Center for Learning

Course Catalog

 

The Beckwith Electric Center for Learning offers a variety of classroom seminars covering diverse and complex subjects relating to the electric power field, ranging from industry theory to product specific applications and operation. Seminar instructors are professionals from Beckwith Electric and recognized experts within the electric power industry.

The Beckwith Electric Center for Learning offers the following topics to help you find the educational programs of most interest and value for you. A Center for Learning Catalog is also available to download in PDF format.

 

Generator Protection

5 Hours
CEUs: .5 (5 PDHs)

Generators are subject to internal faults, external faults and abnormal operating conditions impressed by turbine and excitation system issues, as well as power system events the generator has no control over but must cope with. False (nuisance) trips are costly as the generator’s output is lost. Inability to trip due to lack of sensitivity, lack of certain protections or deficiencies in protection application may cause severe damage to generators, resulting in prolonged outage and revenue loss, plus increased system stability risk. Achieving the ideal balance of secure and dependable protection involves use of an array of elements that protect the generator for all operating modes: off-line, start up, synchronizing, various levels of power output and when challenged by system faults and anomalies.

  • Generator construction and operation
  • Grounding and connections
  • IEEE standards for generator protection
    • C37. 102, Guide for Synchronous generator Protection
  • Generator and power system interaction
  • Generator protection element overview
    • Internal faults (in the generator zone)
    • Abnormal operating conditions
    • External faults
  • Protection Application Exploration
    • Stator Ground Fault (27TN, 59N, 59D, 64S, 67N, 87GD)
      • Exploration of stator ground fault injection protection sensitivity and security
    • Rotor Ground Fault/Brush Lift Off (64F, 64S)
    • Stator Phase Fault (87G)
    • Turn-to-Turn Fault
    • Phase Unbalance/Open Conductor (46)
    • Overexcitation (24)
    • Abnormal Voltage (59)
    • Phase Fault Backup (21)
    • Field Loss (40)
    • Loss of Synchronism (78)
    • Abnormal Frequency (81-U, 81A)
    • Inadvertent Energizing (50/27)
    • Blown VT Fuses (60FL)
    • Breaker Failure/Pole Flashover (50BF)
    • Loss of Prime Mover (32)
  • Tripping considerations and sequential tripping
  • Discuss tactics to improve reliability (security & dependability)
  • Generator protection upgrade considerations
    • Lessons learned from NE Blackout (2003)
    • Redundancy concepts
  • Explore Setting, Commissioning and Event Investigation Tools

Who Should Attend
This course will benefit power plant protection engineers and technicians, as well as power plant operators and protection generalists who desire a deeper background on the subject.

Generator Protection Calculations & Settings

6 Hours
CEUs: .6 (6 PDHs)

Building on the base knowledge covered in Generator Protection Fundamentals, calculations for protective elements are developed. Depending on the element, these calculations use nameplate data, system data or a combination of the two. Margin considerations are explored and impacts on element reliability are discussed, as well as element interdependencies with protection and control in the generator zone, local power plant and system.

  • 59N – Neutral Overvoltage
  • 27TN – Third Harmonic Neutral Undervoltage
  • 3Vo – Neutral Bus Overvoltage
  • 46 – Negative Sequence Overcurrent
  • 87 – Phase Differential current
  • 24 – Volts/Hz/Overexcitation
  • 50/27 – Inadvertent Energizing
  • 51V – Inverse Time Phase Overcurrent
  • 21 – Phase Distance
  • 50BF – Breaker Failure
  • 32 – Directional Power
  • 27 – Phase Undervoltage
  • 59 – Phase Overvoltage
  • 81 – Over/Under Frequency
  • 60FL – VT Fuse-Loss Detection
  • 40 – Loss of Field
  • 78 – Out of Step
  • Isync Trip

Who Should Attend
Engineers responsible for developing and/or checking generator protection settings. Testing Technicians who want to obtain a greater understanding of generator protective element testing, especially for impedance-based elements.

Transformer Protection

4 Hours
CEUs: .4 (4 PDHs)

Transformers are subject to internal faults, the effects of external faults and abnormal operating conditions impressed by the power system events the transformer has no control over but must cope with. False (nuisance) trips are costly as the transformer and load are disconnected. Inability to trip due to lack of sensitivity, lack of certain protections or deficiencies in protection application may cause severe damage to transformers, negatively impacting power flows, impacting power quality and compromising stability. Achieving the ideal balance of secure and dependable protection involves use of an array of elements that protect the transformer from prolonged internal faults, excessive through faults and when challenged by power system faults and anomalies.

  • Why transformers fail
    • The cost of failures
  • IEEE C37.91, Guide for Power Transformer Protection
    • IEEE Devices used in Transformer Protection
    • Transformer Protection Review
    • Transformer Protection Functions
  • Explore Protection Functions
    • 87T Phase Differential Characteristic
      • Compensation in Digital Relays
      • Relay Configuration: Winding Arrangement and CT Connection
  • Overcurrent based (50, 51, 50N, 51N, 46)
  • Through fault protection (TFM)
    • Current Summing & Through-Fault
  • Overexcitation (24)
    • Generating plant causes
    • T&D system causes
    • Protection Against Overexcitation – V/Hz versus 5th Harmonic
  • Phase Differential (87T)
    • Unique Issues Applying to Transformer Differential Protection
      • CT performance issues (saturation, remnant flux, tolerance, rating)
      • Percentage differential characteristics with variable percentage slopes
      • Internal ground fault sensitivity
      • Restraints for inrush and overexcitation
        • Overexcitation 87T Blocking Restraint – Failure to detect nascent fault
        • Overexcitation Adaptive 87T Pickup Restraint – Detects nascent faults
    • Adaptive restraint for security
    • Point-on-Wave Switching Inrush
    • Cross Phase Averaging
    • Switch-onto-Fault
  • High Set Phase Differential (87H)
  • Ground Differential (87GD), Restricted Earth Fault (REF)
  • Interface and Analysis Software: Desirable Attributes
    • NERC “State of Reliability”
  • Elegant Simplicity – Realization of configuration, settings, logic, monitoring
  • Trany Shop – Test and Commissioning

Who Should Attend
This course will benefit transmission, distribution and power plant protection engineers and technicians, as well as operations personnel and protection generalists who desire a deeper background on the subject.

Transformer Protection Calculations & Settings

1 Hour
CEUs: .1 (1 PDHs)

Building on the base knowledge covered in Transformer Protection Fundamentals, calculations for protective elements are developed. Depending on the element, these calculations use nameplate data, system data or a combination of the two. Margin considerations are explored and impacts on element reliability are discussed, as well as element interdependencies with protection and control in the transformer zone, whether in generation, transmission or distribution.

  • Examine CT performance
  • Calculate winding “tap” values
  • Determine 87T pickup points
    • Determine variable percentage slope breakpoints
    • Determine harmonic restraint values
  • Determine 87H pick up
  • Determine 87GD pick up
  • Determine pick up and time delay settings for 50/51 through fault protection

Who Should Attend
Engineers responsible for developing and/or checking transformer protection settings. Testing Technicians who want to obtain a greater understanding of transformer protective element testing, especially for impedance-based elements.

Fault Fundamentals

2 Hours
CEUs: .2 (2 PDHs)

  • Fault Types
  • Short-Circuit Calculations
  • Calculations and Settings

Who Should Attend
This course will benefit transmission, distribution and power plant protection engineers and technicians, as well as operations personnel protection generalists who desire a deeper background on the subject.

Blackout Avoidance & Load Shedding

1 Hour
CEUs: .1 (1 PDHs)

The 2003 Northeast Blackout was a clarifying moment for the science of system protection. The effects of improper protection application, incorrect settings and lack of event analysis information became abundantly clear in its aftermath. The event cost billions of dollars in terms of lost productivity, and imposed life safety issues on over 50 million people. NERC has issued several reports and recommendations to improve these three factors. On the bulk power systems, underfrequency and undervoltage load shedding are mitigation steps to cope with such events.

  • Discussion of Recent Major Wide Area Blackouts
  • Stability Basics and Classifications
  • Protective Elements that Tripped in the 2003 Event
  • Sources of Power System Reactive Support
  • Effects of Insufficient Reactive Support
  • Voltage Collapse as a Root Cause of Most Recent System Blackouts
  • The P-V Curve as a Means of Studying an Undervoltage Collapse Event
  • How Undervoltage Collapse Effects Generator Protection Security
  • Undervoltage Load Shedding as a Mitigation Measure

Who Should Attend
Generator and Transmission Protection Engineers responsible for developing and/or
checking generator protection schemes and settings.

Generator NERC Compliance

1 Hour
CEUs: .1 (1 PDHs)

As a result of the 2003 Northeast Blackout, NERC became very active and issued several prescriptive rules regarding generator protection. This was due to the incorrect and insecure performance of generator protection on large numbers of the generation fleet in the affected area. Both primary and backup protection misoperated during the event. To properly set these elements, one requires knowledge of the system and system protection the generator is connected to, plus the control settings on the generator’s automatic voltage regulator (AVR). The interdependencies of the power system’s characteristics, the power system’s protection, and AVR settings are explored along with pertinent NERC PRC rules.

  • NERC’s concern regarding generator protection security
  • NERC’s PRCs that impact generator protection
  • Power Plant protection considerations
    • Generator itself
    • Generator Step-Up Transformer
    • Auxiliary Transformers
  • Generator voltage regulator controls and limit functions (over/under excitation, volts/hertz limiters)
    • Coordination with a generator’s short time overcurrent capabilities and protective relays
  • Generator Loadability and Impact on System Backup Protection
  • Difficulty of Coordinating 51V elements with System 21 elements
  • Methodologies in PRC-025 pursuant to System Backup Protection Calculations

Who Should Attend
Engineers responsible for developing and/or checking generator protection schemes and settings.

Motor Bus Transfer

3 Hour
CEUs: .3 (3 PDHs)

Motor Bus Transfer is the process of rapidly transferring sources to a motor bus for planned source switching and unplanned source failure. The rapid transfer allows the process to continue without interruption. To avoid damage to the motors, specialized equipment and methods are employed to cope with the dynamics of motor deceleration, and voltage and phase angle change between the new source and the motor bus. Improper reconnection of the motor bus can cause cumulative or immediate damage to the motors, and result in a process crash.

  • Residual Voltage Transfers always thought to be safe even if completed out-of-phase, can cause significant torques on motors, exceeding a 3-phase fault at the motor terminals.
  • IEEE C37.96 identifies events that occur or conditions that exist prior to and during transfer where, at transfer initiate, the initial phase angle may be nowhere near zero!
  • So at the end of a Residual Voltage Transfer spin down, the close phase angle may be nowhere near zero!
  • Research with modeling motors during transfer has proven that in 40% of the cases closing at varied angles, the peak-to-peak torques developed during the Residual Voltage Transfer are higher than the 3-Phase Short Circuit Torques of the motors on the bus.
  • This research has revealed that the peak currents in motors during Residual Voltage Transfers are higher than the 3-Phase Short Circuit Currents in more than 60% of these cases.
  • This motor modeling research also shows that in 89% of the cases closing at varied angles, the currents during Residual Voltage Transfer are in excess of six times rated current.
  • Synchronous In-Phase Transfers may take longer than some arbitrary time limit. Depending on the initial phase angle at transfer initiate, it may take more than 6 or 10 cycles for the motors to rotate back into synchronism.
  • Compared to blind Residual Voltage Transfers, these Synchronous In-Phase Transfers are much faster, closing at much higher voltages, at much lower slip frequencies, with closure near zero degrees and low inrush current and torque.
  • The 1.33 resultant pu V/Hz transfer criterion in NEMA MG-1, ANSI/NEMA C50.41 and IEEE C37.96 has no correlation to motor torque and actually gives passing grades to severely excessive torques upon transfer.
  • Time period transfer criteria, stated in NEMA MG-1, IEEE 666, ANSI/NEMA C50.41 and IEEE C37.96, are arbitrary and would permit severely out-of-phase transfers or conversely may preclude perfectly good synchronous transfers.
  • A Motor Torque Ratio TPK /TL, introduced as the aggregate peak torque at transfer expressed as a multiple of the aggregate load torque prior to transfer, displays a high correlation to the phase angle at transfer with little effect from voltage or frequency difference.
  • If it is torque that reduces the life expectancy and damages motors or driven equipment, or both, as suggested in the C50.41 Standard, then the industry must use a torque-based criterion to assess if transfers are being completed within acceptable torque limits.

Course Outline:

  • Introduction
  • Why Transfer Motor Load Sources
  • Basic Application Configurations
    • Primary-Backup
    • Main-Tie-Main
    • Multiple-Option Source Selection
  • IEEE Std C37.96-2012 Motor Bus Transfer Classification – Methods & Modes
    • Automatic and Manual
    • Closed Transition Method – Hot Parallel Transfer
    • Open Transition Method – Fast, In-Phase, Residual Voltage
    • Open Transition Modes – Simultaneous, Sequential
  • IEEE Std C37.96-2012 Conditions Across Normally Open Startup or Bus Tie Breaker – Before / During Transfer
    • Effects of a Fault
    • Out-of-Step (OOS) Generator Trip
    • System Separation between Incoming Supply Sources
    • Supply Source Transformer Winding Phase Shift
    • Transient Effects upon Disconnect of Motor Loads
    • Motor and Load Characteristic Effects on MBT
  • Failed Residual Voltage Transfer – Case Study
  • Transfer Initiate, Inadvertent External Operation, Lockouts
  • Load Shed During Transfer
  • ANSI/NEMA Standard C50.41-2012 Resultant per unit V/Hz Limits
  • Bus Transfer Spin Down Testing, Acceptance Testing, Setting Considerations
  • Spin Down Analysis & Settings Calculations – Case Study
  • Sequential vs. Simultaneous Transfer, The Need for Speed – Case Study
  • IEEE Fast Transfer Sync Check Relay Performance Test Protocol Results
  • IEEE Residual Voltage Transfer Relay Performance Test Protocol Results
  • Motor Bus Transfer System Dynamic Performance Test Protocol Results and Observations
  • A Motor Bus Transfer Torque Ratio Criterion applied to Live Open Transition Transfers Under Normal Operating Load Conditions – Observations and Conclusions
  • Test Results from Modeling of Transient Currents and Torques on Motors during Residual Voltage Motor Bus Transfer
  • Conclusions

Who Should Attend
Engineers and Technicians responsible for applying, setting and commissioning motor bus transfer systems in both power plants and industrial facilities. Also, Personnel in Plant Operations responsible for process output and continuance.

Automatic Synchronizing

1 Hour
CEUs: .1 (1 PDHs)

Synchronizing is the process of taking two electrical systems and connecting them. This can be affected on a generator to a bus, or a tie between two bulk power systems. Proper synchronizing involves minimizing the phase angle, slip frequency and voltage difference between the two systems. Prior to synchronizing, the systems may have a static phase angle or rotating phase angle. The application of sync check and automatic synchronizing elements is explored and calculations developed. Synchronizing schemes are illustrated that improve security. Specialized control algorithms to properly adjust generator speed and voltage for proper synchronization are defined and graphically illustrated.

  • Effects of Synchronizing Errors
  • Synchronizing System Components and Elements
  • Classical Synchronizing Scheme
  • Manually-Supervised Automatic Synchronizing
  • Fail-Safe Analysis and Schemes to Improve Security
  • Testing Provisions
  • Backup Path Philosophy
  • System Restoration Scenario (Tie Line Syncing)
  • Matching a Generator to the System Prior to Synchronizing
    • Conventional Method & Pulse-Width-Modulated Proportional Method
  • Field Test Results

Who Should Attend
Generator and T&D Protection Engineers responsible for developing and/or checking synchronizing schemes and settings.

Distributed Energy Resources Operation, Control & Protection

4 Hours
CEUs: .4 (4 PDHs)

Distributed Electric Resource (DER) is increasing its penetration into the distribution system. This technical session provides a background into DER operation and associated control and protection considerations for conventional and inverter-based power sources. We will review types of DER/DG and the modes in which they can operate in parallel with the distribution system. Key aspects of IEEE 1547 and a sample DER interconnection screening process are highlighted. Details of on-site standby power system conversion to operate in parallel with the distribution system are shown. Protection methodology at the point-of-common coupling (PCC) and point-of-interconnection (PI) is explored for all types of DER. A treatment of distribution system protection and control considerations and applications with DER is discussed.

  • Define Distributed Electrical Resource (DER)
  • Explore Types of DERs
  • Why DER?
  • Utility and Facility Drivers for DER
  • Mission Critical Power and Conversion to DER
  • Rates and DER Operational Sequences
  • Industry Concerns
  • IEEE 1547: Industry DER Guide
  • Sample Utility DER Interconnection Guide
  • Interconnection Protection: “The Five Food Groups”
    • Anti-islanding
    • Powerflow
    • Fault detection
    • Abnormal operating conditions
    • Reconnection
  • Interconnection Transformer Impacts
  • Generator Types and Impacts
    • Synchronous
    • Induction
    • Asynchronous (Inverter Based)
  • Example Protection Applications
  • Distribution Protection Coordination Issues
    • Directionalization
    • Reclosing coordination
  • Smart Grid / Microgrid and DER
  • Impact of IEEE 1547-2018
    • Fault ride-through
    • Reactive support and voltage control
  • System Control with DER
    • LTC, Regulator and Capacitor Control Issues

Who Should Attend
Electrical distribution generalists, system planners and DER P&C practitioners.

Feeder Protection Calculations & Settings

2 Hours
CEUs: .2 (2 PDHs)

  • Feeder Protection Calculations Example
  • Short Circuit Current
  • Per Unit Quantities
  • Symmetrical Components
  • Fault Types
  • Fault Current Calculations Example

Who Should Attend
Distribution Engineers and Technicians, and Operations personnel desiring a practical background into the protection of this part of the system.

Distribution System Optimization

4 Hours
CEUs: .4 (4 PDHs)

  • Volt-VAr Control (VVC), Volt-VAr Optimization (VVO), and Conservation Voltage Reduction (CVR) Issues and Answers
  • Allowable voltage ranges
  • Equipment and devices used in Volt-var control
    • LTC, voltage regulator and capacitor controls
  • Volt-var Control Technologies and tradeoffs
  • Cost-Benefit Analysis of VVO
  • Verification, Assessment and Monitoring Requirements for CVR

Who Should Attend
Distribution Engineers and Technicians, and Operations personnel desiring a practical background into the protection of this part of the system.

Distribution Feeder Protection & Control

3 Hours
CEUs: .3 (3 PDHs)

Distribution protection is a complex scenario with many elements: relayed feeder breakers, recloser controlled feeder breakers, line reclosers, sectionalizing switches, sectionalizers and fuses. The application and location of the protective and sectionalizing infrastructure predicates the application and coordination of protection. Compounding the complexity is the application of DMS/DA and presence of DER/DG. The session covers the distribution topology and protective infrastructure, and application of settable of relays and recloser controls.

  • Distribution System Reliability
  • Standards and Practices
  • Protection Philosophies
  • Causes of Faults
  • Fault Types
  • Distribution Construction/Configurations
  • Impedances Used in Fault Current Analysis
  • Fault Calculations and Settings
  • Protection Devices and Characteristics
  • Protective Device Selection and Application
  • Protective Functions of Relays and Controls
  • Ground Fault Detection Methods
  • Automatic Reclosing
  • Time Overcurrent Device Coordination
  • Special Protective Applications
  • Fault Event Analysis

Who Should Attend
Distribution Engineers and Technicians, and Operations personnel desiring a practical background into the protection of this part of the system.

Smart Grid Essentials

8 Hours
CEUs: .8 (8 PDHs)

This session focuses on distribution automation controllers and applications in Smart Grid environments. Load tapchanger, regulator and line capacitor controls are all constituents of IVVC, VVO and CVR schemes. Proper control must be able to function with various levels of DMS/DA integration including autonomous operation, changing grid topology and operation adaptation, communication infrastructure and bandwidth, DER/DG integration, and cyber security considerations.

  • Introduction
    • Smart Grid Industry Drivers
    • Characteristics of Smart Grid
    • Smart Grid Architecture
    • Information (Cyber) Security Challenges
    • Funding opportunities for Smart Grid Development
    • Standardization Activities Related to Smart Grid
    • Integrated Volt VAr Management Systems
    • Distributed Generation
    • Power Quality
  • Introduction to IVVMS
    • Purpose & Objectives (Present + Smart Grid)
    • Expected Smart Grid Operating Requirements & Configurations
    • kW Control – Conservation Voltage Control Function Basics & Application
  • Understanding IVVMS Operations
    • VAr Control – A Primary Driver & Function Cap Controls – History of Smart Grid Features & Systems Primary Effect on Voltage Profiles Sizing, Locating & Coordinating Innovative VVM Techniques & Smart Grid Backup
    • LTC Voltage Control–The Ultimate Voltage Responsibility Reverse Power Operation Reversible Radial Feed, DG Applications (Large & Small), Combo Feed/DG, Distribution Tie Transformers, Network Applications Effects on Voltage Profiles LTC Control Features & Applications Settings, Timing, Coordination Effects on Voltage Profiles
    • Voltage Control for Variation of Diverse System Configurations
  • Paralleling LTC Transformers and Systems
    • Transmission Tie and Distribution Substation Transformers Smart Grid Enhancements
  • Power Quality
    • Utility Definition Versus End Consumer Definition
    • Performance Based Rates
    • MAIFI, SAIFI, SAIDI and CAIDI
    • Engineering the Distribution Grid to Reduce SAIDI & MAIFI
    • Single Phase Re-Closers Versus Three Phase Reclosers
    • Fault Locators
    • Sags & Swells
    • Harmonics
  • Volt/VAr Smart Grid Architectures
    • Field Apparatus Used to Implement Smart Grid
    • Types of Architectures Used to Implement Smart Grid

Who Should Attend
T&D Engineers, Technicians and Operations personnel responsible for implementing Smart Grid applications, including those with interests in IVVC, VVO, CVR and DER/DG Integration.

LTC & Regulator Controls

8 Hours
CEUs: .8 (8 PDHs)

On-line load tapchangers are a key component for controlling voltage at transmission and distribution levels. They are also a key element of IVVC, VVO and CVR application. Schemes and applications for operation, alarming, runback, reliability centered maintenance, paralleling and coordination with capacitors are addressed.

  • Review of LTC/Regulator Control Functions
    • Basics of Voltage Regulation
    • Regulation Blocking
    • Tap Position Feedback
    • Line Drop Compensation
    • Reverse Power Conditions and Options
    • Voltage Reduction
    • Paralleling of Transformers
  • Control Hardware and Hands-On
    • HMI, buttons, switches, LEDs
    • Menu items, entering settings and navigation
    • Communications options
    • External interfaces and connections
    • Accessories- Adapter kits, panels, etc.
  • Settings Programming
    • Use of TapTalk Software for Communicating with controls
    • Configuration for connected apparatus
    • Control Setpoints
    • Real time monitoring
    • Advanced Smart Grid Functions
    • TapPlot Software
  • Installation and Testing

Who Should Attend
T&D Engineers, Technicians and Operations personnel responsible for implementing Smart Grid applications, including those with interests in IVVC, VVO, CVR and DER/DG Integration.

Transformer Paralleling

1 Hour
CEUs: .1 (1 PDHs)

Additional Information Coming Soon

Introduction to Cyber Security

2 Hours
CEUs: .2 (2 PDHs)

Modern Intelligent Electronic Devices (IEDs) used in Electric Power System Protection and
Control Applications are incorporating high-speed wired and wireless communications. More applications are now using high-speed Ethernet communications and they are often interfaced with public shared networks such as the internet to transport the data. This brings serious vulnerability concerns from outside attackers (from within and outside the country) with malicious intent. This course covers the cyber security vulnerabilities that exits on the Electric Distribution System and how to address them using the latest cyber security technologies (IEEE 1686, IPSec, RADIUS, etc.) which can be embedded in the protection and control IEDs to provide end-to-end security. The presentation also covers NERC CIP Version 5 standard.

  • Government Regulations on cyber security
  • Consequences of Cyber-attack on Distribution Protection and Control IEDs
  • Cyber security Standards
    • IEEE 1686
    • IEEE C37.240
    • NERC CIP Version 5
  • Cyber security Requirements and technologies
    • Access Control and Authenticity of the users
      • Password Requirements
      • Role Based Access Control
      • Secure DNP Authentication
      • Password Management using Remote Authentication Dial in User Service (RADIUS)
    • Data Confidentiality
      • Data Encryption
      • IPSec
  • Public Key Infrastructure and Certificates
    • Cryptographic and Key Management
      • IKE, ISAKMP, Diffie-Hellmann(DH) Key Exchange
    • Certificates
      • OpenSSL toolset
  • Example of embedded implementation of IEEE 1686, RADIUS and IPSec on Distribution Capacitor bank control

Who Should Attend
Distribution Engineers that want to get a basic understanding of why Cyber Security Is important for distribution applications.

Hands-on Testing and Commissioning Labs

8 Hours per Relay System

Protection and control systems play a key role for the safe and reliable operation of today’s electricity power systems. The complexity of multifunction digital protection presents considerable challenges to those responsible for testing and commissioning these devices.

It has been well documented by NERC and other regulatory agencies that incorrect settings and logic account for a large majority of relay failures and misoperations. Proper testing and commissioning can greatly reduce the likelihood of this type of relay failure.

In the following hands-on labs, Beckwith Electric will provide detailed instruction on testing all relay protective elements and associated logic, utilizing Beckwith’s relay software. These labs are appropriate for customers who utilize a three phase relay test set from multiple suppliers. They are hands-on sessions and students will be asked and encouraged to provide their own three phase test equipment.

Learn skills required to test and commission Beckwith relays for generator, transformer, and distribution feeder/recloser control protection including:

  • Verify correct wiring and configuration.
  • Verify protective element settings: Pick-up, Drop-out, Timing
  • Verify proper logic supervision
  • Verify additional logic configurations (Breaker Failure, Cold Load Pick-up, and more)
  • Review relay software utilization for testing purposes.
    • Overall software review
    • Configuration of relay set points and settings
    • Sequence of events, oscillography, and transient playback

Who Should Attend
Power system protection engineers, technicians, or individuals responsible for either developing or executing relay test plans for the relay testing and commissioning process.

Protective Relay Systems Available for Training:

  • Generator Protection
    • M-3410A Small Generator Relay
    • M-3425A Comprehensive Generator Protection System
  • Transformer Protection
    • M-3311A (2, 3, or 4-Winding) Transformer Protection System
  • Intertie Protection
    • M-3410A Intertie Protection Relay
    • M-3520 Intertie Protection Relay
  • Distribution Protection
    • M-7651A D-PAC Protection, Automation and Control System for Power Distribution applications
    • M-7679 Recloser, Switch, Sectionalizer, Feeder & Advanced Distribution Automation
  •  Motor Bus Transfer
    • M-4172 Digital Motor Bus Transfer System For Low Voltage (LV) Switchgear Applications
    • M-4272 Digital Motor Bus Transfer System For Low Voltage (LV) and Medium Voltage (MV) Switchgear Applications