details.
– use the 3x25A setting. Parallel three current injectors with other 3. This would provide 25A per phase. your requirement is 12.88A that’s why it’s showing out of range.
– Please check the connection setting and select the proper port number and baud rate by looking into the device manager
-Everything is correct only Check test correction once or use another serial cable. Check earthing of the relay as well as your laptop charger.
– Check the communication port configuration from the communication menu usually this error appears due to wrong port selection and configuration
– Yes, you uploaded the wrong menu text file to the IED. To make it normal you need to send the right default menu text file via parallel port again or updating the same firmware will make the IED to go default settings and menu text. If you are planning for a firmware update make sure that IED is not in service.

– I’m getting this error while installing digsi4.93
– I had V4.92 loaded and it deleted it. I tried again without V4.92 loaded but got this same error.
– Do we require to test, “inter trip” during end-to-end testing of line differential function Or only for distance?
– Yes you have to check

Our DIGSI 5 Course is available. Click on the picture to know more info

– Hi all I want to implement Autorecloser in PSL and assign an output contact to it (for Micom Agile p443). Which output logic DDB signals, Should I use?

– Hi everyone can anyone help me with this issue? I am configuring IEC. Here is my settings relay subnet: laptop IP: now if I put relay IPs from to, I get the response from it. but to aren’t working. what could be the solution? there is no subnetting, why is it restricting me to 92 devices?
– Relay subnet and switch subnet must be the same. What’s the subnet in the switch?
– does a switch has masking? I don’t think so.
– Every switch has IP & Mask If you know the IP address of the switch
– Type in ur browser, and there u can also check the subnet mask
– Which switch u r using?
– that is something diff, that is just to access the switch conf
– the ports aren’t assigned to any VLANs
– so no need for that
– It is linked with relays communication, the relay fiber would be connected to switch if both are not synced, communication with IEC won’t work
– You can check that as a part of troubleshooting
– it’s working with IPs 1-92. That’s what I’m saying, maybe another switch has a different subnet due to which relay won’t be accessible with laptop IP
– Install device model.

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– I have faced some issues in Micom p642 agile regarding fault recording trigger. Relay doesn’t trigger at the time of differantial trips so please help me with it I have tried all the options for the fault trigger all other faults are triggered but when only differantial protection trip at that time fault is not triggered or on the graph was generated.

– Micom relays and SEL RTAC connected in the same network.. is it possible via RTAC, DR files from Micom relays can be downloaded
– future scope of power system protection. future scope of relay coordination. What innovation is required in relay coordination?

– anybody having a protection relay panel O&M manual of any Kv level. Pls, share if U have.
– Please don’t touch any electric pole especially when it’s raining.
– Any anyone knows how to test Thermal protection in ABB REM 543

– How to change CT Ratio in a secure Energy Meter? Could you share the P441 manual for the Areva brand?
– I need software for Micom p 741. Remote HMI. Please

– When DC Source 1 is failed our Breakers got tripped. What could be the reason for the same?
– Check CTD
– Please share the control diagram of the breaker with us. Selective tripping?
– Undervoltage shunt
– Kindly how I test REF in 7UT612 siemens with 1 phase current inject?
– This wire is for voltage equalizing. so CT body will be the same voltage as a bus bar. if not connected will cause floating voltage for the CT body and result in partial discharging.
– I think it’s a capacitive leakage wire to connect to the capacitive indicator. You can eliminate capacitive insulators if your CTs have this capability(capacitive leakage).

– anybody has a VFD Test format or procedure?
– anybody configures RSTP at Micom p546?
– Guys anybody have a Test format for Diesel Generator?
– Can anyone tell what could be the reason for the battery blast in dg during Cranking?
– Short circuit on crank cable or in the crank. The second reason crank can be stuck or engine

– How to calculate stall rotor time in SIMOCODE?
– Use VRLA type to avoid the blast
– This battery is 12V;180AH Tata make almost 2.5 years old used to crank 415KVA Dg
– Is there any pole calibration happening in ACB for any make to close all-pole at the same time? And if happen then how it’s done?
– Why do we use a coreopsis conductor inside a tubular conductor?
– If anyone facing this issue in Siprotec 5 BCU(6md86), after restarting the device then manually operate the master trip relay (86.1&86.2), that same time given reset command from SCADA but it’s not getting reset.
while communicating ABB relays, how do I know which versions of PCM I need to use? ( 2.6 or 2.9)

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– What might happen to this insulator failure?
– Sepam 80 fails to operate shows maintenance key 1. any ideas?
– Converter issue
– Which converter? Relay is communicating on Ethernet/LAN
– In VT secondary injection. How to calculate phase to phase voltage in unbalanced conditions? Eg. we inject 20V in the R phase & 40V in the Y phase. What should be the phase-phase voltage? In actual condition, the multimeter reads 53V. how to prove it theoretically.
– vector sum
– Ip1(cosPhy+i sinPhy) + Ip2(cosPhy+ i sinPhy)
– Values are not matching.

– how to calculate the operating region of directional overcurrent and earth fault relay?
– u cant add a real and imaginary part. I= 2root ( real sq + imag sq).this is how u add a real and imaginary part
– Can anyone please help me provide an XRIO converter for RED670 V2.1.0? I’ll be grateful
– Can anyone tell me the meaning of the number mentioned in the box?
– Order information I believe

– I need RDS-pp codes for equipment used in the wind Power plant. RDS-pp is a Reference Designation system for power plants.
– Digital kits like omicron, meggar can inject voltages and currents of desired magnitudes.
– As a Protection Engineer you have to roam all around India for different projects.
– I am getting a network error while downloading from the server

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– Anyone can explain CT sparking
– Looseness or open Circuit
– Isolate the system to avoid any mishap
– Loose connection on side phases!

– What is the main difference between low impedance and high impedance bus bar protection schemes?
– High impedance in the Low impedance relay is nothing but based differential relay in this we have the slopes to avoid relay operation from the through fault current and CT saturation condition also.

– Hey I need help can I find here someone who works with Elster A1800 consumption counting
– Anyone has auto manual change over test Format.
– CT connection is ok?
– check the serial cable. also, try (test connection) from the device list.
-Tried with other serial cable Problem solved.

– what is the criteria for Grounding control and power cables, should it be grounded from both ends or one end”
And the reason for grounding is both sides or a single side?
-1 core power cable shield must be grounded only from one side, otherwise transformation current with inducted to the shield. I&C& signal cables as well. In this case, the induction is from the outside. However, for 3core, 3phase cable it could be grounded in both sides
– what about multicore control cable?
– In Siemens design which is used for many power plants, it is mentioned that only one Side must be grounded to prevent circulating current.

– Hi world someone can help me with F650 HMI with GE config. I need to make hmi with Modbus protocol
– Check relay HMI
-Should not b in the Submenu?
– Make it to the main menu page
-Plz check the Technical key of the IED in the software, is that compatible?
– Check the report details in the common read/write tool to get more information.
Note: It’s not recommended to do a common read with a lower version of PCM600 if the IED is configured with a higher version of PCM600.

– display error name is flashed v1.0,
– For parallel operation, you need to synch both transformers first, then close the breaker. Changing load from one transformer to another, Different tap positions mean different voltage levels (if both transformers are fed from the same source & in case of under-voltage, the load will draw more current, which might result in OC Fault, overheating of cables. The breaker may trip in the second case but in the first case, straight damage if you haven’t installed AVR. Breaker doesn’t care for Voltage, it only trips on high currents, But one transformer connected to load which has a voltage of 10.4KV
– it mainly depends on uk% and loads current. having enough data, you can simulate the Network using DigSILENT. In my experience, you can parallel both transformers without worrying.
– Check impedance voltage percentage Within limit, u can
– Check impedance voltage percentage at nameplate data
-When u have two transformers in parallel then you may have to look at the circulating currents that might flow when tap positions are not matching. Account for that circulation current as it will be an issue
– Sir the same I read in a document due to low impedance in the transformer which has less tap position certain amount of current will circulate within the winding but why?
– difference in impedance of the transformer more than 10% will have a circulating current too. even if taps are the same and the voltages are the same
– 66kv breaker CG make
-There is no need for SC capacity coordination, your new breaker may be oversize but that’s not a problem
– 40kA/3sec means it can withstand up to 40kA which is higher than 31.5kA. if 31.5kA for your substation is ok, then 40kA is ok, too.
– Not a problem higher capacity only.

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– Can anyone have an idea, what is meant by the cross trigger input TFR (fault recorder)?
– Cross triggering is used between TFRs to initiate recording all the TFRs and provides system-wide dynamic recording e.g. Power swing

– Please provide earthing in HT cable termination at both ends, must in HT earthing is very important
– In transformer slope testing what is I bias calculation that needs to be set in the omicron test?
– What is the IBias calculation equation to feed in the omicron differential characteristics for generator protection
– When we send the configuration to the relay we will face a syntax error at the last step, what is the matter?
– Depends on what relay u are testing.
– In the shot test, you choose the points on the characteristic curve and the software tests only at those points. In the search test, u select the sweep for IBias e.g. 0.2 to 5 with some intervals. This will create vertical lines on the characteristic curve and the test set will then determine the Idiff value on each of those lines. The test set will determine the Idiff value at which the relay operates. Search is like making the test set determine whats the characteristic curve and if the searched point is within the tolerance limit then only the test is considered passed


– I have a p443 distance relay(Micom Schnieder make), I tested this relay in zone 1, but it also trips in zone 2 and zone 3 simultaneously..and although I marshaled output contacts to trip.. it does not send tripping order to test set. anybody solves this issue
– Which test set are u using? Have u checked the current or voltage connections? Normally this happens when u are injecting current or voltage in reverse, which means the relay is looking in reverse. Check whether the reverse zone is enabled or not.
– omicron 356
– U using a distance module? Check your trip contact type, And double-check the PSL file.
– I test this relay manually through the test set, not through the laptop. I am using the time module.
-Ok. First, confirm ur output relays are properly working and connections are ok or not. Force them from the Commissioning menu and check continuity using a multimeter. Check ur wiring. U using a dry connection or wet contact.?
– Maybe the relay SOTF function is on
– Good point. Ensure there is a pre-fault. time set on the test set. Normally it is 1 sec.
– There are 2 issues. One is ur relay tripping on all zones. And second ur binary output feedback not reaching the test set. Solve them one by one.
– Usually, zone 1 is inside zone 2 and zone 3 (if all your zones are forward direction).

– We have one 13.8KV (15KV sys voltage) Switchgear. Due to an increase in the connected load, we want to change the CT in one of its Cubicles. The new CT suggested by the Supplier has the following Specs: *CT 300/5, Burden 15VA, 5P10, BIL 10KV. now my question is the 5P10 & the burden suggested by them is correct for this MV Switchgear? I’ve seen some CT having 5P20. Where we will select 5P10 & 5P20? Also, do we need to replace the metering core, as well as a load, that is increased?
– all CT replacements should have a CT CALCULATION ( sizing) according to circuit parameters. You should ask for this document first
– To say if it matches or not you need to know the maximum short circuit current, and also you need to know your relay and cables burden because 5P10 means this CT will be stable and will not saturate in the range up to 10 times the nominal current and with 15 VA burden. If you calculate your actual burden then 5P10 might be equivalent to 5P20.

– if we have 1K ohm shunt resistors of 180W for high impedance cable diff port. But need to change the resistors to 500 ohms as per settings, so how we can calculate watts for 500 ohms resist I think the definition of the armature is not exact and correct
– I was just skimming over the pdf and noticed that. The armature is where voltage is induced in it

– Do we have any stationary armature in the power plant machine? I haven’t seen
– Alternator I guess?
– In synchronous generators Armature is stationary and the dc voltage is applied to the winding on the rotor to have a rotating magnetic field
– It is easier to have a stationary three-phase output than having a rotating one
– Probably it is a technical dictionary For practical uses But from an academic point of view, things are different And brushless synchronous generators have a rotating armature. The rotating armature is mounted on the rotor to excite the generator’s field circuit
– I don’t say that we don’t have a rotating armature. I’m saying that the armature and the rotor are 2 different subjects
– I think there are only two terms of stator and rotor. depending on various conditions and requirements we use either stator as armature or field or vice versa.
– Maybe in a special type of machine the armature is mounted on the stator And a field circuit is on the rotor.
– And for the other type The reverse may be true
– yes. if there is a time-varying magnetic field and a stationary coil. the voltage will be induced in the stationary coil irrespective of stator or rotor or field or armature terminologies may differ as per circumstances.
– I think it’s not a network fault like a short circuit. It’s about the relay hardware itself As the title suggests Hw error
– But that’s what I think I’m not sure

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– How error relay has a hardware problem?
– I can’t open the diagram. It’s a network topology for DMMs and Relays single ring with redundancy characteristics for the 61850 networks, but the question is the connection between HSR &RSTP is correct or not? And can I use PT-G503 or other switches required?
– I think u can’t use different protocols in a single ring. But if u have a separate ring connected separately with the switch, there won’t be an issue. RSTP and HSR can both will work fine about the switch PT503, if it’s an industrial switch, it will work fine.

– Can anyone share the Easergy studio software password?
– Can anybody help me? This switch has been faulty and I don’t know why.
– If you’re having a dual DC source then check the healthiness of both DC supplies. In some cases, If one DC source fails then the switch will give that indication
– you should connect to the switch and read the logs. there may be an alarm for acknowledging for example a link was down, a link was disconnected, etc.

– Hello everyone, Need some help with testing of SR 489 Multilin Phase Differential Characteristic curve using Omicron Diff Operating Characteristic. Has anyone ever verified its operating characteristic?
– In the one substation we have license errors in WinCC frequently (siemens automation)What I should do for getting rid of this alarm?
– It’s a hardware key. U contact Siemens helpline. No, It,s software licenses cc no pas, We have a dongle for sicam pas
And our server doesn’t have any problem
– Error about pas cc configuration
– I think I have missed this license
– It is showing In license.log what is exactly missed
– Ok I will check it
– This license is trial and limited
– If you press the details it shows what is exactly missed
– Ok. How I can repair it?
– But one question, what about the WinCC License?
– I’m dealing with SCC 9, for using that version we have to install WinCC at the first step, license it, then install SCC and license it
– Click details.

-PASCC-configuration license is missing or expired
– but how fix it?
– The trial version is expired. This is for deleting the trial version

-I need to know just how to communicate with the relay and uploading and downloading procedure?
– I tried to communicate TIA15
– Regarding communication and upload and download I need to know the actual way, Because I have experience in Digsi and reydisp software with that I do that blindly but I couldn’t get the correct methods

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– I Install PCM 600 software, after the installation, I update the connectivity package by using the update manager. It shows an error like that ” server couldn’t connect”. How to resolve it?
– Check your connection, if you are using a private network such as your company this may occur
– but I use my internet and I turn off my firewall also but it again shows the same error.
– PCM needs SQLSERVER, this software comes with a PCM package and during installation, you will see that at first SQLSERVER is installing. Maybe it doesn’t install correctly depending on your windows configuration
– It’s true but I don’t think is this problem, it’s most likely of being something with an internet connection, try using VPN
– Uninstalled SQL server then reinstall issue will be resolved
– In the one substations sometimes we have a false alarm. Can anybody help me for finding the reason?
– Check IED events and the MMS 61850 mapping
– Probably another event is triggering the wrong MMS mapping
– the IED did not save anything in the events. How I can check 61850 MMS mapping?
– Can you cause this event again?
– You can use a package monitoring software
– I should trigger this signal manually
– I’m not good at supervisory but I’m pretty sure you can track down on this one the logical device/logical nod..etc until discovering which event is causing this false alarm
– Please try to load the CID once again in the IED
– It seems they are some kind of GI? Don’t you think? Anyone knows how to resolve
– Restart relay.
– Already restarted
– Try to read with PCM 2.6 And PCM 2.9. Try with a different laptop.
– Already tried with another laptop
– Kindly install the latest Hotfix file on your laptop.

– I doubt if we install fuse and MCB in the same rating, then if overload comes what operates first either fuse blown first or mcb operate first if it is so why? Reason. The same for short circuit condition
– Fuse
– Response time is faster than McBride
-Could you please share with me the response time for MCB and fuse?
– The answer depends on the thermal capability curve of each
– How we can clarify? Any documents for this

– When Three generators are running in parallel, suddenly one generator got trip. What happens to other generators? I know that the speed of other generators will increase but I don’t know why?
– According to the drop curve In other words they all agreed to provide the grid with a 50/60 Hz sinusoidal voltage waveform. You can only see the actual increase in speed when you disconnect the generator from the grid. This question is quite complex, the generators are running on the grid or isolated from the Power system? If are connected you need to know how big is the influence of these generators in the system. In other words, you will need a load flow simulation and a transitory simulation engine to know what will happen with the other machines because synchronous generators have angular stability that depends on the intrinsic constructive characteristics. If the system is isolated is most likely that the tripped machine will accelerate and the other machines will decrease speed, if the variant of power is the inside capability and angle stability the speed regulator and the voltage regulator will set a new operation point to guarantee the operation delivering the same amount of power (sorry for bad English, just woke up)
– Actually, this is on a machine connected to an “infinite power” bus. If we are talking about a big loss of generation the machines will swing around the main frequency raising/decreasing speed, right?
– If the frequency of the other two generators was raised means the speed has to increase right?
– Because for speed=120f/p In synchronous machines speed -> frequency. But again, it’s most likely that the speed of the two remaining generators will decrease. Once you have the same amount of load and have to decrease your generation the electrical current on the remaining generators are higher, this will result in a bigger magnetic flux that will make a force in the opposite direction of the primary machine (turbine), in other words, this should break the generator. But as our colleague said, in a big power system you shouldn’t have speed variations. It will all depend on your system. Is impossible to give a precise answer without the information?
– The speed will decrease most likely depending upon the governor’s response if they running in an isolated system. A change in active power demand or production causes a fluctuation of the speed (frequency).
If a generator trips, the frequency will decline. If the loss of generation is greater than the spinning reserve, the frequency could eventually stabilize at a new value lower than the desired one. However, in practice, under-frequency relaying is used to reestablish the balance between power demand and available production. If the frequency decline is excessive, generating units can be automatically tripped off causing an additional decline of frequency, and possible collapse of the system. Acceleration torque (Ta) = T (mech) – T (elec). For small variations 😛 (mech) ≈ T (mech) P (elec) ≈ T (elec)

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– how to download Micom Alstom relay software If you have any software links send
– Google MiCOM S1 Agile

– Does anyone have Torkel win 3.0 (or any) software available?
– I need to download digisi 4.91 or 4.93 with Windows 10 Pro 64 bit
– Anyone can help me to give me site, I can download it directly

– this relay does not turn on why?
– Pls ensure the polarity of the Auxilary supply
26- Ok C1 is + and C2 is –
– Are you sure about the exact output of your dc source?
– Insulation failure at the termination… may be due to too much dust or deterioration of the Elbow connector

– Do you know how to reset the password of this device?
– Yes, I have confirmed a polarity, some problem, relay not turn ON!
– Is it a new relay?
– Yes I used a CMC 256, auxiliary source.
– When u turn On the supply measure the applied voltages on the terminals of the relay using a multimeter.
– What happens when u use a test set. When u apply the voltage on the relay, the voltages drop. I face the same issue on Sr 489 relay using a CMC 356
– Check the applied voltage using a multimeter.
– With changing the configuration and sending it to the relay, this error appeared, what the reason is?
– Relay is in pickup condition, which function?
– How can I find it?
– Check General Introgation
– Exit the pickup condition

Protection relay discussion groups

– I am unable to connect through DIGSI
– Can somebody guide me
– Any fault is there
– What is that LED glowing?
– Check com number of laptop in device manager—> ports
– Change your laptop serial Port configuration, Select the same com number in the laptop, and digsi. Maybe you don’t install the device driver.
– Please check the VD address in ur digsi. Check your Siprotecs drivers

– Can anyone tell what is the password for the ABB 545 Feeder management relay?
– To access the protection setting and to change the settings
– Can anyone guide about Generator Overcurrent with Voltage Restraint protection
– in our dcs system we can get disturbance records of all relays but one. I checked the relay with ied explorer, cfg exists in the relay but the bus doesn’t get it. The Comtrade directory address and everything are fine. Can I use Wireshark to see what’s happening to the file? I used the MMS filter, but I need a more specific one. Does the file transfer through MMS protocol at all? Can anyone guide me?

– We have AVR fed by PMG, can we disable the Voltage Restraint or Voltage Controlled function?
– Kindly use Wireshark and check this shall help u
– With which filter?
– Can anyone in the group help with this
– What is the effect of ambient temperature on SF6 gas pressure!
– Guage readings could be different in day and night timings? Especially in winters
– Pressure will reduce in Winters And especially at night, u might face an alarm or trip in the night and that alarm may go away in the morning
– 7 bar at 20 degree

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protection relay 2 Discussion

– During one phase PT failure, will overflux relay work? Has anyone seen this kind of voltage transformer connection?
– Why is B-phase winding grounded on the secondary side?
– Can u share the nameplate details of the PT
– yes, in an oil company, usually they only use 2 PT inputs and make it a delta connection in the relay
– That’s an open delta voltage transformer or potential transformer.
– It’s mainly used as an input to detect earth faults using neutral voltage displacement.
– Typically the sum of the voltage across D7 and D9 is zero. however, should there be an earth fault and one of the phases hit the ground? you will get voltage across the open point
– Such schemes are used in ungrounded systems or on generator-transformer sets. there is no path for earth fault
– Sorry open wye but the scheme is the same.
– Open delta connection, Yellow phase normally will ground. But as per the drawing seen some conflict.
Normally 2 VT Winding we can see.

– This is a star connection with the y phase grounded Not an open delta. I was reading on the internet it’s some old practice followed in the UK.

– Anyone has any experience with diesel Genset paralleling on the common neutral resistor? How many generators can work connected to the resistor and how many can work isolated in parallel mode? That’s a very big open question.
– Yes, it is problematic to solve its protection system
– Yes we typically run the neutrals to a common neutral bar. Install at least 3 the neutral earthing resistors and contactors
– Are you talking about medium-voltage generators?
– Yeah.
– How did you calculate the size of resistors
– Please, can you share some calculations?
– I need a setting guide for directional protection
– If any example for Double feed SubStation with the tiebreaker normally closed
– What is the Apts scheme?

– For this system, with the two Transformers secondary breakers and the tiebreaker normally closed, and installing directional on the two secondaries, I need some guidance on how to make the setting for the directional, And if anyone has a similar case I will be glad if he shares his settings and how to make them?
– the intention of the Directional on the secondary side is for backup protection? I ever encounter an application that uses the secondary side 67 as a backup by looking up into the transformer and if it operates it will trip both HV and LV.

– Can anybody share about the zig-zag transformer? Principle operation of it.

– Anyone has SR 469, SR 650, and SR 750 test formats? Which is software used for these relays? Anyone pls help?

– what could be the cause of the SF alarm?
– PLC is communicating with another PLC over Profibus
– Well, it can be a lot of stuff, but the first thing I always have for this alarm. SISTEM FAULT means that you may have some unit programmed inside your PLC that is not connected in the field.
– So if it still works let it be
– with that alarm all parameters of the slave address become red
– This is not something to concern, just be sure you have a good backup of the PLC program. but if it remains, it will not let the startup of the Engine
– Yes, but if it is already working, maybe is only a module programmed in the PLC but not connected in the field, but I say, I saw processes going on for Years with this SF, and nothing ever happened.

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– we have a problem with the Genetaror Micom P343 that does not boot, please help us how to fix it, thanks
– Check the ribbon resistance of HMI to relay. We have faced the same and asked Alstom then after they checked and replace the ribbon, and fixed the issue.
– Where is the ribbon?
– Open the front side of the relay then there is a connecting ribbon cable u can find
– This, is not Bad contact Ribbon the message is clear (Micom Booting) with Led Alarm lightning in red Fast
It’s like PC booting, I think it’s a microprocessor issue
– We have faced the same problem in our reliance industries Jamnagar plant and Alstom itself give us a solution and change all the ribbons. Micom rebooting issue may be from the HMI problem/relay power card problem but if it comes even after replacing HMI look forward with manufacturers. It’s not just like pc booting issues. There is no chance of error in the relay or bugs like a microprocessor.
– I might be wrong but I share what I experienced with the same problem.
– Any vacancy for a Facilities Manager
– How do I determine distance characteristics in the L90 GE relay? do someone has a commissioning manual for L90 relays?

– I want to know what you guys as an Electrical Department are doing to fight COVID-19 in their workplace.
– 132kv circuit tripped showing R Y B phase and zone 1. And the same circuit is energized from another end at no load. Also, no fault was found on the circuit during patrolling. What will be the fault? Distance Relay type Micom P 441. It could be transient or pic up fault
– Does it show any distance in zone 1?
– Grid staff is not too efficient to check the fault recorder. I will go to check it tomorrow and will discuss it again
– What is the status now does the line charge from both ends?
– Only from another end at no load
– Sir but usually these transients will be blocked by numerical relays rights
– I think it may be DC grounding
– Check the fault recorded to see the fault current and voltage
– Lighting
– Depending on the magnitude and relay Makes. We have had similar invent without any trace of a physical cause
-can you share with us the Comtrade file

– What is the standard setting of the characteristic angle for directional overcurrent phase and ground (67/67N)?
– does somebody has this relay technical manual ABB PCD for the recloser?

– Hi anyone has a static VAR compensator (SVC) protection scheme that can share?
– What is the standard setting of the characteristic angle for directional overcurrent phase and ground (67/67N)?
– For typical distribution networks (up to 33 kV), I set it to 30 degrees. For sub-transmission/transmission, I set it to 45 degrees, between the current phase and voltage polarizing quantity.
– However different scenarios may require different angles and have to be worked out.
– This angle for directional phase overcurrent? What about the angle for directional ground over_\]\]\]]]\\]]\current 67N?
– Are there any references for how to make the setting for directional phase and ground overcurrent 67/67N?
– I would typically read the relay manual, And use the default recommended value. The actual math behind setting them can be very tricky.
– Which relay are you using?
– Sepam s40
– The application is two parallel Transformers
– What’s the voltage level and how far is the relay from the supply transformer?
– From experience, RCA is 20~40
– For 67N, the value is dependent on the type of grounding. Please refer to NPAG, it was clearly explained there
– Anyone has a digsi4 Activation Key? And for 67, if I am not mistaken, RCA is set based on the impedance angle of the system

– Anyone tested Transformer DIFFERENTIAL 7SR242 DUOBIAS. I have some doubts about bias characteristics!
– This is the complete manual, but the bias equation is not clear on it!
– Does anyone here got any information about ct accuracy class 0.1 PL 270 R6
– I want to know knee point voltage and resistance

– Install Studio Enterprise this is a combination of all SCADA & it will work as per your licensing

– Does anybody here has experience with Toshiba relay GRL 200?
– I want to ask about the IO config
– Why don’t you Let the admin look into it? Please send me any study material regarding AVR
– For a substation
– Little emergency for my undergraduate project
– I can send you the datasheet of Engine AVR
– ABB Unitrol 1000

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– I have to change CT/VT ratio in an Elster A1800 energy meter. Already got established communication with the meter via Metercat 3.5 software. I believe CT/VT ratios can be changed via the function “Program” but I am not able to proceed as everything at the “Program” popup window is grey (not editable), I request you support me in changing the CT/VT ratios.
– You have to enable changing xt ratio on the parameters function

– There is no Parameter menu in Functions? please clarify in detail or send a snapshot
– Hi Guys, I have a question for the 220KV level, which is suitable for either CVT or IVT(PT)? And why Usually we are adopting IVT(PT) in Andhra Pradesh India
– CVT always
– Sir can you please support your statement As we have observed the drift in secondary voltages is more in CVT compared to IVT over a time span
– Mainly installation reasons. they are lighter, cheaper, and Safer (transfer of emf when a fault occurs) as there is no direct connection to the primary voltage source.
– Can you explain how does the voltage drift?
– Deterioration in the capacitance levels throughout operations results in variations in secondary voltages Can’t that be fixed during maintenance? (Note: I don’t have any experience in maintenance and operation Even I don’t have any experience in Maintenance. But I am not sure we can improve this ineffective manner)
– CVT for transmission circuits or High Voltage i.e greater than 66kV and IVT for distribution circuits 33kV and below
– Moreover, we are mostly using IVT in 220KV levels also so, I am not aware of fixing methods. I believe it’s a cost trade-off. In India IVTs in 220kV class are more affordable than CVTs. And yet you may see them actively used in 220kV stations where the transmission system is at 220kV level. This is because the same CVT would be used as a coupling capacitor for PLCC communications as well.
– That’s my understanding
– Why when we calculate short circuits at transformer secondary we should consider no-load ph to phase voltage not rated voltage?!
– Yes.CVT is more affordable to be used since the consideration of its(equipment) isolation to H.V.
– Yes, we can track and analyze its dissipation factor( Tan Delta measurement)
– Which position?
– This is an AVR relay from ZIV bringing.
-anyone has the pin configuration of this relay?
– If you mean bias setting, then I would say it has to be calculated based on the transformer parameters
– Hello everybody, good morning. Do any of you run the digsilent program?
– What /which are the switching operations and commissioning procedures of HV / EHV equipment considering the safety rules of power system operation?
-P94V Undervoltage relay showing continuous trip, but no alarm present and all functions disabled, need technical support .can anybody please help?
– Go to view record and reset led Did, but still not going
– To increase the contact Resistance with the Ground!

-To minimize step potential?

Our completed Courses:

– Why stone and whether it’s the only solution?
– Cheapest
– Another reason stones are used is because it helps in the fire. mitigation, especially where oil traps/ sump pumps are not available.

– The leaked oil will have less surface area exposed to air that can burn, thereby reducing the fire hazard.
– Weather dry sunny temp 35c approximately Fault 132kv lighting arrestr and HV bush of power transformer 20/26MVA damaged
– 132kv CT side clamp
-Counter of lighting arrestr
– Lighting arrestr
– Structure damaged After fault jamper
– Analysis as per our senior-most retired chief Engineer such type of fault occurs due to delay of lighting arrestr counter delay. This type of fault occurred in Pakistan time by a time when lightning arrestr having counters are installed. Due to the delay, the HV bush of the power transformer was also damaged
– Did the Hv bushing pass the lighting impulse test?
– At the time of manufacturing or now
– Bushing may be damaged due to pressure of conductor available 132kv surge arrester if required plz context 03214484444
– I wonder if you have the fault recorder of this lighting surge impulse on your relay
– Are there any lightning arresters at the top of the transformers firewall/ other location?
– What’s the fault in the protection relay or fault recorder?
– Ds agile documentation please, guys how can I get cooling oil for a 1000-volt transformer
– What is the relay saturation of the IDMT curve in sepam T80 and S82?

-Any have experience In Reyroll Relays.! I need help with how to change the “Out of service mode”.

– We need to do an 87L test, as you can see in the secondary current to relay is very low 0.044A. We did a second injection for the GE L90 relay and found it doesn’t read 0.044A. Value is fluctuating and gets stable at 0.1A.

– why the 51N protection of the REF615A relay operates in an almost constant time of 0.06 seconds
– reviewing the operation curve the minimum operation time is 0.02 seconds at least the first 3 tests would have given me the correct value
– check the other seating. Check the type of curve selected in the relay, Whether it is time or IDMT
-1 group setting might b clashing with another one, check all stage settings group-wise.
– Work Is for Automation Visit in Kolkata. Just visit the site in Kolkata only people from Kolkata plz contact me.

– A Power distribution full project including the design of LV and MV component
– 40mva x-mer tripped on differential during charging of 33kv feeder with Idr= 0.49pu, Idy= 0.50pu and Idb,= 0.53pu.
Both sides LA has physically verified and found ok.
– Did you check the %of Harmonics during charging from the DR?
– please do a stability test and after that examine the results.

– might anyone have the design book of transformers with CRGO steel core and amorphous metal core
– Please guide how to reset DR full alarm in DPR Micom p442 Schneider Electric
– Maybe you can right-click on the device and select supervise device

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– Anyone has a VALANCE book on “How to Test Breaker Failure Element Logic”?

– I have a problem with Micom P443 for Distance Protection. I have a problem with System Checks for Autoreclose, anyone can tell me what is the difference between CS1 Close Enable dan C/S AR Immediate?
– Cs1 close enable is the setting of sync check on which you want to recloser the circuit breaker like on Live Line Live Bus or Live bus Dead Line or Dead Bus.
– If you enable c/s AR immediate then it means that if during the dead time system check conditions are met then it will reclose the breaker without waiting for the remaining dead time period,
– Like for example if dead time is 1 sec
– And system check conditions are met during 0.6 seconds of dead time, then the relay will give reclose command without waiting for the remaining 0.4seconds of dead time. But you have disabled the system check conditions on shot1 which means it will reclose the breaker without looking into any system check conditions,
– Sys check on shot 1 should be enabled too.

– Hi Guys I have a question: what is the problem with a 3phases motor run by A frequency driver, if I want to run it very slowly for instance at 4HZ normally it runs at a modulated Frequency variable between 50Hz and 0 but what happens to a very low frequency?
– I know that it will run slow, but it will warm up a lot right? but more than that what will it happen? somebody, some documentation to explain this phenomenon?
– It depends on the loading. The higher its loading, the more power is needed to turn the output torque. If you don’t have a load, just make sure your lower frequency setting has a minimal current to move the rotor otherwise, it will overheat.
– I even reinstalled my windows not going, I checked the internet settings also.

– how we can develop an HMI screen of operator name tag id selection in Schneider Vijeo Designer Basic HMI software
– Can Anyone suggest or provide a link for low-cost alternatives for moxa U port 1150 type connectors with similar capabilities?
– USB to Serial converter

– Does anyone have sft sav diagnostic software for the Sepam relay?
– Does Anyone know about selec Twix-2 PLC communication with Schneider HMI
– Please have someone ever configured SEL 487B busbar protection?
– The SEL Technical Support Line is available at +1.509.338.3838

– does anybody here has the SUE3000 configuration tool
– Some examples of End Fault Protection with SEL 487B?

– Anybody can please share with ME Schneider Software SFT SAV?
– what does this number means 6000 of this RCD?
– It can open currents up to 6000A. 6kA
– Note it’s RCBO not RCD
– What s the difference? Because some tell me it is the max number of trips. RCBO stands for residual current circuit breaker. It can open faults up to 6000A. It can be used for short circuit protection as well as sensitive faults of 30ma. RCD is a residual current device. It’s used only to pick up sensitive 30ma faults. They can’t open full short-circuit currents. -Think of RCBO as RCD+MCB
– No it’s the rated fault level.

– We have the following problem with ER making DUOBIAS relay for Transformer differential protection
– Can anyone guide what to be done with this?
– Hi anyone tested the commissioning motor differential protection relay procedure please Sharing
– Short circuit level for this device
– This kind of error shows in sverker 900 Megger relay test kit anyone has an idea what is this?

– Maybe you could try to restart the device. And try jumper each phase RST to the neutral phase.
– Jumper are arranged like this is it ok?
– I have restarted the kit but it not working
– Jumper I1to neutral, then I2 to neutral, and so on. Simultaneously inject a small current to monitor the device voltage ports are also not working
– How about the current ports?
-They are also not working
– Make sure when you start the device the knob selector is in an off position.
– Check the fuses too

– Does anyone know if you can force or simulate voltage on an ABB relay? That is, without using a device like Omicron
– someone helps, how can I test the GE L90 diff relay as a stand-alone without connecting with another one? You can only force digital outputs and simulate inputs. You can’t force analog signals such as voltage and currents. You need an external source
– I’ve never dealt with this relay but If it is for line differential, chances are that you’ll need two relays. the receiver and transmitter
– But you can still use the primary injection method to do the testing
– Do you have to test line differential?
– You can go to setting, testing, channel test, and loopback. Inject currents, the relay will consider one current as local and one as remote

– Hello guys, I’d like to ask maybe some of you ever test this type of relay.
– Where can we find the tms
– I think tms is 2
– TMS is nothing but a round dial
– Yes it is 2
– In this case, it’s 2

– for ref relay input problem. Ref620
– From the drawing, check the terminal point associated with this input. Isolate it then troubleshoot that circuit to find out where the “high/positive” signal is coming from
– why does inside relay see this message drawing as not a problem?

– I am working with a 2X300 MW thermal power plant in India and our 400 kv switchyard is having Alstom MICOM P 441, and REL 670 for protection also for the generator we are having siemens make 7UM622 and MICOM p345.
Is there any standard that speaks about the frequency of relay testing?
– Normally frequency of Numerical Relay testing depends on the utility practices.

– In our utility, we do it annually. But in my opinion, it is not required annually.
– Numerical relay can be tested for 5 years once. Scheme testing can be done annually.
– anyone has a cracked version of IED smart or IED scout for the IEC 61850 simulation?
– How to do scaling of this pressure sensor
– these transmitters are of a fixed range
– 615 series?
– try to use a new project. if still like that try to factory reset the IED but if it is still operating


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– How to connect GPS to this siemens relay 7VE632
-synchronization via IRIG-B
– someone assists me with CPC 100 software.
– You either need IRIG B port on the GPS receiver or you need NTP to IRIG B converter

– Please find below the parameters you are expected to use as discussed with RTM;
Reactance = 0.2215 ohm/km
Inductance = 0.20808 ohm/km
Suseptance = 0.07573 ohm/km
Distance = 313km
– Please how can I find the positive and zero sequence impedances from the above parameters thanks
– 400 KVAR 90 UNITS. 132KV CAPACITOR BANK. neutral CT 5/5. 132kv CT 400/5. Capacitor protection or unbalanced relay current setting? Relay type SPAJ 160 C
– Normally Unbalance protection has one special other CT different from CT 132kv phase or CT neutral but if This CT 5/5A is just for SPAJ protection we adjust the setting unbalance between 10 (..)20% In for nominal current this CT 5/5A

– Please explain the working of the reverse power relay at the consumer end for the small hydropower plant with a declared capacity 24.75 MWWhat is recommended Characteristic angle for Directional Earth Fault protection (67N) on SEPAM

-Sepam relay is on the closed-loop network.
-System grounding: resistance grounded (Two NGR Prallelled: 2x800A: 1600A).
The type used for 67N on Sepam: Type-02 (the protection function uses I0 vector magnitude).
Residual Current input on Sepam: Calculation of Summation three-phase current (not residual CT).

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– I want to know if my raw data for the sensor is 0 to 32767 and I wanted it to show in HMI in the format of 0 to 100 bcoz if in system sensor mistakenly gets faulty or I have to replace the sensor and the sensor of any other company in my system, so due to this I can change from HMI raw data in the format of 0 to 100 is it is possible?

– Hello, Micom p-243 protects the compressor after start 15 minutes then trip. The indication in local HMI (motor fault alarm )but in the protection relay no indication but became an open position. When I go to the record I see this in the pic
– I do isolation resistance for the motor by using 5kv meggar the result was 4Gohm

– In HMI how to create an operator name error
-It’s over Current, what’s your starter motor current start pick and protection Micom configuration?
– Respected members, Please guide me on how to carry out the Hi-Pot Test/Dielectric strength test for 22kV 3ph Breakers/Bus bar.
-If the available source is DC for testing, how much voltage is to be applied, and are any references of the standard for the same?
– How to write scripting language for 0 to 50 Low and 50 to 100 high values in C programming for HMI?

– on Nari pcs9611 relay, when powered on it displayed sub-supervision Alarms. Alm-device, Alm -time sync.
How can I cancel?
– set the time synchronization to off instead of sntp
– Under settings?
– under device config or communication.

– Does anybody has ZX0 ABB switchgear O&M.manual
– Especially Gas handling procedures
– HB 600-05 en
– HB 605 Gas handling Manual for ZX0
– I tested my lightning arrestor for 11KV after removing it from the line and the IR value was 400 meg.
– A few minutes later I tested it again the value was raised to 15 Gig.

– Please I need the manual of Siprotec 7SA87
– Hello everyone, could you help me with the function of the TC1 on the delta winding?
– It’s a current transformer for the winding temperature gauge

– someone knows what is the difference between I> and I>>?
– I> is the short-time protection setting and I>> is the instantaneous protection setting of the overcurrent relay
– Can somebody tell me what happened if the tripping coil resistance and a closing coil resistance of vcb are the same? then there is any impact on the performance of vcb?
– You can return to the datasheet of the circuit breaker and closing and tripping coil, you can find the standard values of the resistance of the trip and closing coil and compare it to the measurement
– I just want to know the theoretical answer Behind this.
– From an electrical engineering point of view
– closing coil resistance is designed much less than tripping coil resistance to having a stronger magnetic field
– Yes I know it is designed, but my question is if they are the same then, what happened?

– does somebody here have some “how to configure Modbus protocol in SEL relays” document or some kind like that?
– Someone has a method statement for Testing CVT Tan Delta

-Does anybody have a project for the RED670 relay?
– Anything, in particular, you are after !’vv?
– Current line differential relays fairly straightforward?

– Anyone knows what is the problem when a source (power plant) transmits power to a substation, then the neutral current monitored in the power meter is a bit higher than normal?
– I know that It means that there is an unbalance current in each phase. But what else can be that causes the phenomenon?
– The P.F on phases R and S are lagging 0.9, but phase T shows a leading P.F.

– In case it’s an internal fault, just assume that the 87 T relay and Ref relay will trip.
– your understanding is correct. But apart from it, if primary Overcurrent (50/51P) works, it will trip the CB 150 kV, and how about the CB 20 kV?
– Is it required to trip the CB 20 kV too?
– 87T trip, REF not really, depending on the fault. PP fault or 3P internal fault won’t initiate REF
– To isolate the power from the LV side too, in case of bus section on the 20 kV side is closed
– Depends on the control scheme we use in most of the cases we adopt if HV side CB trips on protection LV CB also gets a trip, and REF is more sensitive for earth faults in the differential zone. If it is an earth fault REF trips faster than Diff.
– I think that 20 kV CB will need to trip too to prevent reverse power from the remanent voltage (power) at Bus 20 kV side. But if there is a remanent voltage on the 20 kV side, is it possible to induce a voltage in the primary winding to create a current?
– Since you have NGR, an earth fault close to neutral may not be detected by REF.
– Percentage of the unprotected zone can be calculated based on relay settings and CT ratio.
– Yes. due to the resistance, the sensitivity will be limited.
– Have everyone ever tried the induced voltage on the secondary winding of step down Transformer i.e. let’s say 150/33 kV. How about the primary winding transformer, does it will generate a low current or a harmonic current?
– Actually, fault moves towards the source. In actual LV will not trip because the fault current will move towards the source side (150kv) side but if inter trip function is available then LV 20kv side will trip too
– Anyone knows about the calculation to get the value of Z1 Sensit? Iph>1 ?
– Fault current should be above this value to identify zone 1 or zone 2 faults
– I got it. But how to get this value?
– Okay. I have found it was 1.2 x CCC / CT Ratio
– CCC indicates which value? please clarify I doubt the Current Carrying Capacity Of the conductor
– In Distance Relay
– Anyone knows the CB IS( In-Service) Time function?
– Since I close my CB then the IS time starts to count to set AR Block
– If CB is manually closed then after this time CB will be considered in service and the Auto Recloser function will be enabled too.
– But why it AR block indication appear?
– After the CB IS Time starts to count. Still struggling on this distance relay
– Because during CB IS time AR Function is disabled to block the AR on SOTF fault, change to ABB REL670
– What type of relay is this one?
– P443 Micom
– does anybody here has a p14d Modbus register
– who knows the ZIV default password
– Any ZIV relays specialist
– Hello all, does anyone has a GRL 200 Toshiba Line Current Diff Manual Book?
– Four corner numbers 7931

Join 20 WhatsApp groups for protection engineers

20 WhatsApp Groups for protection engineers

  • WhatsApp Grp 01: Protection Relay – General
  • WhatsApp Grp 02: Substation Automation – General
  • WhatsApp Grp 03: Transmission line protection
  • WhatsApp Grp 04: Transformer protection
  • WhatsApp Grp 05: Motor protection
  • WhatsApp Grp 06: Generator protection
  • WhatsApp Grp 07: Overcurrent and Earth Fault Protection
  • WhatsApp Grp 08: Busbar protection and Bay controller
  • WhatsApp Grp 09: Breaker protection and control
  • WhatsApp Grp 10: Protection Relay Testing and commissioning
  • WhatsApp Grp 11: DIgSILENT
  • WhatsApp Grp 12: ETAP
  • WhatsApp Grp 13: PSCAD
  • WhatsApp Grp 14: IEC 61850 configuration
  • WhatsApp Grp 15: Switchgear GIS & AIS
  • WhatsApp Grp 16: GE Relay Configuration
  • WhatsApp Grp 17: SIEMENS Relay configuration
  • WhatsApp Grp 18: Schnider Relay configuration
  • WhatsApp Grp 19: SEL Relay Configuration
  • WhatsApp Grp 20: ABB Relion configuration or more services

send a message to our WhatsApp support number, (Click)

Sample discussion:

– I have a Zivercom relay for the Tap changer. everything looks fine but it’s not Tapping who can assist tanks
– is anyone familiar with Siemens Siprotec 4 7SD Line Current Differential Relay? For example, if one end of the relay is selected in Commissioning mode(test mode), will the remote end relay differential protection be in commissioning mode or test mode also?
– Commissioning mode at one line end will not turn on commissioning mode automatically to another side. Plus commission mode is completely different from the test differential mode.
– Can you explain a bit more about the test differential mode?
Does turning the test differential mode at one end also activate the remote end’s test differential mode?
– Anyone REM620 relay this message what problem
– Anyone has the actual standard IEEE 485 or an excel sheet? I need to size the substation battery charger, please!
– IEEE 485-2020?

– Does anyone know what these signals are used for?
– Apparently, they are permissive to Switches
– the arrangement of the substation is as follows
– Have anyone tested Cap bank differential protection in Siprotec 5 7SJ85 relay?

– constantly get this error while writing to the IED
– delete the HMI page first
– do the license update tool
– Does anyone have software for this relay micom2.1?
– I have found Micom software if anyone can give Ziv software as well plz
Our substation incomer feeder is tripping downstream and upstream without any fault when switching on outgoing feeders.
– Please suggest any ideas to solve the above-mentioned issues
– What fault was recorded by the relay?
– There is no fault on the relay but upstream and downstream are tripping when switching on any outgoing feeders.

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– Any circular regarding the fair service life of various testing equipment in the power sector.
– Hi, has anyone ever replaced these manual annunciator window tiles with a 3rd party tiles? or other alternatives?
– We are facing this kind of rebooting issue with the AREVA Micom P742 peripheral Unit for busbar protection. Does anyone have any idea regarding this issue? How to overcome this?

Protection Relay Discussion Group in Telegram:

– Can we use a 10 ac drive on a 15 hp motor?
– 12.5 hp drive on 15 hp motor
– Hi, do you guys ground the shield of control cables at both ends or only a single end?
– Single-end
– How about for CT VT Cable?

– May I know if would there be an issue if we use a CT with a high Burden (15VA for example) for a protection relay (microprocessor type). For the old mechanical type, I understand that the CT needs a higher burden to drive the armature
– when I turn on the generator in this panel my generator has an unstable frequency but when I operate it manually the frequency stabilizes. what may be the cause of this?
– Is your gen-set in synch with other gen?
– no sir.
What is voltage?
– plz check the gain & another setting for your operator panel
– 460v
– there is no problem with the engine & gen-set itself it is the only problem with the operator panel feedback signal which will be generated as per setting
– Cause freq regulation is in the generator itself not in Woodward
– we try to bleed fuel on the generator. but nothing happened
– I thought Woodward only does parallel synchronization and some protection functions but is only using small loads that’s why we don’t sync our generators.
– I looked at the manual for easygen. There is a function of frequency control. I have the same system
– But never got time to check every function in Woodward.
– I do check some functions but the configuration has a password. the management told me that the supplier has the access to its unit.

– does anyone knows about arc resistance and tower footing resistance value for the 765KV transmission line?

– I need to disable goose controls in the REF 615 ABB relay. Is it possible from HMI?
– who can assist me with an IED scout that’s licensed REG630 how to test method DOPPDPR function Power Angle setting anyone to have a formula
– Could anyone be having transformer test guides preferably based on megger make test equipment?
– Paci’s configurator from Schneider, can anybody have this software if yes kindly send me the link, it’s urgent please help me
– Somebody has REX640 TERMINAL DIAGRAM?
– Does anyone know how to choose a zero-sequence transformer?
– In the VAMP300 relay display LED continues to glow without assigning, without mapping with DI points. what is the issue please kindly suggest!

– Need help in ABB RVC APFC Relay programming.
– If anyone has a license for REB500. Can help me, please?
– ABB normally does not release that license that allows you to configure
31etap 12:00 – abb pcm600: The user license there isn’t much you can do with it.

– Kindly someone tells me that in C264 Relay, how to change synchro-check parameters and find the passwords?
– Connect to Cat tool to these devices n check network parameters. Trying to read the setting but the reading takes a few hours. Are there any solutions?
– I assume some delays in the network..try connecting them one-to-one if possible.
– Try to reboot the relay
– what could be the problem if Generator Shuts Down on High or Over Frequency, Over Frequency Runaway
– If you are connected to the grid Burn the rotor due to induced currents. If you are in islanders mode: damage the connected equipment.

– is it ok to run a generator that varies 59.9-60.1 frequency?
– Trying to read ABB RET 670, but the messages show up like this
– Any insights into this problem
– Does anyone knows how to add delay time in VT Fail ABB RED 670
– Not very sure but An inconsistent state means the current values in PCM are not reflecting the IED values. If a reader does not resolve this try to see if there is a new version of PCM.
– 132kV transformer HV breaker was closed on NO load and the LV breaker was open, but suddenly differential relay operates and gives a differential trip. In the fault study, the HV side current was 860 Amp. Somebody tell me what could be the reason?
– For how much time the transformer was on no load? 132/11.5kV?
-Approximately 10 to 15 minutes
– MVA?
-132/22 kV (wind power plant)
– There must b some issue,
– So this is not inrush
– Do TTR and winding resistance,
– If it is the newly commissioned plant then the issue will be in the relay setting otherwise check transformer winding. do the IR.
– I did an excitation test @ 10 kV and the results were OK.
– Plant is in operation for the last 4 years. You will have to do TTR and winding resistance to diagnose the matter, Hope you will get the problem by doing these tests,

– Any mechanical protection PRD, BUCH has operated. Did u retrieve the fault records from the relay?
– TTR?
– turns ratio test
– No trip from mechanical protection.
– In the fault record HV current was 860Amp and LV current was 0 amp.
– Check the CT ratio adopted in the differential relay and what was the differential current setting adopted and actual current during the relay operation?
– Transformer turns ratio

– In 3 phase
– Did you check the lighting arrester AT 132 KV SIDE?
– Yes surge arrestor can also be damaged or weakened, as you are using Yard CT for Differential protection
– do also check your HV arrestors

– Can anyone help me with the PACiS configurator?
– Physically that was OK, for counter I will check
– Do hipot test of arrestors, which might be differential tripped because of arrestors, If u have a secondary injection kit like Omron or Freja plz do the secondary injection to know that there is no problem from the relay side.
– can I ask why my plc doesn’t read flow?
– Check that the analog signal is reaching from your flow meter to plc?
– Check 4 to 20 amp signal

– Hello guys, does anyone know how to avoid distance trips when VT Fail occurred on 3 phases in REL 670?
– Anyone has any material for Artificial intelligence application in Protection?

– Pls help me how to install PCM 2.10
– Strongly recommend installing on virtual machines
– After 3~4 different versions, they always conflict and give errors.
– I run different virtual machines on the ESXi hypervisor.

– I need help analyzing this Disturbance Fault Record whether it is due to Lighting or Flash.
– It was a fault on Line Diff and Reclose on Phase R.
– Plz tell me, what is relay coordination and what its functions are.
– Line auto-reclosed successfully?

– We have 50/1 5p15 CT installed on a 33 kv feeder whose fault current initially was very less but now the Power supplier has installed a 50MVA transformer with 11% impedance
29etap08:55 – abb pcm600: And fault current is almost 8000Amps, I believe I need to upgrade protection CT to meet the high fault current
– Can anyone suggest What’s the 33kv fault level?
– Now it is 8000 amps. Fault current level 50 MVA transformer installed at state electricity board substation and we are consumers with 33 kv feeder voltage
– 50MVA 220/33 KV star/ star connected transformer 11% impedance
– Is the ct used only for over current and earth fault?
– Yes 50,51, 50G, 51G
– Strictly speaking, I would put 200/1 5P40 2.5 VA. However, if the relays have CT saturation detection, you could go lower.
– What’s the relay being used?
– P127
– Do you have the CT test results? In particular the DC resistance of the CT.
-Can you give your consideration or calculations for this selection
– So you need an accuracy limit factor of 40, with a low burden.

– you won’t need much burden as the relay is numerical and installed inside the switchgear
– Your existing 50/1, 15 VA may actually work if you knew the DC resistance.
– Do I have to check with the CT testing kit??
– I believe CT supplier should have this information
– Yeah if you have test equipment (Omicron CR analyzer or similar) that should be easily possible
– That’s possible, however normally the manufacturer will not specify the DC resistance for 5P/10P class acts. No harm in asking them though
– CT’s Analyser
– Ok I will check with him today, as I don’t have an omicron kit available nearby That is the only option I have

– How do you coordinate DC resistance with fault current?
– So if Rct<= 1.75 ohm, you can use it For a 50/1 A ct this may be achievable.
need to Replace 33 kv side CT with, 1000/1A, 5P10,15 VA With this approach, I’d reckoned to check the pickup values.

– Ynynd1 And tertiary (delta winding) are unloaded?
– Then no issue transformer will follow the system phase sequence,

– What is the difference between IN-HV Deriv Angle and IN-HV Measd Angle on monitoring online?
– Derived means the neutral current has been calculated by summation of IA, IB, and IC whereas measured means the neutral wire of ct secondary is connected to the neutral element of the relay, and it is being measured,
– What is a dead zone in protection??
– Dead zone is the Zone between CT & Open CB. It’s the point not seen in the zone of protection that of a relay. If a fault occurs at this point, the relay will not issue a trip. Usually between CT and breaker
– IN HV derive is neutral vector calculation, meanwhile In HV measured is a neutral REF winding
– We cannot say it is neutral ref winding until we see the setting of the relay,
– the setting of the wiring diagram is right. The relay and schematic drawing setting depict the connection of the ct secondary wires with the differential relay.

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protectien relay

– How to calculate capacitor in mfd?
– Step by step distance quadrilateral characteristic for all zones how to draw. please give me any documents sir
– Please suggest Which one is better for bus voltage measurement Induction VT or Capacitive VT?
– Would selecting any of these two make any difference, especially in bus voltage measurements? I don’t think so.
– Capacitive surpass Power Line Carrier (PLC) otherwise they mau consider the cost of their design.
– Cost it seems IVT is more at higher voltages.

– Hi anyone has any training materials for IEC 61850 configuration and testing. Please share. Thanks in advance.
-Does it got configuration in IED scout?

– Anyone has a manual of ABB aux relay model RXPSU14n?
– everyone plz anyone tell me what are these feeders? 1. 11kv Substation loop feeder with fiber optic cable. 2. 11kv Substation loop feeder with pilot wire (send end supervision relay time). 3.11kv Substaion loop feeder with (receive end supervision relay type)

– Please tell me which terminals are going to be used for Carrier Send & Carrier Receive?

– this for scheme logic distance protection?
– Yes
– From highlighted portion, u can understand
– Sir, 1& 2 for Carrier send and 5&6 for Carrier receive?

– Can anyone tell me details of these terminals, it’s an ABB make ACB, SACE PR 121/p ( SACE Emax E2), Open coil, closing coil, motor supply, then Indication ckt, Contactors ckt.

– Can anyone please name a few line auto reclosure 11kv and 11kv and 33kV fault passage indicator manufacturers based in India
– Can anyone give to the solution of board change ABB REF542+ relay
– Which type of communication cable is required for ABB to make REF542plus?
– What could be the issue that the Ready LED is not glowing?
– Ready LED of D400 is not glowing..and our SLDC ppl are not getting data of the entire substation.
– Please suggest how to rectify the problem.
– If anybody has a 220KV substation all equipment SOP for operation & Maintenance. Please share

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– Have anyone idea about the overcurrent coordination between generator and generator transformer
– pls tell me how to decide Bus coupler CT ratio in the 220 kV Double bus bar system?
– Need IEC 60623
– Pls share if any member has it
– What is the busbar current rating, quad moose
– Can anyone reshare the pdf for electrical notes
– Anyone who knows Ziv relays plz contact me
– U want Ziv relay person no?

Our other groups:

. PSCAD group
. Substation automation. Please
. SAS WhatsApp group
. ETAP WhatsApp group
. SAS WhatsApp group
. Substation Automation & SIPROTEC & DIGSI Whatsapp group

– please anyone has SEL 487v technical Manuel for negative sequence
– Hi, anyone knows ZIV SCADA?
– Can anyone send me the Complete Design calculation PCC/MCC with 11KV / 0.415 V Substation.
– Can anyone share the electrical notes latest version?
– Substation Automation & SIPROTEC & DIGSI Whatsapp group, please
– Hello guys I should to cables tray, 90 degrees, 60 degrees, 45 degrees, and upsets and down set formula please help me
– our generator after start display come like this why my friend’s please give solution
– I have Relay GE 369
The password is forgotten How do I open it? How do I delete the old one and make a new password and delete the old one?
– Password reset is done in GE Canada only

– Can anyone give me information on how much the Clearance for 132/33/11 kV windings and the tank for 63 or 90 MVA according to IEC? Our Company design? And if possible the description of how the oil insulation process works according to this distance?
– Mean insulation between HV winding and tank
– anyone please share the HVDC station Single Line Diagram.
– Can any one of the engineers have p632 transformer differential protection calculations.
I had calculations for p633
– P633 is for 3 winding transformer differential protection and P632 is for 2 winding ones?
– I had dealt with 642 and 643
– Relays in transformer differential
– I have No idea on 63 series
– We are using P643 as 3-winding Transformer differential protection. And P-633 as Overall differential protection comprising Generator, Generator Transformer, and Auxiliary transformer

Does anyone have a document SLD for the bay Reactor? Please share with me..thanks
– If anyone has a REM615 backup file please share.
– Plz share anyone Modbus function codes

-Astrum. anyone has software for this converter
– Type rs232 to USB converter drivers. Micom (Areva) P121 software version is 6. H relay don’t connect with the relay
– Using Micom s1 studio and Micom s1agile
– I downloaded all data models still same error present
– Change the USB port of your laptop and try again
– Go to device manager on the laptop
– Check driver settings
– Assign as per p121 communication parameters
– Is your OS Windows 10? Then it will be working without a driver. To check whether it is working go to Device manager and see the listed Com ports.
– I downloaded the software now it’s working
– No 10
– Please share this relay terminals details.. 12 and 34 are NO/NC contacts
– 9 & 10 are current coil
– 1,2
– After coil operation. what is the status of NO contact
– 3&4 would normally be used for trip wiring as it has a trip isolator switch in series.. see the red tab on the grab handle of the relay.
– This particular model is a self-powered type. So terminals 5,6,7,8 are not used. Power is derived from CT terminals 9&10.

– Can anyone give settings for this transformer relay Areva P633?
– All that you need from this nameplate are
1. Trxm rating 20000kVA

  1. Voltage levels 66/11kV
  2. Vector group YNyno
  3. CT ratio if you are using the bushing CT?
    – no I want relay settings for Areva p633

    – Anyone has manuals for this temperature switch for the transformer
    – Please share any procedure to communicate with CSC 326 relay using CSPC software
    – Can anyone share a drive selection guide: I want to convert one dc motor drive to a VVF drive
    – Please share the Secure Premium 100-meter manual.
    – sir, Premier 100, please.
    – sorry, I don’t have premier 100 series manual
    – I need a Secure Prodigy meter manual. Can anyone share, please?
    – What is the standard followed for 132 kV cable ampacity calculation?. ( Installation method above ground).

– Anyone please share the Operating time formula for Normal. Inverse 1.3 seconds curve.
– this is for the Normal Inverse 3 seconds curve I think
– In the case of 1.3 inverse curve instead of 0.1414 take-ups 0.0613 value should be used.
– Does the Overcurrent Highset setting for the feeder depends on the Transformer capacity in the substation?
– Suppose bus fault current 12 KA, and no of connected 3, den 4ka per tr, 400O o/ c high set. Instantaneous
– You are very correct to preserve the transformer life span
– we have 132/33 kV and 220/33 kV substations with 33 kV Feeders…one of my friends told me Overcurrent Highset depends on Transformer capacity.
– how to decide on the highest pls tell me?
– The sum of all the feeder’s load must be equal to your transformer LV capacity. it depends on the load on each feeder. See bus fault current first u HV 2 calculate For both the cases then divided it by no. Of tr.
– Make it ur hv o/c high set
– Tr mva/ tr percentage impedance. Highest fault mva for ur transformer
– We also face difficulty with the password of this relay. YouTube videos did not help.

How can we reduce the tripping of the transformer due to inrush current?
– Transformer 10MVA,66/11KV
HV side CT ratio 125/1A
LV side CT ratio 800/1 A
Relay Micom P642
– Settings of harmonic
– If I’m not wrong, in modern transformers because of core material, the Inrush current harmonics are sometimes less than 20% of the fundamental frequency component due to which differential relay operates. So, we can keep the setting at 15%. For second harmonics we can keep this at 15%

– anyone knows passwords to change settings?
– 000000

– please tell me what is the general delay time used for Overcurrent or Earth Fault Highset protection?
-Depend on your coordination
– Zero
– 100msec
– To allow line zone 1 to clear fault first

Join 20 WhatsApp groups for protection engineers

  • WhatsApp Grp 01: Protection Relay – General
  • WhatsApp Grp 02: Substation Automation – General
  • WhatsApp Grp 03: Transmission line protection
  • WhatsApp Grp 04: Transformer protection
  • WhatsApp Grp 05: Motor protection
  • WhatsApp Grp 06: Generator protection
  • WhatsApp Grp 07: Overcurrent and Earth Fault Protection
  • WhatsApp Grp 08: Busbar protection and Bay controller
  • WhatsApp Grp 09: Breaker protection and control
  • WhatsApp Grp 10: Protection Relay Testing and commissioning
  • WhatsApp Grp 11: DIgSILENT
  • WhatsApp Grp 12: ETAP
  • WhatsApp Grp 13: PSCAD
  • WhatsApp Grp 14: IEC 61850 configuration
  • WhatsApp Grp 15: Switchgear GIS & AIS
  • WhatsApp Grp 16: GE Relay Configuration
  • WhatsApp Grp 17: SIEMENS Relay configuration
  • WhatsApp Grp 18: Schnider Relay configuration
  • WhatsApp Grp 19: SEL Relay Configuration
  • WhatsApp Grp 20: ABB Relion configuration or more services,

send a message to our WhatsApp support:

– hi, anyone has a ZIV RELAY course about programming its logical control, and interlocks? I need to understand completely but is not possible only to use the manual brand, located on their website.

-Anyone faces this problem while adding a relay to the IEC station in sip5?
– If anyone has Sepam relay thermal calculation sheet please share it with me.
– if CT gets saturated .what is the solution after CT gets saturated. We want to replace CT or any other solution
– CT secondary current flow to the secondary winding
– How are confirming that CT got saturated?
– Sir for knowledge purposes if CT gets saturated in future
If we observe these types of problems in the future, how can we overcome these types of problems?
– Which purpose bypass resistor is used in Modbus communication?
– What is the burden of your CTs?
– Saturation is purely a magnetic property issue. So there is no alternative solution to do corrections in the circuit rather than core replacement.
– You need not replace your CT there are ways to demagnetize the ct
– Can you explain in detail the theory of core saturation in ct
– How can we demagnetize the CT? We had followed demagnetization in transformer ..whenever we got erroneous values while testing dc winding resistance
– The easiest way to demagnetize a CT is to apply the test current at a level that approaches its excitation ‘knee’, then slowly decrease the input current to zero. This can be done with secondary excitation or primary current injection.
– I think some testers offer this option, Like omricon ct analyzer
– Can you explain why you need to replace your ct?
– What is the solution to these types of problem
– Anyone has a method Statement for how to create logic for Sepam Relay using SFT2841

our ETAP Video training course:


– we are getting the above error when communicating with RET650. Please tell us what could be the problem?
– Rollback package software needs to be updated using the Update manager of PCM600
– I could not find the Rollback package software. It’s in update manager, select relevant relay IED connectivity package. In that package, there is one rollup package that’s automatically installed.

– 33 kV ABB circuit breaker Trip coil and close coil have a PCB connected to them. Pls, tell me what is the use of that PCB?
– I think PCB is meant for capacitive tripping device CTD. CTD separate unit is present sir
– black color portion in the above image
– Check the drawing, While Exporting, Icd from Abb relay -PCM 600 the ICD file in Browser, showing TEMPLATE
– In scheme drawing of PCB…the electronic ckt PCB meant for coil protection purpose / to safeguard coil.
As the coil is designed for a short time not for continuous.
– what kind of protection is used, sir?
– what are the steps to be followed when synchronizing a new 220 kV Transmission Line to an existing 220 kV Bus?
– Anyone has a WINCC script for the addition of tags and displays on the HMI screen.
– This is a 220 kV ABB make LTB245E1 type circuit breaker. Please tell what is the use of S7-A circled in the above figure
– Did you look up S7 in legends?
– I think you could find working philosophy in the breaker manual
– It is mentioned Blocking switch but the function of it is not mentioned anywhere?
– For emf voltage discharge
– They are opposite
– I think they are for an anti-pumping system, isn’t it?
– Anti-pumping will come only in the Closing path. This is an AC motor (Spring charge) circuit I think.
– Spring charge also needs to be cut off, so I thought the Motor Cut off will be via Q1 contacts in series. S7 contact is, like AN said, for discharging stored EM energy in the motor winding.

– Anyone knows how to download cid file from Sepam relays and how to do goose configuration?
– Hello guys, please how do I program the LED of ABB REF615. My main challenge is to change the parameter setting from false to true.

– Hello colleagues, I have a question, in case there is a fault on the 33kv or 11 kV side is there any impact on 132kv side protection equipment? Mean did the protection will sense the fault?
– overcurrent relays on 33kv from TP, maybe send a trigger From application configuration
– Yes 132 side will sense the downstream faults but it will work as backup protection for downstream protection

– How to calculate phase sequence angle in cable
– Anyone pls explain how to set the power calculation for the reverse power relay…
-How to calculate the size of earthing cable for DCS or PLC?
– Please reply to this expert windows +R
2. type services. MSc and enter
3. right-click on SQL server (PCMSERVER) AND THEN START
– when do I start services?
– Reinstall the SQL server 2014
– Please can anyone help me with the primary impedance R1 + jx1/ km and R0 +jx0/km value of a Bear conductor ASCAR 250mm² with a diameter of 23.45mm
– Hello guys! Anyone working with GE Multilin D30? I have a relay that seems to be unconfigured on distance. Backup OC and EF are enabled but seems no contact is assigned for tripping though it shows indication during testing. 50/51, 50N/51N

– Power Swing Block is used and activated in Distance Relay to block its operation in case of Swing period disturbance
– It’s not about definition. I want ABC concerning enervista.
– Emanuel starts reading the D30 manual.
– What should be OLTC AVR relay PT Lower and raise voltage settings.

– Secure Premium 300 energy meter is showing like this in the parameters..please tell me what is its means?
– CT low means very fewer amps detected by ct
– What is the meaning of VT polarity?
-VT polarity means instant of increasing live terminal to positive is the same instant of increasing live terminal in secondary to positive in this case polarity is good and this secondary terminal is x1 and x2 is grounded. But if vice versa x2 become life and x1 is grounded For VT polarity Test the same ways of CT polarity Test
– Is it affect relay operation
– Of course, if this relay is Directional or Distance or Reverse power Relays and also if powering measuring device as kwh meter

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– What do we have to check if the transformer tripped in?
– DGA, Insulation, Ratio, Magnetic balance and Winding Resistance
– Hi guys, do you know where I could find a bibliography for protection for photovoltaic systems connected on the grid? I need to know a siemens V4 relay can work as a time source for Micom relays
– Magnetising current, Short circuit impedance tests of the transformer are also important to check for any deformation of windings. Turns ratio test and DC resistance test of winding.
– SFRA test is also one of the diagnostic tests but it’s not done in most the companies
– Do you mean the bandwidth (this determine when the tap shift up/down)?
– Yes

– Please tell the ‘distance’ below which ‘Line Differential Relay’ should be used for protection of 220 kV or 132 kV Transmission line?
– Line differential use mostly for underground cable not over a headline for e.g RED670 Abb line differential and OHL REL670 will be used
-In addition, RED670 can protect distance too
– sir, why is it that Differential is used for cable and not a line?
– Because with differential you are normally using fiber Optic, laying parallel with feeder. It is common to use line differential for underground cable and distance relays for overhead feeders
– Cant we have line diff if we have OPGW with the line?
– As much I know there is no distance length specified for Line differential relays. Line differential protection is also being used in overhead lines especially short lines and for high voltage lines that have redundant protection such as 400 kv
– Yes I think it is possible, the line can be used with opgw too, but I never face that actually in our system

– anyone has 2 phase transmission line with ‘line Differential protection’?
Line differential protection is being used for very short lines say less than 1 km. We are using it on 550 meters 220kv line.
– will anyone please the type of curve used by Indian railways for Overcurrent protection of the traction feeders?
– Very inverse characteristics
– why is it used and not Normal Inverse or Extremely Inverse?
– Main protection is overcurrent protection for railways. they adopt very inversely in the downstream network. so for relay coordination, we use the same curve

– Anyone knows how to configure goose signal at abb PCM software.pls share documents if u have
– How to check I/O Status in sepam80 relay
– In HMI, Or Software
– I have used this once before, now I am not getting it
– Once Relay is Connected with ur Lap, There is Spanner Symbol Available in Icons, Open it, Directly it will go to I/O Monitoring In HMI, Press Main Menu, U ll Get IO page Directly, Press Enter then Side Arrow for Next page
– Does the main menu mean this one?
– Press 13, then Options will come as I
– If I am using this protection output in logipam, then where I want to enable it and give settings
-For 50/51N_1_3, I enabled unit 1. Then where I have to give set. In groups A 3 or 1
– Anyone please share the Power Swing testing file for Omicron CMC356?
– Anyone has EMCO AVR relay service engineer contact no in india
– How to calculate transmission line loss from line length
– i^2 * (unit R/km*line length) will give for one

– Dears how to activate the help file “about” in digsi4 software
– Anybody has a manual for ETL 41 ABB PLCC equipment?
Kindly share.
– In EMCO AVR relay at the parallel of PT supply component used which is burnt is capacitor or resistor
– To test directional earth fault relay, voltage I’m giving is healthy and how much current to give and its the angle In earth, fault make voltage less in one phase
– Your test will fail because you inject a healthy phases voltage, that’s mean there is no zero-sequence voltage needed to operate the relay. You should simulate a real fault, if an earth fault happens to phase A the voltage of this phase will drop to a low value

– I’m trying to press the about button but the help doesn’t open the specific tab explain ‘ although I reinstall the device drivers
– Install the Device driver with help from the siemens site
– Already installed but it appears as a total manual in pdf, not an individual parameter
– Anyone has logic for soft on manual close command in p444 micom

Anybody having Pre-commissioning and Commission procedure or MOS for Substation Upgrade projects

– What is the Siprotec 5 Relay Password??
– 6 times 0
– Tried, not Working
– 222222

To join our protection relay WhatsApp group, please send interest on Whatsapp:

– I am facing a problem with the SFT2841 authorization code/registration.

-Register with ur mail ID, code link will come
– U can give any mail ID, and number. It will get registered.
– I got it registered. But still can not log into the Sepam, any ideas
– Do you use a USB to serial adapter or do you have a built-in serial port?
– What’s the relay model
– Is this cable fit for Front port communication?
– Yup

– Hello everyone I had a problem with the siemens Siprotec 7vk61 relay it is not measuring injected current and the relay is not showing measurements could anyone please help me out with this
– Relay showing measurements in

is there any Error led?
– No led
-Try to initialize the

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– MLFB file with the same version, Then configure as per your system Then check
– For what purpose was this relay used?
– Breaker Management
– Eg, like TIE bays
-Auto reclose
– AR for a tie, and all
– Inside the software, you checked the measurements?
– It is showing this on measurements
– Error in IED
– Yes also it is not showing in Digsi software
– Check the Control options in Relay

– Anyone having Areva P521 pilot wire Relay Technical Manual.

Need Areva, not Schneider.
– How to find the slope for low impedance REF in Sepam T81
– Please tell me What value of Contact Resistance is acceptable for 33 /132/220/400 kV Circuit breakers?
– ABB de 30 a 40 micro ohm
– The contact resistance value depends on the current of the circuit and not on the voltage.
– You should evaluate the manufacturer’s tests also evaluate the dissipated power in the resistance found. Then compare with the short circuit power of the circuit breaker
– If I install the 7sr100 RK all template then I got the 7sr100 r4h-1a. Is it’s crt?
U install Rk range

– H series will come In a minimum of all templates. the 7vk61 is not showing measurements do anyone have a solution for it?
– Anyone with guide notes for using sverker 780 relay tester On vamp relay?
– What is this infuse failure relay?
– Looks like selenium rectifier 3 phase. Also called a metal rectifier

can anyone help me with how to test overexcitation on the generator by CMC? V/f =1.2

– Voltage KV rating how much?
– 11kV
– There are two methods to check, one is increasing voltage and the second decreasing frequency method.

  1. Keep frequency constant and raise the voltage.

2. Keep voltage constant and decrease frequency. In both cases, plz continue to monitor the v/f meter on display.

– Do anyone has a solution for this relay it is not showing measurements
– Kindly check the logs once. I was assuming that there is a configuration issue. Because device healthy condition.
Apart from that, this is a sync relay so there is no ct connection and this window is for current measurement.
– Sorry not Sync it is auto recolse relay
– Trigger the check syn Input, Manual, or Give all measurements properly.
– What is the best method to find zero sequence impedance of line?
– U have to take it from the conductor manufacturer he provides you with R0 and X0 and you can calculate.
– Ct are connected

– How can I synchronize the relay time and date with the laptop time and date in Siprotec 5 Siemens relays
– How to check this curve 2 in Sepam m87 relay?

– anyone has ideas for loss off comm on SIEMENS 7SR1811? we checked the fiber comm is ok but the commlink still failed.
– How do you check fiber communication?
– by applying laser light end to end.

– when we read this error coming to any solution to read ABB Rec670
– Kindly provide auto reclose logic for ABB bcu. For one and a half scheme 400kv.
– There are two SEL relays for the same line prot. have different order numbers while one comm. the channel used for direct fiber and one used with media converter. Still found a comm. Fail can you help
– can I use PCM 600 for version 2.8 in the relay?
– Yes. But must have the connectivity package of the relay you are communicating.

To join our protection relay WhatsApp group, please send interest on Whatsapp:

– Does anyone know how to communicate Double F6150e with the F6300?
– Use the network for communication using pc.

– Can I change power disconnectors or isolator’s control in substations from working by classic control to working by PLC (programmable logic controller)?
– Same generators on parallel connection but one either not taking load or shedding of load at 50%. What can be the coz?

– Anyone knows the cable testing IEC formula for both ac and dc?
– We have a 7SJ62 Siemens relay protection. In the event log, the time and date have a question mark. The source protocol of our device is Ethernet NTP. Why do we have a question mark on the time and date of the event?
– Your device time is not Sync with GPS Clock

– Pls guide anyone on how to check the spring charge motor trip test using the B10E megger kit
– I need advice on protection on a 132kV transmission line to connect to a solar PV plant producing 92MW.
– This is the first generating plant like this proposed in the country.

– Does anyone know how to make logic equations in Areva P921?
– Exact solution for this?

– This problem is coming in Digsi while communicating via USB.
– In the taskbar, there is comtask32 close that first then close DIGSI and restart with run as administrator or restart the laptop
– Apart from this?
– Means I don’t know
– This happens whenever you disconnect the device in online mode. If this is happening only one or two times while communicating the device then you have to follow the same procedure as mentioned.
– However, if the same thing happens after doing this then you have to repair your DIGSI.
– DIGSI repair also tried the Same problem arising, Random at some periods Some Times.

– devices connected? After repairing
– Different devices only, Then try to connect in another project don’t connect on the same file,
– I’m, using DIGSI for a while.

– Randomly I have got this error, Once this error came almost all times same error repeat while communicating, Still, I could get the Proper solution for this, and also cause for this error, I have searched In DIGSI manual
But nothing was mentioned regarding Comtask32. All the minor checks – All seems okay
– Problem in Siprotec 4. I’m using software 4.93
– then you have to reinstall your windows as well DIGSI.
– I’ve faced this issue in different laptops / different os too.

– How could we check trip log and event log in IED Scout in siemens Siprotech Relays
– What is the type of this FO port, please?
– LC/SC/ST like this?
– LC
– these two, please?
– LC
– SC
– The above relay has FO LC-type rear ethernet port and its protocol is IEC60870-5-103. Will it support time synchronization with SANDS make GPS?
– Abb rec670 relay restarting again after double point status included. Does anyone know how to solve this restarting issue please send me a message
– This change is in the 61850?
– No just changed binary input status
– What will be the default password for GE L90?
– It is showing local access denied while changing settings from HMI. I am getting this error when I send application configuration to the relay REF 615
– I can able to read but am not able to write what will be the reason!? please anyone who knows how to solve this issue message me.
– Can someone help me to configure this relay ABB REF 541?
– Breaker feeding primary of 6.6/.415 kv transformer is tripping on earth fault during inrush
– 6.6kv is grounded through 50 Amps NGR
– 51n is set at 10 amps idmt at 200 Msec
– 50n is set at 20amps dt at 50 msec

– Please guide for the 68 settings in ABB ref 615 relay
– It’s tripping on Earth fault Highest function?
– Earth fault’s highest setting may be less. We keep it as 8-10 times of idmt setting. For example, if CT is 600/1A, then earth fault highest function is kept at 2A(10 times of 0.2A)
– anyone having a thermal overload calculation sheet for the transformer kindly shares
– Transformer testing

– Please tell me What is the use of the rings in the above Voltage Transformer?
– Any sip5 engineer who knows to change the phase current name for DR?
– Hi everyone I am facing this problem for ABB615. Whenever I gave the read from IED that time showed this error.. – — How can I solve those errors and read relay files from the relay?

-Anyone pls send me the ABB REF615 Relay version 5.0.13 relay connectivity package
– Use and update manager or go to their website
– The updated manager has no option for searching
– Kindly update the license by right click on the relay and using the license updation tool.
– Please, can anyone help. CB always trips back after single-phase Auto reclose. The PD is the 60s
– Kindly make it clear?
– After the relay give AR command to the CB it will close and trip back immediately and after that, the CB will trip other phases on PD. I’m doing commissioning the line, not charge
– Here shows option 5.0.1. But I need 5.0.13. how can I download the package
– Did you check for any trip signal presented to the single-pole trip relays?
– Yes. The feedback is on the relay to test set.
– Breaker should be in a close position for AR
– In the open condition, AR should block
– It was in a close position and I trip the CB with the relay on 21Z1 Ph-G fault. Then CB open and the relay send a reclose command

– Did you check the outputs which are getting high on single-phase trips?
– I have checked it very well because the test kit shows the duration of the trip. About 0.038s
– No other outputs are getting high?
– Yes
– Disable TOR function and then check
– TOR?
– Trip on reclose function which is there in every numerical relay
– Disable this function and then check the auto reclose
– Correct CB state must be provided for the AR relay/21 for AR to work. As I understand AR will work if the CB is open, not when it is closed, along with other interlock conditions.
– The problem is that the CB is reclosing and tripping back immediately, Which means some trip signal is tripping it. it’s not the ar logic which is at fault.
– You need to remove the particular phase’s trip input to the single-phase trip relay and then try a reclosing function test.
– If it works, you are going to find out which relay keeps issuing the trip positive to the 1 phase trip relay.
– If you reclose the CB from the AR function of the relay, the CB close and remains. If there is a high output it should not stay
– That’s the logic.
– The problem happens only when I trip the CB from Close to open and back to close?
– You can check also a timer on CB for pole discrepancy. sometimes you need to delay more for reclosing test.
– That s a basic check. make sure that the dead time is not more than the reclaim time & PD time. Even though as per your description it’s not what trips the CB on reclosing.
– Adjust the timer on CB after that reclose successfully signal to come.
– If it’s a new CB, after conducting the CB closing timing test, set the deadtime above the closing time of CB too.
– it’s a new CB
– Normally, the closing time is 100msec and the dead time is set as 1sec. Remove other 2 phases trip relays and then apply single-phase fault with one trip relay. Check if AR works
– Keep one trip relay in circuit with other trip relays drawn out
– Suppose you apply Red phase fault, keep the red phase trip relay in the circuit
– If others are there it will trip the CB on 3Ph
– That’s what we are doing
– you apply Red phase to the earth fault using the testing kit and keep Red phase trip relay in the circuit
– Have you checked that Breaker is closing on Single phase fault AR and then tripping? If others are active the relay will show TrpA, TrpB, and TrpC
– it’s closing on ar, but again tripping on single-phase trip relay, And later due to PD timer, remaining phases trip too
– You said that it’s again tripping on the Trip relay. Check the Auxiliary contact 52A of the circuit breaker which is in series with the trip coil. This contact can malfunction. This contact is meant to break the DC circuit of the Trip relay
– If the trip relay remains in the energized state it can again trip the breaker

Join 20 WhatsApp groups for protection engineers

20 WhatsApp Groups for protection engineers

  • WhatsApp Grp 01: Protection Relay – General
  • WhatsApp Grp 02: Substation Automation – General
  • WhatsApp Grp 03: Transmission line protection
  • WhatsApp Grp 04: Transformer protection
  • WhatsApp Grp 05: Motor protection
  • WhatsApp Grp 06: Generator protection
  • WhatsApp Grp 07: Overcurrent and Earth Fault Protection
  • WhatsApp Grp 08: Busbar protection and Bay controller
  • WhatsApp Grp 09: Breaker protection and control
  • WhatsApp Grp 10: Protection Relay Testing and commissioning
  • WhatsApp Grp 11: DIgSILENT
  • WhatsApp Grp 12: ETAP
  • WhatsApp Grp 13: PSCAD
  • WhatsApp Grp 14: IEC 61850 configuration
  • WhatsApp Grp 15: Switchgear GIS & AIS
  • WhatsApp Grp 16: GE Relay Configuration
  • WhatsApp Grp 17: SIEMENS Relay configuration
  • WhatsApp Grp 18: Schnider Relay configuration
  • WhatsApp Grp 19: SEL Relay Configuration
  • WhatsApp Grp 20: ABB Relion configuration or more services,
  • send a message to our WhatsApp:

– Electric duct heater 240 volts, 3500 w what are meggar valves
– This would not lead to a successful Autorecloser.
– If the CB aux switch s faulty and a trip signal persists, the TC will get burned out.
– Yes, the trip coil can burn
– But I don’t find any other reason. I think they need to check trip coil resistance too,
– As the coil has not burned, it’s not the CB aux switch that s causing the issue.
– Can we extract fault waveform, I mean one more thing needs to be checked: the testing kit needs to stop injecting fault after the first trip, is it being ensured.
– Correct! And if the kit feedback point of the trip is correct.
– Yes I confirmed it. It shows 0.038s
– If you remove feedback the test kit continues
– Check the Programming logic of the relay, maybe Autoreclose digital output signal may have been connected to the trip output contact of Relay
– Check the PSL or configuration of the Distance relay. I have only a three-phase supply without neutral, in my system newly 1 phase loads are being added. how can I provide neutral wire to these loads, without implementing any Trafo (Delta-Wye)?

– Hi guys. How Can I reset these ledes?
-Reset, then reset indication LEDs, Check the BB switch if it’s on or off.
– I did it but it doesn’t work.
– Where can I find BB switch?
– On the same panel
– This is the Sepam Relay s configuration,

– Why we are using () In not gate function. is it mandatory to use the set brackets?
– Not Required
– If u Want to Invert an Input, U Can use it NOT directly. So set brackets Were not important, right?

– What is the meaning of this error code, please? p343
– This error code means that analog input module serial E2ROM Failure.
– We advise replacing analog input modules through an authorized repair center.

– Anyone knows how to trigger DR in sip 4 either online or manually?
– Open relay online and go to test then double click on test waveform, DR will be triggered.

– HMI in LabView with IEC 61850 (MMS) Communication
-It’s just a simulation or HILT (LOOP IN TESTING)?
– First I configure the SEL 751 in QuickSet software, then I use the SEL Architect software for IEC 61850 configuration, in the end, I use the RELAB OPC SERVER software to read the reports I created and the software transforms them into OPC signals and the LabView can read that data in real-time. You can also use Kepserverx to transform MMS or GOOSE data to OPC
– Value under switch on condition means in case of differential

– I have good knowledge of digsi4 but no knowledge of digsi5 software. Anyone has any guidelines to access digsi5. I need to see how the signal is configured for SAS OR GOOSING.
– Actually in 5 no need to assign any signal for IEC all are pre-configured
– In the file, there is the option of IEC structure on that, you can see

– Anybody Simulating signals from IED SCOUT?
– This block “MVGAPC1” is used for SAS in the REF615, but I don’t need it to appear on the events

– can anybody tell me the difference between short-term overcurrent trips and long-term overcurrent trips?
-What is the password of SEL 551?
– Sometimes the password for FTP might be FTPUSER too. If you have quickset settings, you will get the information in it

To join our protection relay WhatsApp group, please send interest on WhatsApp:

-Does anyone face time inaccuracy in OMICRON CMC256 only if trip time < 1-second?

-What are you testing?
-Phase Overcurrent.

– What are you using? Quick CMC, state sequence, or auto?

– We use a 125V DC system for our substations. The string consists of 93 NiCad cells. The charger is SENS. The only settings available on the charger are FLOAT, set at 1.37VpC 122V, and EQUALIZE, set at 1.57Vpc 138V. These values appear to be assuming the string consists of 88 cells.

– Should I just adjust the FLOAT to 130V?
-I don’t see any way to set the number of cells in the string.
-How separate furreol in canon mk2600 printer?
-Anyone worked on Micom 546 relay. Line differential relay? I am facing one problem that the tx of differential communication getting on-off frequently in back relay tx is getting
on-off, or in your mux, In HMI of relay
– Value is getting 1 and 0.
– maybe you can check in measurement 4 in display relay, same or not with tx on HMI.
– What is the password of this relay SR-489?

-The factory default passcode is zero (0)

– Also, you can try state sequence.

– just an update Was able to find in the setting where there is the number of cells for the string but was not allowed to change the value which was found to be 93.
– we Will try to contact the manufacturer to address this.

– What’s the difference between WCDM11 type relay and WCD type? Both are reverse power protection relays but can we interchange them?
– how do I install DIGSI 4 in windows 8 or windows 10?
-Hi the above relay SIEMENS show the error LED and monitor SMS.

– can you help me to solve this issue? Busbar relay 7ss52?

– Actually, it falls back in monitor mode, go down there will be one option of reset. do that.

-Yes. Otherwise, nothing will show in time

-hi, could anyone shares PDF standard library “IEC 60255-6 ELECTRICAL RELAYS -PART6:MEASURING RELAYS AND PROTECTION EQUIPMENT”?

– Does anyone have a manual for this relay or how to read the settings for this relay?
– Which relay?
– Micom p444
– Once switch off auxiliary supply And switch on

– I have a question about inrush on the Transmission line:

– Is it inrush current created during energizing of under-ground transmission line? On voltage levels of 132kV and 6.5KM
– No, inrush current produces during charging of transformer.
– Anyone has Rio file for field failure and pole slip?
What is the default password of this Siemens Relay?

– 000000

To join our protection relay WhatsApp group, please send interest on WhatsApp:

– Why u need To communicate and see Fault Recorder
– I think It can be used HMI only And Modbus communication ports only available
– Ok. That is also ok. I can use that only as long as I have the respective firmware.

– Guys anyone has this book?! Can anyone upload it?
– Transformer Inspection and Testing (Electrical Power Plant Maintenance Book 1) pdf

– Hello anyone works this type of MDB?
– This is not MDB. looks likes the control panel.
– Sir Are you working on this panel?
– Looks like if SC and Rtu panel
– Please send a link goes to download TDMS software for DRTS 64 testing kit

– Hi does anyone have MComp suite software of L& t relays?

To join our protection relay WhatsApp group, please send interest on WhatsApp:

Our completed Courses:

contact us to get this impressive IEC61850 collection

  • IEC 61850 Precision Time Protocol IEEE 1588
  • IEC 61850 PRP Redundancy
  • IEC 61850 Quality of Service
  • IEC 61850 Redundancy Protocols
  • IEC 61850 Substation Architecture
  • IEC 61850 Substation Design Considerations
  • IEC 61850 Time Synchronization
  • IEEE 1588 – Master, Slave, and Transparent Clocks
  • IEEE 1588 Synchronization Basics
  • Important Properties of PTP
  • Integrating Serial and IP Ethernet
  • Introduction to IEEE 1588 Precision Time Protocol
  • Network Management System Deployment Scenarios
  • Network Management System Security
  • Network Security- The Defense in Depth Model
  • NMS User Guide- Device Discovery
  • NMS User Guide- Permissions and Users
  • NMS User Guide- Statistics
  • NMS User Guide- Views and Alarms
  • Product Overview – RAPTOREye
  • PTP Profiles
  • PTP Timing Requirements in Power Systems
  • Securing a Switch and Functional Architecture
  • Security Standards and the NERC CIP Framework
  • Serial IP Conversion Use Case
  • Switch Hardening_ Local Password and Access Authentication
  • Switch Hardening- Finalizing the Security Configuration
  • Switch Hardening- Secure Management and Configuration
  • The Best Master Clock Algorithm
  • The Gap Between Legacy Serial and Ethernet
  • The Network Management System FCAPS Model
  • Time Transfer Technology Comparison
  • Virtual Serial Port Redirection
  • What is a Network Management System (NMS)
  • Name Size Date Modified
  • Best Practice – Securing SNMP
  • Best Practice_ Securing Management Protocols
  • Best Practice- Enabling Remote Logging
  • Best Practice- Time Sync, Disable Services, and Port Security
  • Converting Serial to IP
  • Core Redundancy and OSPF
  • Defense in Depth Model
  • Device Hardening- Best Practice Basics
  • Device Level Security and Switch Functional Architecture
  • Digital Substations- An Introduction to IEC 61850
  • Ethernet Network Overview
  • Gateway Redundancy – VRRP
  • How does a VLAN work
  • How PTP IEEE 1588 v2 Works
  • HSR-PRP Redundancy
  • IEC 61850 Communication Protocols
  • IEC 61850 HSR Redundancy
  • Interior Routing Protocol
  • Layer 2 and Redundancy
  • Layer 3 Concepts – Routing
  • MAC and IP Addressing Format
  • Managed vs Unmanaged Switch and Router
  • Migration from Serial to Ethernet
  • Redundancy Architecture from Substation to Control Center
  • Redundant Network Timing Requirements
  • Routing Functions and The Routing Table
  • Static Routing vs. Dynamic Routing
  • STP and RSTP Redundancy
  • The Physical Layer
  • VLAN Basics
  • VLANs (IEEE 802.1Q)
  • VLANs and Redundancy
  • VLANs, Routing, and Cybersecurity
  • What Is a Switch
  • What is a VLAN
  • What is Ethernet
  • Bridging the Gap Ethernet, Serial, and Legacy Equipment in Substations
  • Digital Substation Communications – What you Need to Know About IEC61850 Network Design
  • Educational Training Introduction_ Networking 101 For OT Professionals
  • IEC61850 Overview Video
  • It’s about Time – Intro to IEEE 1588 and Precision Time Protocol
  • Keeping an Eye Out_ Understanding Network Management Utilization
  • Network Hardening, NERC CIP and the Smart Grid
  • Network Redundancy- What Are Your Options- Why Choose One Technology over Another
  • Networking 101 for OT Professionals_ Ethernet and its Application in Critical Utility Networks
  • Networking 101 For OT Professionals- Making Sense of the Layers. Benefits of Layer 2 and Layer 3
  • Switch Hardening Best Practices- How to Secure Your Industrial Network
  • VLAN Fundamentals and Its Benefit in Network Design for Mission Critical Applications
  • Name Size Date Modified
  • Alex Apostolov about the past, present and the future of relay protection
  • Christoph Brunner about origins of IEC 61850 and its future developments — Big Energy.
  • IoT for Utility and Industrial Power Grids- Where Is the value-
  • Route to IEC 61850 (2016)- The Concept of IEC 61850
  • Route to IEC 61850- Engineering IEC 61850 systems
  • Route to IEC 61850- HMI and Station Control
  • Route to IEC 61850- Testing IEC 61850 Systems
  • Route to IEC 61850- The Concept of IEC 61850
  • Route to IEC 61850- Time Synchronization for IEC 61850
  • The Future of Industrial Automation Video – GE Intelligent Platforms
  • Welcome to the Digital Substation World I Episode 01
  • ABB Goose config
  • Cara Create ICD_SCD File (IEC61850 Protocol) dari Relay Reyrolle Argus 7SR
  • Fiber Optic and Data Transferring between Substations and OTDR
  • GE course
  • GE DCS
  • GE Geese confgi procedure
  • Hands on Protection Testing using IEC 61850
  • How to configure IEC 61850 with Easergy Studio
  • How to enable Virtual Machine on Latest Windows Host Operating System
  • How to generate the IEC 61850 MMS GOOSE Protocol traffic using SCL files with IEDScout
  • How to perform the compare and find difference between the SCL files
  • How to save the SCL file from IEDScout
  • How to setup OpenSCD to be used in offline
  • How to subscribe the GOOSE messages from third-party relays to ABB make relays in PCM600
  • How to use IEDScout in offline and the benefits behind
  • How to use IEDScout in offline to practic
  • IEC 61850 implementation-related documentation for IEDs and Tools
  • IEC 61850 Overview Part 9 SCL Files
  • IEC 61850 programming training
  • iec61850.
  • ied scout
  • Introduction and contents overview
  • Introduction to packet sniffing and basics of communication protocols
  • Making right connections to start sniffing in switched environment
  • Start capturing with Wireshark and manage its basic settings
  • Using Filters
  • Working with packets
  • Working with capture files
  • Digital substation traffic capture analysis
  • Practical demonstration
  • IEDScout on MBX1 IEC 61850 IED Simulation with Positive use cases
  • ieee1588
  • OMICRON Customer Portal Overview
  • Route to IEC 61850 (2016)- The Concept of IEC 61850
  • SEL Goose config
  • SETR850 schnider
  • Simulating an IED from IEDScout PC with 102 port-occupied services
  • StationScout offline benefits-Part-1
  • STRATON IEC61850
  • Trick Rahasia Edit CID File IEC61850 untuk Integrasi SIPROTEC5 PACIS Alstom
  • Using IEC 61850 to Solve Protective Relaying Challenges (2011).mp4 292 M
  • ABB webinar
  • Awareness of IEC 61850 communication standard – Preface and tutors introduction
  • digsi 4 iec61850 config
  • digsi4 report
  • easergy pro
  • ethernet
  • How does Modbus Communication Protocol Work
  • IEC 61850 Data Modeling Part 2 – Triangle MicroWorks Inc
  • IEC 61850 in the Modern Substation
  • IEC 61850 Standard for T&D Grids
  • iec 61850 webinar omicron
  • IEC 61850
  • IEC_61850_Simply_usable_mit_closing.
  • iot – 38 – Lecture 3.3 Packet Capture Demo
  • Mensajes GOOSE en IEC61850 de Siemens
  • omicron goose
  • omicron products
  • omicron SV
  • Relational Database Concepts
  • sip5 iec61850
  • triangle
  • Practical IEC 61850 for Substation Automation for Engineers and Technicians
  • Video Session 2- Practical IEC 61850 for Substation Automation for Engineers and Technicians
  • Video Session 3- Practical IEC 61850 for Substation Automation for Engine
  • What is OSI Model
  • What is the IEC 61850 protocol- How does it work- What’s the difference with other protocols
  • SIPROTEC 5 certificate automation – using Enrollment over Secure Transport protocol
  • Webinar SIPROTEC 5 certificate Secure Transport EST protocol
  • Expert Talk – Overview of SICAM A8000, SIAPP & Web HMI
  • Global Summit 2022 Digital switchgears for intelligent secondary distribution grid automation
  • Global Summit 2022 Behind the scenes– Self optimized grid to the largest onshore fish farm in Norway
  • Global Summit 2022 Conference Digital switchgear solutions for primary distribution
  • Global Summit 2022 Conference Precisely tailored substation automation with SICAM A8000
  • Global Summit 2022 Keynote Innovative technologies in electrification & automation for our future
  • Global Summit 2022 Mastering distribution grid diversification by IoT SIPROTEC5
  • Global Summit 2022 SICAM A8000 beyond the typical substation automation–New apps for the Etransition
  • Global Summit 2022 Training How to write your own application for SICAM A8000 with SIAPP
  • Migration of SICAM TOOLBOX II configuration
  • SICAM Earth Fault Indicator – SICAM EFI Introduction Animation (FR)
  • SICAM Earth Fault Indicator – SICAM EFI Introduction Animation
  • Automation and remote terminal units SICAM A8000 RTU SIPROTEC-5 SIEMENS
  • Sicam Application CP8050 Automation and remote terminal units A8000 RTU SIPROTE

Learning is a continuous process and enables us to be competitive in our field.

In this package, you get Trained DIGSI 4 and DIGSI 5 to work with SIPROTEC 4 & 5, how to work with Etap software, and how to use IEC 61850 for integration and communication between different equipment brands.

Product detail:

IEC 61850 training package (4 hrs – 1.5 GB)
SIPROTEC 4 and DIGSI 5 training package (7 hrs – 1.8 GB)
SIPROTEC 4 and DIGSI 4 Training package ( 3hrs – 830 MB)
ETAP for protection engineers (5.5 hrs)
  • DIGSI 5 Training: 435 Minutes – Full HD Size ( 1.9 GB), In English, By Dr. Saeed Roostaee
  • DIGSI 4 Video Training: 185 Minutes, In English, By Dr. Saeed Roostaee
  • IEC 61850 configuration Video Training: 4 hrs Language, In English, By Dr. Saeed Roostaee
  • ETAP Video Training: 5.5 hrs, In English

61850 certificate links:

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Part 1: Substation Automation – an overview
Part 2: An introduction to IEC 61850 & how to learn it effectively
Part 3: Overview of the main features of IEC 61850 – Part I
Part 4: Overview of the main features of IEC 61850 – Part II
Part 5: IEC 61850 data structure and data format – Part I
Part 6: IEC 61850 data structure and data format – Part II
Part 7: IEC 61850 station in DIGSI 5 and IEC 61850 System Configurator
Part 8: GOOSE configuration and the publisher/subscriber LNs
Part 9: GOOSE simulation via IEDScout
Part 10: GOOSE configuration and simulation between SIP 5 & SEL relays
Part 11: Time synchronization settings and SNTP configuration
Part 12: Case study – Part I
Part 13: Case study – Part II
Part 14: Case study – Part III
Part 15: IEC 61850 configuration in DIGSI 4
Part 16: IEC 61850 configuration between SIP 4 & SIP 5
Part 17: Sample project

IEC 61850 training package

Demos & DETAILS:

IEC 61850 training package

  • Total length: 246 Minutes (4 hours)
  • Trainer: Dr. Saeed Roostaee
  • Language: English
  • Download:

The UCA is implementing changes to the IEC 61850 certification testing program to follow IEC requirements that only one revision of a standard can be valid at one time. Edition 1 was officially withdrawn by the IEC in December 2012 when Edition 2 became the current revision of the IEC 61850 standard. The UCA has therefore decided to phase out the issuing of Edition 1 only certificate and transition to Edition 2 conformance test certificates. The new Edition 2 conformance tests will include an option for certifying backward compatibility for Edition 1. This will allow new test certificates to cover both Edition 1 and 2 as required by utilities that install new equipment into existing Edition 1 systems or mixed systems (containing Ed. 1 and 2 devices).        
The end-of-life date for Edition 1 conformance testing and certification is targeted for December 31, 2020. However, the actual date may change depending on when updates to Edition 2 conformance tests are published with procedures for testing Edition 1 backward compatibility. Please read the official press release from the UCA for many more details

Announcement of End-of-Life for IEC 61850 Edition 1 Certification 

The IEC 61850 testing groups, within the UCA IUG, have concluded that the UCA IUG must enforce testing by the IEC position that there is one valid revision of a standard at any given time. Testing to a withdrawn standard is not consistent with the IEC position and would lead to supporting testing and certification of Edition 1, Edition 2, Edition 3, etc. 
Simultaneously long into the future. In the review of the current IEC 61850 QAP Addendum, it has become clear that this was never the intent. Furthermore, the testing groups recognize that an abrupt and immediate transition of testing from one version to another would be very disruptive to all impacted parties. The current IEC 61850 QAP Addendum is lacking adequate guidance for the process of updating the conformance testing procedures in synchronization with the standard. Therefore, to ensure a timely transition to new versions of standards while supporting a stable and growing market for IEC 61850 devices and applications the IEC 61850
QAP Addendum is being updated to define a migration path for how testing procedures are synchronized to new versions of the standards as follows: 

  • A guaranteed minimum period from the publication of a major revision of the IEC 61850 standard. Since the IEC process for releases is a 5-year interval, the current proposal is that conformance testing of a specific major release of 61850 should be guaranteed to be no less than 10 years. It is thought that this guidance allows utility stability for project planning. 
  • Upon the publication of a new release, which causes the withdrawal of the previous IEC standard, the conformance test procedures will need to be updated to not only test the conformance to the new standard but also backward compatibility to the previous standard and thereby provide utilities the assurance that new devices can be integrated into older systems protecting utility investment. 
  • Once the revised test procedures are available, and the 10-year minimum has been achieved, the UCA Conformance Testing for the older standard would cease
  • Conformance certificates shall indicate if the certificate is being issued based on withdrawn standards.

Edition 1 Conformance Testing is currently outside of these criteria being proposed because the withdrawal date of Edition 1 of the standard was December 2012 and the publication date of Edition 1 was May 2005. The end-of-life for UCA Edition 1 Only Conformance Testing andCertification is targeted for December 31, 2020, and would still require that the backward.  
compatibility testing is available thereafter.   

This announcement is being provided so that the information needed for utility project planning and to protect utility investment in deployments is based upon older versions of the standard. What is being proposed does not mean that older versions of devices would not be available, only that newer versions would be conformance tested to the current version and for compatibility with the older version. 

More about IEC 61850

Reference: (

IEC 61850 library for Engineers  

{.pdf}615 series ANSI IEC 61850 Engineering Guide.
{.pdf}650 series IEC 61850 Communication Protocol Manual.
{.pdf}650 series IEC 61850 Communication Protocol Manual.
{.pdf}670 series 2.0 IEC IEC 61850 Edition 1 Communication Protocol Manual.
{.pdf}670 series 2.0 IEC IEC 61850 Edition 2 Communication Protocol Manual.
{.pdf}2013 IEC 61850 INTEROPERABILITY TEST Munich, Germany.
{.pdf}61850 easy.
{.pdf}ABB AFS660 Switch High-availability Ethernet device based on new IEC-standard redundancy protocols PRP/HSR.
{.pdf}ABB AFS660 Switch High-availability Ethernet device based on new IEC-standard redundancy protocols PRP/HSR.
{.pdf}ABB is implementing the first commercial installation of IEC 61850-9-2 LE process-bus technology.
{.pdf}ABB review Special Report IEC 61850.
{.pdf}Advanced protection and control IEDs from ABB.
{.pdf}AGILE DIGITAL SUBSTATIONS The complete guide.
{.pdf}Analysis and implementation of the IEC 61850 standard.
{.pdf}Application Considerations of IEC 61850/UCA 2 for Substation Ethernet Local Area Network Communication for Protection and Control.
{.pdf}Applications of IEC 61850 Standard to Protection Schemes.
{.pdf}Applications of Phasor Measurement Units.
{.pdf}Applications of PMU measurements in the Belgian electrical grid.
{.pdf}The Application-View Model of the International Standard IEC 61850.
{.pdf}Approach to optimized process Bus architectures.
{.pdf}Approach to optimized process Bus architectures.
{.pdf}Automation at Protection Speeds: IEC 61850 GOOSE Messaging as a Reliable, High-Speed Alternative to Serial Communications.
{.pdf}The Building Blocks of a Data-Aware Transport Network: Deploying Viable Ethernet and Virtual Wire Services via Multiservice ADMs.
{.pdf}Calibration System for Electronic Instrument Transformers With Digital Output.
{.pdf}Challenges and Integration of PV and Wind Energy Facilities from a Smart Grid Point of View.
{.pdf}Challenges and Lessons Learned from Commissioning an IEC 61850-90-5 Based Synchrophasor System.
{.pdf}Colombian electrical sector adopting high redundancy communication design on a new HV substation



⦁ Communication in Power application.

⦁ Communication Protocols and Networks for Power Systems- Current Status and Future Trends.

⦁ Communications network solutions for smart grids.

⦁ The concept of IEC 61850.

⦁ CT Standard.

⦁ D2-01_07_Meeting requirements in an IEC 61850 station bus SAS.

⦁ Data transport network.

⦁ Dealing with Packet Delay Variation in IEEE 1588 Synchronization Using a Sample-Mode Filter.

⦁ Design and Implementation of Packet Analyzer for IEC 61850 Communication Networks in Smart Grid.

⦁ Design and Performance Testing of a Multivendor IEC61850–9-2 Process Bus Based Protection Scheme.

⦁ Design, Development, and Commissioning of a Supervisory Control and Data Acquisition (SCADA) Laboratory for Research and Training.


⦁ Developing Real-Time PMU Applications for Smart Transmission Grids.

⦁ Development of IEC61850 Based Substation Engineering Tools with IEC61850 Schema Library.

⦁ Differential Protection RET 54_/Diff6T function Application and Setting Guide.

⦁ Digital umspannwerk.

⦁ Digitalization in Transmission and Distribution.

⦁ Direct Evaluation of IEC 61850-9-2 Process Bus Network Performance.

⦁ Distributed busbar protection REB500 including line and transformer protection Product Guide.

⦁ Distributed Multifunction Fault Recorder.

⦁ A Distributed PMU for Electrical Substations With Wireless Redundant Process Bus.

⦁ Duplicate and Circulating Frames Discard Methods for PRP and HSR (IEC62439-3).

⦁ Dynamic Testing of an IEC 61850 Based 110 kV Smart Substation Solution.

⦁ EC 61850 for Substations.

⦁ ECT Evaluation by an Error Measurement System According to IEC 60044-8 and 61850-9-2.

⦁ Efficient Energy Automation with the IEC 61850 Standard Application Examples Energy Automation.

⦁ Emerging Applications of Synchronous Ethernet in Telecommunication Networks.

⦁ Enabling digital substations.

⦁ Energy Management of Internet Data Centers in Smart Grid.

⦁ Engineering Perspective

on IEC 61850. ⦁ Enhanced Engineering process SCL example. ⦁ Enhanced Engineering process SCL Files. ⦁ ERL 61850 IED Configurator. ⦁ ERL 61850 IED Configurator. ⦁ Ethernet & IEC 61850 Concepts, Implementation, Commissioning. ⦁ Ethernet in SAS. ⦁ Ethernet in SAS. ⦁ Ethernet in Substation Automation Applications – Issues and Requirements. ⦁ Ethernet Module EN100 for IEC 61850 with electrical/optical 100 MBit Interface Application Examples. ⦁ Ethernet Networks Redundancy With Focus On IEC 61850 Applications. ⦁ ETHERNET NETWORKS REDUNDANCY WITH FOCUS ON IEC 61850 APPLICATIONS. ⦁ Ethernet-Based Public Communication Services: Challenge and Opportunity. ⦁ Evaluation of IEC 61850-9-2 Samples Loss on Total Vector Error of an Estimated Phasor. ⦁ The Evaluation of Phasor Measurement Units and Their Dynamic Behavior Analysis. ⦁ Evaluation of Time Gateways for Synchronization of Substation Automation Systems. ⦁ Executive Summary (Introduction to MMS. ⦁ Feeder Protection and Control REF615 Application Manual. ⦁ Focus on the application – IEC 61850 experience with the third-party system configuration tool. ⦁ Generic IEC61850 IED Connectivity Package User‘s Guide. ⦁ Get on the digital bus to SA. ⦁ GOOSE AIR. ⦁ GOOSE Configuration Example. ⦁ Goose messages for automated testing: 765 kV transmission network. ⦁ Goose Messaging Determining its potential in a real case. ⦁ GOOSE IEC 61850 Test System. ⦁ GPS and IEEE 1588 synchronization for the measurement of synchrophasors in electric power systems. ⦁ Grid Automation REC615 and RER615 IEC 61850 Engineering Guide. ⦁ HardFiber. ⦁ Hidden Challenges in the Implementation of 61850 in Larger Substation Automation Projects. ⦁ IEC60076. ⦁ iec61850-8-1{ed1.0}en-2004. ⦁ IEC61850 Based Process Bus Protection Solution for Remote Located Power Transformers. ⦁ IEC61850 Modeling for Switch Management. ⦁ IEC 60870-5-101/104 Slave Technical. ⦁ IEC 60870-5-103 Communication Protocol Manual. ⦁ IEC 61400-25-2. ⦁ IEC 61850-3 and IEEE 1588. ⦁ IEC 61850-7-420 IEC 61850 Part 7-420 DER Logical Nodes. ⦁ IEC 61850-9-2 Based Process Bus. ⦁ IEC 61850-9-2 Process Bus and Its Impact on Power System Protection and Control Reliability. ⦁ IEC 61850-9-2 Process Bus Communication Interface for Light Weight Merging Unit Testing Environment. ⦁ IEC 61850 – Communication networks and systems in substations. ⦁ IEC 61850 – More Than Just GOOSE: A Case Study of Modernizing Substations in Namibia. ⦁ IEC 61850  Process Bus – It is Real!. ⦁ IEC 61850: COMMUNICATION NETWORKS AND SYSTEMS IN SUBSTATIONS. ⦁ IEC 61850 and Measurements. ⦁ IEC 61850 -Communication Networks and Systems in Substations:

An Overview of Computer Science.

⦁ IEC 61850 driver FAQ.

⦁ IEC 61850 Enabled Automatic Bus Transfer Scheme for Primary Distribution Substations.

⦁ IEC 61850 General.

⦁ IEC 61850 GOOSE and IEEE C37.118 Synchrophasors Used for Wide-Area Monitoring and Control, SPS, RAS, and Load and Generation Management.

⦁ IEC 61850 Goose applications to distribution protection schemes.

⦁ IEC 61850 Goose applications to distribution protection schemes.

⦁ IEC 61850 MMS Client Driver Help.

⦁ IEC 61850 Model Expansion Toward Distributed Fault Localization, Isolation, and Supply Restoration.

⦁ IEC 61850 Process Bus – It is Real!.


⦁ IEC 61850 Protocol API User Manual.

⦁ IEC 61850 Qualifications.

⦁ IEC 61850 standard for SA.

⦁ The IEC 61850 standard for SA.

⦁ IEC 61850 standard for SA.

⦁ IEC 61850 Substation Configuration Language and Its Impact on the Engineering of Distribution Substation Systems.

⦁ IEC 61850 System Configurator.

⦁ IEC 61850 System Configurator.

⦁ IEC 61850 Technical Overview.

⦁ IEC 61850/61400 Model Designer.

⦁ IEC 61850: Role of Conformance Testing in Successful Integration.


⦁ IEC 61850-Based Feeder Terminal Unit Modeling and Mapping to IEC 60870-5-104.

⦁ IEC 61850-Based Information Model and Configuration Description of Communication Network in Substation Automation.

⦁ IEC 62357: TC57 Architecture Part 1: Reference Architecture for Power System Information Exchange.

⦁ IEC 62439 PRP: Bumpless Recovery for Highly Available, Hard Real-Time Industrial Networks.

⦁ IEC Smart Grid Standardization Roadmap.

⦁ IED Configuration Guidelines.

⦁ IEEE-1588 Standard for a Precision Clock Synchronization Protocol for Networked Measurement and Control Systems.

⦁ IEEE 802.1AS and IEEE 1588.

⦁ IEEE 802.3ba 40 and100 Gigabit Ethernet Architecture.

⦁ IEEE 1547.2 IEEE Application Guide for IEEE Std 1547™, IEEE Standard for Interconnecting Distributed Resources with Electric Power Systems.

⦁ IEEE 1547.3 IEEE Guide for Monitoring, Information Exchange, and Control of Distributed Resources Interconnected with Electric Power Systems.

⦁ IEEE 1547.4 IEEE Guide for Design, Operation, and Integration of Distributed Resource Island Systems with Electric Power Systems.

⦁ IEEE 1547.6 IEEE Recommended Practice for Interconnecting Distributed Resources with Electric Power Systems Distribution Secondary Networks.

⦁ IEEE 1588.

⦁ IEEE 1588 Precision Time Protocol Time Synchronization Performance.

⦁ IEEE 1588 Precision Time Synchronization Solution for Electric Utilities.

⦁ IEEE 1588 Version 2.

⦁ IEEE 1615 IEEE Recommended Practice for Network Communication in Electric Power Substations.

⦁ IEEE Application Guide for IEEE Std 1547™, IEEE Standard for Interconnecting Distributed Resources with Electric Power Systems.”

{.pdf}IEEE c37.118.1 IEEE Standard for Synchrophasor Measurements for Power Systems.
{.pdf}IEEE c37.118.2 2011 IEEE Standard for Synchrophasor Data Transfer for Power Systems.
{.pdf}IEEE Recommended Practice for Network Communication in Electric Power Substations.
{.pdf}IEEE Standard for a Precision Clock Synchronization Protocol for Networked Measurement and Control Systems.
{.pdf}IEEE Standard for Electric Power Systems Communications— Distributed Network Protocol (DNP3).
{.pdf}IEEE Standard for Ethernet.
{.pdf}IEEE Standard for Ethernet.
{.pdf}IEEE Standard for Ethernet Amendment 1: Physical Layer Specifications and Management Parameters for Extended Ethernet Passive Optical Networks.
{.pdf}IEEE Standard for Information technology— Telecommunications and information exchange between systems Local and metropolitan area networks— Specific requirements Part 17: Resilient packet ring (RPR) access method and physical layer specifications.
{.pdf}IEEE Standard for Service Interoperability in Ethernet Passive Optical Networks (SIEPON).
{.pdf}IEEE Standard for Synchrophasor Data Transfer for Power Systems.
{.pdf}IEEE Standard for Synchrophasor Measurements for Power Systems.
{.pdf}IEEE Standard Profile for Use of IEEE 1588™ Precision Time Protocol in Power System Applications.
{.pdf}IEEE Std 802.1.
{.pdf}Impact of IEC 61850-9-2 Standard-Based Process Bus on the Operating Performance of Protection IEDS: Comparative Study.
{.pdf}An Implementation of FTTH based Home Gateway Supporting Various Services.
{.pdf}Implementing New Generation Protective Relay Schemes based on IEC61850 Standard for Substation Communication in the Eskom 765kV Transmission Network.
{.pdf}Implementing Vehicle-to-Grid (V2G) Technology With IEC 61850-7-420.
{.pdf}Industrial & Plant Communication.
{.pdf}Industrial automation systems Manufacturing Message Specification.
{.pdf}Industrial Communication.
{.pdf}Installation and commissioning manual Line distance protection IED REL 670.
{.pdf}The Integrated Energy and Communication Systems Architecture.
{.pdf}Integration of a New Standard.
{.pdf}Integration of IEC 61850 GSE and Sampled Value Services to Reduce Substation Wiring.
{.pdf}Integration of IEC 61850 GSE and Sampled Value Services to Reduce Substation Wiring.
{.pdf}Interoperability and Performance Analysis of IEC61850 Based Substation Protection System.
{.pdf}Interoperability Requirements for IEC 61850 System Configuration Tools.
{.pdf}Introduction and Overview of IEC 61850 Configuration and Diagnostics.
{.pdf}IP and Ethernet Communication Technologies and Topologies for IED networks.
{.pdf}Issues and Approaches on Extending Ethernet Beyond LANs.
{.pdf}Kalki SCL Manager.
{.pdf}Laboratory Investigation of IEC 61850-9-2-Based Busbar and Distance Relaying With Corrective Measure for Sampled Value Loss/Delay.
{.pdf}Large Scale Grid Integration of Renewable Energy Sources – Way Forward.
{.pdf}Leading the way to Digital Substations.
{.pdf}Lecture 5a Substation Automation Systems.
{.pdf}Logical nodes.
{.pdf}Magnum 6KL Managed Edge Switch.
{.pdf}Memory Requirements Analysis for PRP and HSR Hardware Implementations on FPGAs.
{.pdf}MiCOM Px4x-92LE Technical Manual IEC 61850-9-2LE Interface.
{.pdf}MiCOM Px4x-92LE Technical Manual IEC 61850-9-2LE Interface.
{.pdf}Model Implementation Conformance Statement (MICS) for IEC 61850 for the SEL Real-Time Automation Controllers.
{.pdf}Model Implementation Conformance Statement for the IEC 61850 interface in SEL-351A.
{.pdf}Model Implementation Conformance Statement for the IEC 61850 interface in SEL-351S.
{.pdf}Model Implementation Conformance Statement for the IEC 61850 interface in SEL-2411.
{.pdf}Model Implementation Conformance Statement for the IEC 61850 interface in SEL-2440.
{.pdf}Modeling and (Co-)simulation of power systems, controls, and components for analyzing complex energy systems.
{.pdf}Modeling and Simulation for Performance Evaluation of IEC61850-Based Substation Communication Systems.
{.pdf}The move to IEC61850  what and when will it be delivered?.
{.pdf}MU320 Merging Unit.
{.pdf}MU Agile AMU Technical Manual Analogue Merging Unit.
{.pdf}Network Interactions and Performance of a Multifunction IEC 61850 Process Bus.
{.pdf}A network scheme for process bus in smart substations without using external synchronization.
{.pdf}A New IED With PMU Functionalities For Electrical Substations.
{.pdf}Next-generation substations.
{.pdf}Non-conventional instrument transformers Advanced GIS substations with IEC 61850-9-2 LE process bus.
{.pdf}A Novel Communication Network for Three-Level Wide Area Protection System.
{.pdf}Object Modeling of Data and DataSets in the International Standard IEC 61850.
{.pdf}Offprint of an article published in PAC World, Fall 2008 Standard IEC 61850 – Network Redundancy using IEC 62439.
{.pdf}On the Use of IEEE 1588 in Existing IEC 61850-Based SASs: Current Behavior and Future Challenges.
{.pdf}One-Way Delay and PTP (IEEE 1588v2) Test Applications.
{.pdf}Optimal Integration of Disparate C37.118 PMUs in Wide-Area PSS With Electromagnetic Transients.
{.pdf}Overview of IEC 61850.
{.pdf}Overview of IEC 61850.
{.pdf}Packet Tracer Network Simulator.
{.pdf}The Parallel Redundancy Protocol for Industrial IP Networks.
{.pdf}Performance Analysis of IEC 61850 Sampled Value Process Bus Networks.
{.pdf}Performance assessment of an IEC 61850-9-2 based protection scheme for the mesh corner of a 400kV transmission substation.
{.pdf}Performance Evaluation of Time-critical Communication Networks for Smart Grids based on IEC 61850.
{.pdf}Performance of IEC 61850-9-2 Process Bus and Corrective Measure for Digital Relaying.
{.pdf}Phasor measurement based on IEC 61850-9-2 and Kalman–Filtering.
{.pdf}Plan Ahead for Substation Automation.
{.pdf}Plc-based SA and SCADA.
{.pdf}Plug-in rapid-wire integrated.
{.pdf}A PMU for the Measurement of Synchronized Harmonic Phasors in Three-Phase Distribution Networks.
{.pdf}The PMU Interface using IEC 61850.
{.pdf}PMU Interoperability, Steady-State, and Dynamic Performance Tests.
{.pdf}PMU-based Voltage Instability Detection through Linear Regression.
{.pdf}Power network telecommunication PowerLink – power line carrier system.
{.pdf}Power network telecommunication PowerLink – technical data.
{.pdf}Power network telecommunication SWT 3000 Teleprotection.
{.pdf}The power of IEC 61850.
{.pdf}The power of IEC 61850.
{.pdf}Power Systems Communications.
{.pdf}a practical application primer for protection engineers.
{.pdf}Practical Applications of Ethernet in Substations and Industrial Facilities.
{.pdf}Practical Considerations for Ethernet Networking Within Substations.
{.pdf}Practical Experience with IEEE 1588 High Precision Time Synchronization in Electrical Substation based on IEC 61850 Process Bus.
{.pdf}Precision Clock Synchronization.
{.pdf}Precision Time Protocol.
{.pdf}Protection and Control System Upgrade Based on IEC- 61850 and PRP.
{.pdf}Protocol Implementation Conformance Statement (PICS) for IEC 61850 for the SEL Real-Time Automation Controllers.
{.pdf}PRP and HSR for High Availability Networks in Power Utility Automation: A Method for Redundant Frames Discarding.
{.pdf}PRP and HSR Version 1 (IEC 62439-3 Ed.2), Improvements, and a Prototype Implementation.
{.pdf}The Real-Time Publisher/Subscriber Communication Model for Distributed Substation Systems.
{.pdf}Reason RT411 Technical Manual Time Signal Distributor.
{.pdf}Redundancy in Substation LANs with the Rapid Spanning Tree Protocol (IEEE 802.1w).
{.pdf}Reliable data networks for electric power systems.
{.pdf}Requirements for Ethernet Networks in Substation Automation.
{.pdf}Resilience technologies in Ethernet.
{.pdf}SA Hand Book.
{.pdf}SAM600 process bus.
{.pdf}The SAM600 process bus IO system integrates conventional instrument transformers into modern, IEC 61850-9-2


⦁ process bus substation automation, protection, and control systems.

{.pdf}Sampled Values.
{.pdf}SAS Application pictures.
{.pdf}SCADA and IP.
{.pdf}SCADA Systems: Challenges for Forensic Investigators.
{.pdf}Seamless redundancy.
{.pdf}Selecting, Designing, and Installing Modern Data Networks in Electrical Substations.
{.pdf}Selection Guide / Ethernet Switches.
{.pdf}Sepam Ethernet Guide.
{.pdf}Sepam IEC 61850 communication.
{.pdf}SICAM A8000 Serie CP-8000 Master Modul mit I/O.
{.pdf}SICAM A8000 Series.
{.pdf}SICAM A8000 Series  Wherever energy flows Protection Technology / Substation Automation / Power Quality and Measurements.
{.pdf}SICAM A8000 Series CP-8000, CP-8021, CP-8022 User Manual.
{.pdf}SICAM A8000 Series Operation, telecontrol, and automation in the smallest spaces.
{.pdf}Simulation and testing of the over-current protection system based on IEC 61850 Process-Buses and dynamic estimator.
{.pdf}Simulation of Parallel Redundant WLAN with OPNET.
{.pdf}SINEAX CAM Parameterization of IEC61850 bus card.
{.pdf}SIPROTEC 4, SIPROTEC easy, SIPROTEC 600 Series, Communication, Accessories.
{.pdf}SIPROTEC 5 Communication protocol IEC 60870-5-103.
{.pdf}SIPROTEC 5 Communication Protocol IEC 60870-5-104.
{.pdf}SIPROTEC 5 Communication protocol IEC 61850.
{.pdf}SIPROTEC 5 Modbus.
{.pdf}SIPROTEC 5 Process Bus.
{.pdf}SIPROTEC 5Communication protocol DNP3.
{.pdf}SIPROTEC 7SC805.
{.pdf}SIPROTECMerging Unit 6MU805 V4.01 Manual.
{.pdf}smart grids.
{.pdf}The Smart Substatiion usiing IIEC 61850 Ediitiion 2.
{.pdf}Solutions for Digital Substation.
{.pdf}Stand Alone Merging Unit User Guide MGU010000.
{.pdf}A Study on GOOSE Communication based on lEC61850 using MMS Ease Lite.
{.pdf}Substation Automation Process Bus.
{.pdf}Substation Automation Systems.
{.pdf}A Survey of Communication Network Paradigms for Substation Automation.
{.pdf}A Survey of Ethernet LAN Security.
{.pdf}Switchgear Optimization Using IEC 61850-9-2 and Non-Conventional Measurements.
{.pdf}Synchronized Phasor Measurements and Their Applications.
{.pdf}Synchrophasor Standards Development – IEEE C37.118 & IEC 61850.
{.pdf}System 800xA IEC 61850 Connect Configuration.
{.pdf}System 800xA IEC 61850 Engineering Workflow.
{.pdf}System Engineer Configures IEC 61850 Gateway to DNP3 Substation.
{.pdf}System-Level Tests of Transformer Differential Protection Using an IEC 61850 Process Bus.
{.pdf}TCP/IP Protocol Suite.
{.pdf}Technical Requirements for DER Integration Architectures.
{.pdf}Teleprotection over an IP/MPLS Network.
{.pdf}Testing a SIPROTEC GOOSE bus protection scheme using an OMICRON CMC.
{.pdf}Time Signal Distributor.
{.pdf}Time Signal Distributor.
{.pdf}Time Synchronization (IEEE 1588) and Seamless Communication Redundancy (IEC 62439-3) Techniques for Smart Grid Substations.
{.pdf}Time Synchronized Low-Voltage Measurements for Smart Grids.
{.pdf}Towards Implementation of IEC 61850 GOOSE Messaging in Event-Driven IEC 61499 Environment.
{.pdf}Traffic Generation of IEC 61850 Sampled Values.
{.pdf}Transforming Critical Communications Networks for Substation Automation Communications network infrastructure requirements and architectures.
{.pdf}Two Improvements Related to Overcurrent Functions for Bus Protection in Distribution Systems.
{.pdf}Use of IEEE 1588–2008 for a Sampled Value Process Bus in Transmission Substations.
{.pdf}Use of Precision Time Protocol to Synchronize Sampled-Value Process Buses.
{.pdf}User Experiences Implementing IEC61850 in Intelligent Electronic Devices.
{.pdf}A user-friendly implementation of IEC 61850 in a new generation of protection and control devices.
{.pdf}Using OPNET to Model and Evaluate the MU Performance Based on IEC 61850-9-2LE.
{.pdf}Utilization of GOOSE in MV Substation.
{.pdf}Utilizing IEC 61850, Ethernet, and IP Standards for Integrated Substation Communications.
{.pdf}VAMP RELAYS IEC 61850 interface Configuration instructions.
{.pdf}The Virginia Tech Calibration System.
{.pdf}Virtual Power Plant for Grid Services using IEC 61850.
{.pdf}VSE 006 IEC 61850 interface module.
{.pdf}VSE 006 IEC 61850 interface module Configuration instructions.
{.pdf}A Web-Based Remote Access Laboratory Using SCADA.
{.pdf}What Is IEC 61850?.
{.pdf}What Protection Engineers Need to Know About Networking.
{.pdf}White Paper on Standards for DER Communications Using IEC 61850.
{.pdf}Wide area voltage protection.
{.pdf}Wide-Area Ethernet Network Configuration for System Protection Messaging.
{.pdf}Wide-Area Ethernet Network Configuration for System Protection Messaging.
{.pdf}Wide-Area Protection and Power System Utilization.
{.pdf}(2003). “Communication networks and systems in substations – Part 1: Introduction and overview.”
{.pdf}(2003). “Communication networks and systems in substations – Part 2: Glossary.”
{.pdf}(2003). “Communication networks and systems in substations – Part 3: General requirements.”
{.pdf}(2003). “Communication networks and systems in substations – Part 4: System and project management.”
{.pdf}(2003). “Communication networks and systems in substations – Part 5: Communication requirements for functions and device models.”
{.pdf}(2003). “COMMUNICATION NETWORKS AND SYSTEMS IN SUBSTATIONS Part 10: Conformance Testing.”
{.pdf}(2003). “IEEE Standard Test Method for Use in the Evaluation of Message Communications Between Intelligent Electronic Devices in an Integrated Substation Protection, Control, and Data Acquisition System.”
{.pdf}(2005). “Communication networks and systems in substations – Part 7-3: Basic communication structure for substation and feeder equipment – Common data classes.”
{.pdf}(2005). “Communication networks and systems in substations – Part 7-4: Basic communication structure for substation and feeder equipment – Compatible logical node classes and data classes.”
{.pdf}(2005). “Communication networks and systems in substations – Part 9-1: Specific Communication Service
{.pdf}Mapping (SCSM) – Sampled values over a serial unidirectional multidrop point to point link.”
{.pdf}(2007). “Communication networks and systems in substations – Part 7-1: Basic communication structure for substation and feeder equipment – Principles and models.”
{.pdf}(2009). “Communication networks and systems for power utility automation – Part 7-420: Basic communication structure – Distributed energy resources logical nodes.”
{.pdf}(2010). “Communication networks and systems for power utility automation – Part 7-2: Basic information and communication structure – Abstract communication service interface (ACSI).”
{.pdf}(2010). “Communication networks and systems for power utility automation – Part 90-1: Use of IEC 61850 for the communication between substations.”
{.pdf}(2011). “Communication networks and systems for power utility automation – Part 8-1: Specific communication  service mapping (SCSM) – Mappings to MMS (ISO 9506-1 and ISO 9506-2) and ISO/IEC 8802-3.”
{.pdf}(2011). “Communication networks and systems for power utility automation – Part 9-2: Specific communication service mapping (SCSM) – Sampled values over ISO/IEC 8802-3.”
{.pdf}(2012). “Communication networks and systems for power utility automation – Part 6: Configuration description language for communication in electrical substations related to IEDs.”
{.pdf}(2012). “Communication networks and systems for power utility automation – Part 90-5: Use of IEC 61850 to transmit synchrophasor information according to IEEE C37.118.”
{.pdf}(2013). “Communication networks and systems for power utility automation – Part 90-7: Object models for power converters in distributed energy resources (DER) systems.”
{.pdf}(2013). “IEEE c37.242 IEEE Guide for Synchronization, Calibration, Testing, and Installation of Phasor Measurement Units (PMUs) for Power System Protection and Control.”
{.pdf}(2014). “IEEE Recommended Practice for Network Communication in Electric Power Substations.”
{.pdf}on an electric power substation, Internet protocol (IP) networks are provided. For the power
{.pdf}engineer new to IP networking, this document provides an introduction to the concepts that need
{.pdf}to be mastered as well as specific recommendations to follow when deploying the technologies.
{.pdf}For equipment manufacturers and system integrators, it provides direction and requirements to
{.pdf}facilitate interoperable electric utility information networks
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{.pdf}Antonova, G., et al. (2011). Communication redundancy for substation automation. Protective Relay Engineers, 2011 64th Annual Conference for.
{.pdf}Apostolov, A., et al. (2006). A Distributed Recording System Based on IEC 61850 Process Bus. Power Systems Conference: Advanced Metering, Protection, Control, Communication, and Distributed Resources, 2006. PS ’06.
{.pdf}Apostolov, A. and B. Vandiver (2011). IEC 61850 GOOSE applications to distribution protection schemes. Protective Relay Engineers, 2011 64th Annual Conference for.
{.pdf}Astarloa, A., et al. (2013). System-on-Chip implementation of Reliable Ethernet Networks nodes. Industrial Electronics Society, IECON 2013 – 39th Annual Conference of the IEEE.
{.pdf}Atienza, E. (2010). Testing and troubleshooting IEC 61850 GOOSE-based control and protection schemes. Protective Relay Engineers, 2010 63rd Annual Conference for.
{.pdf}Bhardwaj, V., et al. (2014). A review of various standards for the digital substation. Green Computing Communication and Electrical Engineering (ICGCCEE), 2014 International Conference on.
{.pdf}Bonfiglio, A., et al. (2013). The smart microgrid pilot project of the University of Genoa: Power and communication architectures. AEIT Annual Conference, 2013.
{.pdf}Castello, P., et al. (2014). Improving the availability of distributed PMU in electrical substations using wireless redundant process bus. Instrumentation and Measurement Technology Conference (I2MTC) Proceedings, 2014 IEEE International.
{.pdf}Chao, Z., et al. (2009). An integrated PMU and protection scheme for power systems. Universities Power Engineering Conference (UPEC), 2009 Proceedings of the 44th International.
{.pdf}Dan, Z., et al. (2010). A new scheme of control and protection based on utilizing phasor measurement technique. Control and Decision Conference (CCDC), 2010 Chinese.
{.pdf}Darby, A. B., et al. (2014). Experience using PRP Ethernet redundancy for Substation Automation Systems. Developments in Power System Protection (DPSP 2014), 12th IET International Conference on.
{.pdf}Das, N., et al. (2013). Process-to-bay level peer-to-peer network delay in IEC 61850 substation communication systems. Power Engineering Conference (AUPEC), 2013 Australasian Universities.
{.pdf}De Dominicis, C. M., et al. (2010). Experimental evaluation of synchronization solutions for substation automation systems. Instrumentation and Measurement Technology Conference (I2MTC), 2010 IEEE.
{.pdf}Dolezilek, D. (2010). Case Study Examples of Interoperable Ethernet Communications within Distribution, Transmission, and Wide-Area Control Systems. Communications Workshops (ICC), 2010 IEEE International Conference on.
{.pdf}Dutra, C. A., et al. (2014). Process bus reliability analysis. Developments in Power System Protection (DPSP 2014), 12th IET International Conference on.
{.pdf}Feuerhahn, S., et al. (2011). Comparison of the communication protocols DLMS/COSEM, SML, and IEC 61850 for smart metering applications. Smart Grid Communications (SmartGridComm), 2011 IEEE International Conference on.
{.pdf}Gajic, Z., et al. (2010). Using IEC 61850 analog goose messages for OLTC control of parallel transformers. Developments in Power System Protection (DPSP 2010). Managing the Change, 10th IET International Conference on.
{.pdf}GE “Communiicatiion Protocolls.”
{.pdf}Georg, H., et al. (2013). Performance evaluation of time-critical communication networks for Smart Grids based on IEC 61850. Computer Communications Workshops (INFOCOM WKSHPS), 2013 IEEE Conference on.
{.pdf}Gonzalez-Redondo, M. J., et al. (2013). IEC 61850 GOOSE transfer time measurement in the development stage. Industrial Electronics (ISIE), 2013 IEEE International Symposium on.
{.pdf}Hakala-Ranta, A., et al. (2009). Utilizing possibilities of IEC 61850 and goose. Electricity Distribution – Part 1, 2009. CIRED 2009. 20th International Conference and Exhibition on.
{.pdf}Hoga, C. (2011). Seamless communication redundancy of IEC 62439. Advanced Power System Automation and Protection (APAP), 2011 International Conference on.
{.pdf}Huu-Dung, N., et al. (2014). An improved High-availability Seamless Redundancy (HSR) for dependable Substation Automation System. Advanced Communication Technology (ICACT), 2014 16th International Conference on.
{.pdf}Hyo-Sik, Y., et al. (2007). Communication Networks for Interoperability and Reliable Service in Substation Automation System. Software Engineering Research, Management & Applications, 2007. SERA 2007. 5th ACIS International Conference on.
{.pdf}Ingram, D. M. E., et al. (2011). Multicast traffic filtering for sampled value process bus networks. IECON 2011 – 37th Annual Conference on IEEE Industrial Electronics Society.
{.pdf}Ingram, D. M. E., et al. (2012). “Use of Precision Time Protocol to Synchronize Sampled-Value Process Buses.” Instrumentation and Measurement, IEEE Transactions on 61(5): 1173-1180.
{.pdf}Ingram, D. M. E., et al. (2013). “Network Interactions and Performance of a Multifunction IEC 61850 Process Bus.” Industrial Electronics, IEEE Transactions on 60(12): 5933-5942.
{.pdf}Janssen, M. C., et al. (2011). Bringing IEC 61850 and Smart Grid together. Innovative Smart Grid Technologies (ISGT Europe), 2011 2nd IEEE PES International Conference and Exhibition on.
{.pdf}Khan, R. H., et al. (2013). Pilot protection schemes over a multi-service WiMAX network in the smart grid. Communications Workshops (ICC), 2013 IEEE International Conference on.
{.pdf}Kirrmann, H., et al. (2011). Seamless and low-cost redundancy for substation automation systems (high availability seamless redundancy, HSR). Power and Energy Society General Meeting, 2011 IEEE.
{.pdf}Martin, K. E., et al. (2014). “An Overview of the IEEE Standard C37.118.2&#x2014; Synchrophasor Data Transfer for Power Systems.” Smart Grid, IEEE Transactions on 5(4): 1980-1984.
{.pdf}Mekkanen, M., et al. (2013). Reliability evaluation and comparison for next-generation substation function based on IEC 61850 using Monte Carlo simulation. Communications, Signal Processing, and their Applications (ICCSPA), 2013 1st International Conference on.
{.pdf}Mekkanen, M., et al. (2014). Analysis and methodology for measuring the IEC61850 GOOSE messages latency: Gaining interoperability testing. Computer Applications and Information Systems (WCCAIS), 2014 World Congress on.
{.pdf}Mo, J., et al. (2010). Evaluation of process bus reliability. Developments in Power System Protection (DPSP 2010). Managing the Change, 10th IET International Conference on.
{.pdf}Ouellette, D. S., et al. (2010). Using a real-time digital simulator to affect the quality of IEC 61850 GOOSE and sampled value data. Developments in Power System Protection (DPSP 2010). Managing the Change, 10th IET International Conference on.
{.pdf}Parikh, P., et al. (2013). Fault location, isolation, and service restoration (FLISR) technique using IEC 61850 GOOSE. Power and Energy Society General Meeting (PES), 2013 IEEE.
{.pdf}Ptaszynski, M., and P. Wronek (2014). Mikronika’s new solutions for power substations with the process of bus technology. Signals and Electronic Systems (ICSES), 2014 International Conference on.
{.pdf}Ransom, D. L., and C. Chelmecki (2014). “Using GOOSE Messages in a Main&#x2013; Tie&#x2013; Main Scheme.” Industry Applications, IEEE Transactions on 50(1): 17-24.
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{.pdf}Seung-Ho, Y., et al. (2012). Performance analysis of IEC 61850 based substation. Advanced Communication Technology (ICACT), 2012 14th International Conference on.
{.pdf}Sichwart, N., et al. (2013). Transformer Load Taps Changer control using IEC 61850 GOOSE messaging. Power and Energy Society General Meeting (PES), 2013 IEEE.
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{.pdf}Sidhu, T. S., et al. (2010). Packet scheduling of GOOSE messages in IEC 61850 based substation intelligent electronic devices (IEDs). Power and Energy Society General Meeting, 2010 IEEE.
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Learning is a continuous process and enables us to be competitive in the area of Substation Automation and Protection relay. Consistent with this belief and built on a strong experience in this field, we offer various services and education products such as video training packages, software training, remote technical support, providing relay settings and test sheets, remote relay testing, Online training, and training at the site. Browse our website – if there are any requests or ideas, then please contact us.

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