The Copperbelt University
School of Engineering
Electrical Engineering Department
POWER SYSTEM PROTECTION
(EE531/DEE330)
2020/2021 Unit 4. Relay Technology
By Mr. Buchizya Kumwenda
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Table of Contents
List of Figures ................................................................................................................................. 3
List of Tables .................................................................................................................................. 3
List of Abbreviations or Acronyms ................................................................................................ 4
Unit 4. Relay Technology ............................................................................................................... 5
Objectives .................................................................................................................................... 5
Learning Outcomes ..................................................................................................................... 5
Content ........................................................................................................................................ 5
4.1
Introduction ...................................................................................................................... 6
4.2 Evolution and classification of protective relays .................................................................. 6
4.3 Aspects of modern protection relays ................................................................................... 18
4.4
Modern Relay Operating Principles ............................................................................... 23
4.5 Relay terminologies and a summary of protection systems ................................................ 26
4.6
Research Questions ........................................................................................................ 27
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List of Figures
Figure 1. Some consequences of undetected short circuits or improper relay settings .................. 6
Figure 2. Highlights of the protective relay development .............................................................. 7
Figure 3. Electromechanical relay types ......................................................................................... 8
Figure 4. Solid state relays ............................................................................................................ 10
Figure 5. Microprocessor (μP) based relays - E.g. SEL 751 for feeder protection ...................... 11
Figure 7. Relay panels with EM and μP relays ............................................................................. 15
Figure 6. Classifications or types of protective relays .................................................................. 17
Figure 8. Modern protection relay system requirements .............................................................. 18
Figure 9. Protection IED with simple communication capabilities .............................................. 19
Figure 10. Protection, control, monitoring and auxiliary functions .............................................. 20
Figure 11. Modern relay operating principle ................................................................................ 26
List of Tables
Table 1. Performance evaluation and comparison of the three generation protective relays ....... 12
Table 2. Typical relay codes: ANSI/IEEE C37.2 standard device number codes ........................ 16
Table 3. Relay functions and their applications ............................................................................ 27
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List of Abbreviations or Acronyms
ABB – ASEA Brown Boveri
AC – Alternating Current
A/D – Analogue to Digital
ANSI – American National Standards Institute
CB – Circuit Breaker
CPU – Central Processing Unit
CT – Current Transformer
DC – Direct Current
DNP – Distributed Network Protocol
DT – Definite Time
DSP – Digital Signal Processing
EMR – Electromechanical Relays
EMI – Electromagnetic Interference
E/F – Earth Fault
EHV – Extra High Voltage
GE – General Electric
GPS – Global Positioning System
HV – High Voltage
HVDC – High Voltage Direct Current
HMI – Human Machine Interface
IDMT – Inverse Definite Minimum Time
IEC - International Electro-technical Commission
IED – Intelligent Electronic Devices
IEEE – Institute of Electrical and Electronics Engineers
LAN – Local Area Network
LCD – Liquid Crystal Display
MV – Medium Voltage
NERC - North American Electric Reliability Corporation
NPR – Numerical Protection Relay
O/C – Overcurrent
O/V - Overvoltage
PC – Personal Computer
pf – power factor
PMU – Phasor Measurement Unit
PRP – Parallel Redundancy Protocol
PT – Potential Transformer
RAM – Random Access Memory
REF – Restricted Earth Fault
RFI – Radio Frequency Interference
ROCOF – Rate of Change of Frequency
RTU – Remote Terminal Unit
SCADA - Supervisory Control and Data Acquisition
SEL - Schweitzer Engineering Laboratories
SOE – Sequence Of Events
TCP – Transmission Control Protocol
VT – Voltage Transformers
μP - Microprocessor
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Unit 4. Relay Technology
Objectives
The student should be able to
•
•
•
•
•
State the definition and purpose of relays in power systems
Explain the relay operating principle based on modern technology
Discuss the evolution and classification of relays in terms of application, construction,
etc.
State the advantages and limitations of various relay technologies
Describe the substation communication systems for monitoring, control and protection
Learning Outcomes
The student should be able to

describe the requirements of a modern protection relaying system
Content
4.1.Introduction
4.2.Relay operating principle
4.3.Evolution and classifications of protective relays
4.4.Relay characteristics
4.5.Relay settings
4.6.Tutorial Questions
4.7.Research Questions
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4.1 Introduction
Undetected and isolated faults and abnormal conditions such as overloads/short circuits due to
improperly set relays or lack thereof can cause considerable damage to equipment, plant and also
result in service discontinuity or an unwanted outage as can be seen in Figure 1.
Figure 1. Some consequences of undetected short circuits or improper relay settings
Therefore, the fundamental objective of system protection is to quickly isolate a problem so that
the unaffected portions of a system can continue to function. The primary device employed to
achieve this objective is a protective relays which act as a decision-making device in the
protection scheme. A protective relay is a device or technology designed to implement protection
functions that properly detect defective line or apparatus or other power system condition of an
abnormal or dangerous nature, interpret input condition in a prescribed manner and after
specified conditions are met and initiate appropriate control circuit condition so as to cause
contact operation or initiate disconnection of the faulted area by circuit breakers.
The following sections outline the basic modern relay operating principles, the evolution and
classifications of protection relays, and the communication requirements.
4.2 Evolution and classification of protective relays
The relays used to protect power systems underwent important modifications in their
functionalities and technologies in order to improve the technical and financial aspects. Figure 2
highlights some aspects of the protection relay development.
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1900s (1902 – 1905)
<= o/c inst. trip devices, built-in in HV breakers
1905 – first o/c relay e.g. ABB introduced type TCB
ageing of the textile bellow gave some problems
1917 – thermal relay type
1918 – time current inverse o/c RI relay type
1909 – induction disc type incorporated the concept of directional
discrimination of faults
- directional relay using pilot wires for conveying information from one
end to the other of the line was introduced
Induction type mho relays were later introduced
1940s – electronic based relays referred to as static or solid state relays
1923 – distance relay (impedance type)
1950s - The distance relay type RYZK
1939 – polarized dc relays with improved accuracy and
sensitivity
1960s – proposals to use digital computers and
microprocessors for protective relaying
The first Combiflex static
relays were introduced 1969
1970s
- worlds first line distance relay with quadrilateral
characteristic, type RAZOG with shortest operating time of 21
ms
- Ultra-high-speed (UHS) relays with operate time of one
quarter cycle to a half cycle, began with the RADSS bus
differential relay
1975 – full scheme distance relay
type RAZFE
1976
- switched scheme relay type RAZOA, line distance relay for
Subtransmission
- Ultra high-speed line distance protection with the travelling wave
detector relay type RALDA
1979 – commercialization of microprocessor based relays with
emphasis on achieving very high fault clearance speed
1983 - fault localisator RANZA with +- 2% accuracy using fully
numerical apporach, much better than the analogue electronics
1986 – ABB first fully numerical relays was introduced
RELZ 100 – numerical line distance protection
1980 – improved digital relays with multifunction feature
available on the market
This led to drastic reduction in the product and installation
costs
Despite the relays performing the logic (digital), the filtering
was done using analogue methods
1988 – 1st prototype of phasor measurement unit (PMU) based
relay developed by Virginia Tech research team
1990s – Popularization of the notion of integrated protection and
control
Relays were able to provide protection, monitoring, control,
disturbance and event handling, and communications
1994
– The communication between the
terminals was utilising 56/64 kbit digital
telecommunication, replacing the previous pilot wire relays
– REB 551 Breaker terminal cointains breaker oriented functions e.g.
Auto reclosure, Synchro check, Breaker failure etc
1996
– dedicated control terminal REC 561
1998
– RET 521 Transformer terminal, 21 ms operating time
2000
– RED 521 General differential protection, typically 12 ms operating
time, and less than 2 ms CT saturation
Recent – optimization: Advanced firmware and complex hardware
Figure 2. Highlights of the protective relay development
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All of the relays developed until the 1940’s were electromechanical relays. Examples of pictures
and schematics of the first generation protective relays are shown in Figure 5.
Attracted armature type
Induction disc type
Thermal relays
Gas operated relays
Figure 3. Electromechanical relay types
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The first relay functions were integrated in the breaker design, and acted as overcurrent trip. The
first stand-alone electromechanical relay was designed 1904 but produced in 1905 for
overcurrent protection. The relay had a bellow made of impregnated balloon cloth, which in
combination with an air valve attenuated the movement of a solenoid to give the required delay.
This design was used in many installations, although the ageing of the textile bellow gave some
problems. The first thermal relay, type designation RW was delivered in 1917, and was used for
protection of three-phase motors. The design was based on the bimetallic principle, i.e. the
difference in thermal elongation for two metals. The time current inverse characteristic RI relay
was designed in 1918 and delivered in many countries from 1920 to 1985, when the last relay
was manufactured. However, this relay is still used in many countries. Actually, the time
overcurrent RI curve is also implemented in modern numerical relays for coordination of RI
relays still in service. From the era 1920 to 1930 a large number of various relays were
introduced. Some examples can be given below:



1924


1925


Sensitive earth-fault protection type RIRA 3
Power relay type RPB 10
Balance relay, differential protection type RBF 5
An induction relay voltage regulation relay type RCA and RCE (RRCE for plugin system RR), for voltage regulation of transformers with tap changers was
introduced
 Poly-phase power relay type RPAF
 Delayed under voltage relay type RODA
 Frequency relay type RF 2
 Thermal relays type RTV
 Earth fault relay type RJMS 1
 Signaling relays
 Timers
1930 type RMJ and worlds first modular RRMJ
 Instantaneous current relays
 Instantaneous voltage relays
The electromechanical relays (EMR) are still the most predominant relays in almost all countries
throughout the world including, Zambia, the USA and Russia, especially for HV and EHV. This
can be attributed to their long lifetime exceeding 60 years.
The early 1940’s showed the way into the development of static relays or solid state relays that
used electronic devices and didn’t contain a moving parts as can be seen in Figure 4.
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Figure 4. Solid state relays
Despite their effectiveness, during the past 15 – 20 years, there has been a widespread
displacement of EMR and solid state relays by microprocessor (μP)-based relays, in boarder
term, Intelligent Electronic Devices (IEDs) protection devices. Advances in the Very Large Scale
Integrated (VLSI) technology and software techniques in the 1970’s led to the development of
microprocessor-based relays. The world’s first fully numerical line distance protection terminal,
RELZ 100 was introduced 1986. This was also the first multifunction relay, where a number of
functions were integrated










Full scheme line distance relay with 5 zones
Load compensated operation
Phase selector
Power swing blocking
Disturbance recorder- 1 ms resolution
Event recorder
Over-current
Fault locator
Built-in protection communication schemes
Serial data communication with two ports for monitoring and control, etc.
The platform that incorporated an extensive library of protection and control software functions,
monitoring functions and communication functions was introduced in 1994. The integration
decreased the required wiring and space and increased the overall reliability, fault tolerance and
availability together with reduced investment and operation cost.
Other emerging trends include hardware platforms, configuring the software to perform different
functions, integrating protection with substation control, and substituting cables carrying
voltages and currents with fiber optic lines carrying signals in the form of polarized light. On the
software side, artificial intelligence techniques, such as neural networks, and adaptive protection
are some of the fields applied in protection practices. In addition, applying feedback systems in
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which relays monitor the operating state of the power system and automatically reconfigure
themselves for providing optimal protection.
Figure 5 shows a SEL 751 microprocessor based relay for feeder protection. It can be
appreciated that one SEL 751 relay performs a number of functions which would otherwise
require using a number of electromechanical relays. In addition, it has a user interface inform of
touch screen or key pad.
Figure 5. Microprocessor (μP) based relays - E.g. SEL 751 for feeder protection
This transition from the electromechanical to the numerical relays can be justified by the large
flexibility and the wonderful features accentuated in Table 1. The table provides the performance
evaluation and comparison between the different relays generations in order to bring out the
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strong and the weak points of each relay type. Microprocessor based relays provide many
functions that were not available in electromechanical or solid state designs. These features
include multiple setting groups, programmable logic, adaptive logic, self-monitoring, selftesting, sequence-of-events (SOE) recording, oscillography, and ability to communicate with
other relays (peer to peer) and control computers. The cost per function of microprocessor based
relays is lower than the counterparts owing to the reduction in cost of components, production
equipment and production techniques. The inherent drawback of microprocessor based relays is
the ageing of their electronic components that tends to bring on changes in their parameters,
during their 10 – 15 year lifetime. For instance, the service life of electrolyte capacitors, which
are widely used in microprocessor based relays, does not exceed 7 – 10 years, and this is under
favourable conditions of temperature and humidity.
Table 1. Performance evaluation and comparison of the three generation protective relays
Particular - Functionalities and
characteristics
Operating principle
Measuring elements/hardware
composition
Measuring method
Input signal levels
Auxiliary CT or VT
Surrounding environment:
Temp., dust, magnetic fields,
gravity, EMI, RFI, etc.
Timing function
Accuracy and sensitivity
Discrimination capability
Moving parts
Contact bounce and arcing
Shock and vibration proof/resistant
Deterioration due to operation
Acoustic Noise during operation
Robust
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Electromechanical
Electromagnetic
principle, thermal,
pressure etc.
Induction disc,
Electromagnets,
Induction cup,
Balance Beam,
float switches,
bimetallic strips
etc.
Electrical
quantities
converted into
mechanical force,
torque
High
Not required
Gravitation and
magnetic fields
may result in
undesired operation
Mechanical clock
works, dashpot
Temperature
dependent
Low
Yes
Yes
No
Yes
Yes
More
Type of Protective Relay
Solid State
Microprocessor or IEDs
(digital/numerical)
Transistors and
Microprocessors and built-in
ICs
software with predefined values
R, L, C,
Transistors,
Analogue ICs
comparators
Microprocessors, Digital ICs,
Digital Signal Processors
Level detects,
comparison with
reference value
in analogue
Comparator
Low
required
Their value may
vary with respect
to ambient
temperature and
humidity
A/D conversion, Numerical
algorithm techniques
Static timers
Temperature
dependent
moderate
No
No
Yes
No
No
Less
Low
required
Are more susceptible to EMI and
RFI perturbations. However,
IEEE std. 37.90 or IEC 61000
series of standards ensure the
relay designs provide excellent
reliability under those conditions
counters
Stable
high
No
No
Yes
No
No
Less
Requirement of draw-out
Operating speed and reset time
Precision (setting)
Techniques and algorithms for
achieving very high speed fault
clearance
Required
Slow
Low
Traditional
methods
Required
Fast
Moderate
Traditional and
basic
programming
Microprocessor compatibility
Product cost
Installation cost
Cost per function
Relay programming
Communication techniques or Data
or Information processing method
or algorithm
SCADA compatibility
Cyber security requirements
Data communications
Remote operation
Disturbance immunity
Parameters setting
- Human Machine Interface (HMI)
No
Low
Low
Very high
No
-
Yes
Low
Low
High
Partially
-
No
No
No
No
High
Difficult
- Plug setting, dial
setting
Yes
Yes
Yes
Yes
Low
Very easy
- Keypad for numeric values,
through computers
Requirement of specially trained
staff for operation
Range of settings
Multifunction
Setting management
Basic training
No
No
No
No
Low
Easy
- Thumb wheel,
dual in line
switches
Basic training
Limited
No
Basic
Wide
Limited
Basic
Function flexibility
Self- checking, diagnostics,
supervision, monitoring and
adaptability
Self-testing
Resistance
Output capacitance
CT burden
Detection of instrument
transformer saturation
No
No
Limited
No
Very wide
Yes
May require setting management
software to create, transfer and
track the relay settings.
Yes
Yes
No
100 mΩ
< 1 pF
High (8 – 10 VA)
No
No
10 Ω
> 20 pF
Low (1 VA)
No
Isolation voltage
Need for Auxiliary supply or selfpowered from the CT
Visual indication
Integrated functions
 protection
 metering
 monitoring
 control
 disturbance and event
handling (archiving)
Low
Required
High
Required
Yes
10 Ω
> 20 pF
Low (< 0.5 VA)
Can be programmed to detect
saturation of instrument
transformers in order to
minimize incorrect operations
High
Required
Targets/flags
NO
LEDs
Limited
LEDs, LCD
Yes
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Not required
Very fast
High
Artificial intelligent techniques,
hardware platforms, configuring
the software to perform different
functions
Yes
High
High
Low
Programmable
Serial, Ethernet, Modbus etc.
Advanced training
 communication
Metering feature
Operational value indication
Monitoring feature
Control feature
Disturbance and event handling
(archiving or recording or storage)
or SOE recording and
oscillography
Communication feature
GPS location and satellite time
synchronizing
Condition monitoring
Compactness
Susceptibility to common mode
failure
Power consumption
Firmware and Software
requirements
No
No
No
No
Not possible
No
Possible
No
No
Not possible
Yes
Possible
Yes
Yes
Possible
No
No
No
No
Peer to peer, to control
computers, etc.
Yes
No
Bulky
No
No
Small
Low
Yes
Compact
High
High
No
Low
some may
require basic
firmware
Very Low
Yes
Volume and wiring (space
requirements)
Require fewer CT or VT
connections as some operating
quantities, such as zero sequence
currents and voltages are derived
by numerical techniques. Thus,
one numerical relay can replace
up two five panels with EMRs or
two panels with static relays
Low
High
Overall weight per function
Economics – volume production
Combiflex relays and modular
building system
Ageing of components during
lifetime
Lifetime
High
Low
No
High
Limited
No
-
-
-
40 – 60 plus years
10 – 15 years
Market value or demand duration
Long
7 – 10 years
109 operations
Short
Replacement cost (may vary
depending on model/vendors )
Sensitivity to voltage transients
due to CB switching in the primary
circuit of the CT and VT
Low
High
Low
High
Reliability
Effect of DC component of
asymmetrical faults
Number of devices to control e.g.
breakers
Failure causes
Maintenance schedule – calibration
No
High
- Semiconductor
devices may get
damaged
- relay
maloperation
Yes
Less
Less
More



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Upon
Upon
Yes
Short
They become obsolete very
quickly
High
Yes
Upon commissioning
and functional testing required
interval


commissioning
1 year after
commissioning
and every 2
years
thereafter
After setting
changes


commissioni
ng
1 year after
commissioni
ng and every
3 years
thereafter
After setting
changes
 1 year after commissioning
 8 – 10 years thereafter
 After setting changes
The self-monitoring and selftesting feature reduces the need
for routine maintenance because
the relays automatically take
themselves out of service and
alert the operators of the problem
when they detect functional
abnormalities.
From the viewpoint of reliability, a statistical study (between 2000 and 2009), Deputy Head of
Relay Protection Department of Central Dispatch Service of UES of Russia, showed that the
reliability of microprocessor based relay is about 60% less than that’s of electromechanical relay.
Most of the issues raised are sorted by risk control. And once the risk is well identified and
properly assessed, it is just enough to take it into account and to plan making the necessary
actions in the good instants. For example, if we are sure enough that the lifetime of a digital relay
is 10 years, we must foresee its change after ten years minus epsilon , we should, also, be careful
in its last years of service. So, after identifying the weak points of the protective relay; it will be
clear where one must focus the efforts to reduce the failure risk and, consequently, improve the
reliability of the relay. The use of the redundancy technique (back up element) allows a
significant reduction of failure rates, and hence improving the reliability of the considered
protection system.
Figure 7 shows bulky relay panels with EMR relays compared to compact microprocessor based.
The reduction in size of microprocessor based relays is a result of the high level of integration of
the hardware and the ability of using one physical device for performing multiple protection
functions, such as overcurrent and multiple zone distance relaying for phase and ground fault
protection. The shortcoming of this benefit is that it increases the susceptibility to common mode
failure of the protection schemes.
Figure 6. Relay panels with EM and μP relays
Relay classification based on logic is further highlighted in Table 2 using the ANSI/IEEE C37.2
standard device number codes. The overcurrent relays are level detectors which operate under
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overloads or short circuit conditions. They are applied in the protection of feeders, lines, motors,
generators, transformers etc. Earth fault relays are also level detectors connected in the residual
circuit of 3 phases where earth fault current causes residual current to flow for the relay to
operate. They are also used for the protection of feeders, lines, large motors, generators,
transformers etc. The differential relays are comparators in which the CTs are connected on both
sides of protected equipment or between pilot wires to get differential current to operate the
relay. Differential relays are used to protect large motors, large generators, large transformers,
large generator transformer units etc. Distance or impedance relays respond to the ratio of V/I =
Z (distance between relay and fault) and is applied in medium and high voltage line protection.
The Carrier current relay utilizes the phase comparison of high frequency carrier signals to
actuate the relay and is used for feeder and long-overhead line protection.
Table 2. Typical relay codes: ANSI/IEEE C37.2 standard device number codes
Device
Description
Number
Device
Description
Number
2
Time delay relay
3
Checking or interlocking relay
12
Over-speed relay
51
Inverse time overcurrent relay
14
Under-speed relay
51G
Inverse time E/F & o/c relay
21
Distance Relay
51N
Definite time E/F & o/c relay
24
Over-flux or V/Hz Relay
52
AC Circuit Breaker
25
Synchronism check relay
59
Overvoltage relay
26
Over-temperature relay
59N
Neutral point displacement relay
27
Undervoltage relay
60
Voltage balance relay
29
Isolator
61
Generator Inter-turn
30
Annunciation relay
55
Power factor relay
32
Directional overpower relay
64
Restricted Earth-fault relay
68
Locking relay
56
Field application relay
37
Undercurrent or Underpower relay
66
Notching or jogging device
40
Excitation Fault Protection
67
Directional overcurrent relay
46
Negative sequence or reverse-phase or
78
Phase angle or out of step relay
phase balance current relay
74
Alarm relay
76
DC overcurrent relay
47
Negative sequence voltage or phase-
79
Auto-reclose relay
83
Automatic selective control or
sequence or phase balance voltage relay
80
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Monitoring loss of DC supply
transfer relay
48
Incomplete sequence relay
81O/U
Over/Under-frequency relay
49
Thermal relay
85
Pilot Communications, Carrier or
Pilot Wire Relay
86
Tripping relay
95
Trip circuit supervision relay
50
Instantaneous overcurrent relay
87
Differential relay
186
Autoreclose lockout relay
The summary of the classifications of protective relays is shown in Figure 6.
etc.
Relay Classifications/
Types
GE
SEL
Based on
Manufacturer
ALSTOM
ABB
Based on
characteristic
Based on
actuating
parameter
Based on
logic
- Definit time
relays (DT)
- IDMT relays
- Instantaneous
relays
- IDMT with
instantaneous
- Stepped
characteristic
- Programmed
switches
- Voltage
restraint
overcurrent relay
- Differential
- Unbalance
- Neutral
displacement
- Directional
- REF
- Overfluxing
- Distance
schemes
- Busbar
protection
- Reverse power
relays
- Loss of
excitation
- Negative phase
sequence relays
- etc.
Based on operation
mechanism
- Current relays
- Voltage relays
- Frequency
relays
- Power relays
- etc.
A) Primary
relays
B) Backup or
Standby
Analog or
solid state
Amplitude
comparators
- single input
Static
Microprocessor
based
Phase comparators
- two or three input
Digital
(hardware
based)
Mechanical
Induction relay
- Shaded pole
strucure
- Watt-hour meter
structure
- Induction cup relay
Used for directional
or distance
Attracted
armature
- hinged armature
type
- polarized
moving iron type
Solenoid and
plunger type
Used for
instantaneous units
for o/c or o/v
Based on
applications
Numerical
(software
based)
Electromagnetic
relays
Balanced
beam type
relay (low
burden)
Used for
differential or
distance
Thermal
A) OT Trip (oil
temperature trip)
B) WT trip
(winding
temperature trip)
C) Bearing
temperature trip
D) Etc.
Mechanical
interlocks
Float type
A) Buchholz
B) OSR
C) PRV
D) Water level
controls
E) Etc.
Pressure
switches
Pole discrepancy
relays
Figure 7. Classifications or types of protective relays
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IEDs
(advanced
software
based)
4.3 Aspects of modern protection relays
Figure 8 highlights the requirements of modern relay systems. The electric utility has been
divided into several departments to reliably and securely provide electricity to their customers.
These departments usually include a separate Supervisory, Control and Data Acquisition
(SCADA) department and a Protection & Control (P&C) department, each with its own focus.
SCADA provides a manned control center with real-time data in order to monitor and operate
their system, including energy management, outage restoration, safety, and
reliability/availability. P&C provides automated protection of primary equipment. The SCADA
and P&C departments each have their individual responsibilities with clear lines of functionality
and separate hardware
Serial Communication and Time Synchronization
with Older generation relays
IED Ethernet Communication and IEEE 1588
Time Synchronization
Figure 8. Modern protection relay system requirements
a) Communications systems
In the 1990s, the notion of integrated protection and control became very popular and benefited
full advantage of microprocessor technology, for protection, monitoring, control, disturbance and
event handling, and communication. There are many different types of communication media
such as twisted pair cable, coaxial cable, fibre optic cable and wireless communication. The
wireless networks are by far the most popular choice for new network algorithm. Nowadays,
modern digital relays draw on the experience and technical resources of the previous series and
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also featured compactness and less power consumption along with support for remote operation
based on enhanced communication functions. The use of global positioning system (GPS) for
digital measurement, especially for overhead line protection, gives very encouraging results.
They are more accurate than distance relaying algorithms which are affected by inadequate
modelling of transmission lines and parameter uncertainty due to line aging, line asymmetry and
environmental factors. The use of GPS technique allows providing time synchronization to ±1 µs
accuracy, a thing which proves the high precision character of this technique.
The IED relays communicate with local and remote peers, and with substation and control center
computers. Figure 8 shows the analog current and voltage inputs, opto inputs for monitoring the
status of substation equipment or receiving of some forms of control signals, relay outputs to
operate breakers or indicate changes of state of the relay, as well as front and back serial
communication port (used for extraction of event and disturbance (waveform capture) records).
The IEC 61850 has enabled replacement of hardwires used to interface the outputs with opto
inputs with high speed communications and the IEC 60044 facilitates replacing the current and
voltage circuits with sampled analog values over fiber thus ensuring a copperless interface with
the protection IED. The IEC 61850 can be used also for measurements, data acquisition, remote
control, setting changes, event, fault and disturbance records extraction and time
synchronization. The serial front and back port interface is optional, if the user requires a
redundant access to the substation through modem for setting changes and records extraction.
Microprocessor (µP) relays are designed for measurements status control via LAN data
measurements, status, and control via LAN data communications.
Figure 9. Protection IED with simple communication capabilities
The parallel port on the front of the protection IED can be used for maintenance. When the
requirement is to upgrade the relay firmware, a laptop is connected to the parallel port and the
user downloads the new firmware in the flash memory of the relay. For relay testing, a special
monitoring device with several LEDs and audio alarm is plugged into the parallel port in order to
indicate the operation of different internal protection elements or schemes.
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b) Data processing techniques
In fact, the accuracy of relays depends not only on their hardware components but also on the
manner of information processing to evolve the decision signal; this is what is called the data
processing algorithm or the processing method. So, the research of the optimal method to obtain
the most accurate decision in the fastest way is one major challenge in the numerical protective
relay design. Over the past two decades, the application of the artificial intelligence methods on
power protection relaying (ANN, Fuzzy logic, genetic algorithms…) is under investigation.
Perhaps the most wonderful aspect in artificial intelligence techniques is the ability to learn by
training any complex input/output mapping and recognize the noisy patterns. These techniques
have been quite successful but are not adequate for the present time varying network
configurations, power system operating conditions and events.
c) Functional library
The terminals can be loaded with a number of modular, type tested software function blocks as
shown in Figure 5. The various functions are arranged as individual blocks, that can be combined
either as predetermined schemes or custom designed utilising function block programming. This
means that an output signal from one function can be used as an input signal to another function.
These function blocks include all protection functions, tripping and autoreclosing logic, all
control functions for apparatus control and interlocking, binary inputs and outputs as well as a
logical function library with AND, OR and Time Delayed elements (0-50 seconds with 5 ms
resolution).
Future
Etc.
Future
Interlocking
Etc.
Apparatus control
Fuse failure
o/c protection
Synchro- and dead-line-check
Breaker failure protection
Auto-reclosing
Line differential protection
Earth fault o/c protection
Optional I/O units
Fault locator
Operating values I, V, P, Q, f
Real time clock
Event recording
Disturbance recording
Self-supervision
Remote communication
Distance protection
Man-machine interface
Protection and control
function
Monitoring and auxiliary
functions
Figure 10. Protection, control, monitoring and auxiliary functions
d) Monitoring
Modern microprocessor based IEDs offer many advantages over their electro-mechanical
counterparts. One of these advantages is the ability to monitor the IED health and the health of
the protection and control system and raise an alarm if any monitored function is amiss. This
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ability to monitor the protection and control system gives the utility the capability to
continuously insure the health of the protection and control system. The only way to insure
confidence in an unmonitored protection and control system is to test the system. This includes
not only testing the protective relay functions, but also testing the overall protection and control
system. For a system to be considered fully monitored, it must meet the following minimum
requirements



Internal self-diagnosis and alarming
Voltage and current waveform sampling three or more times per power cycle and
conversion of the samples to numeric values for measurement calculations by
microprocessor electronics that are also performing self-monitoring and alarming.
Alarming for power supply failure.
Some of the monitoring techniques include: trip coil, close coil, and lockout relay monitoring,
usage of IED self-test alarm contacts, instrument transformer failure detection using analog
GOOSE messaging & other level detection/comparison methods, breaker restrike detection,
station battery monitoring, oscillography cross-triggering, automated contact input & output
testing and natural testing by event analysis.
e) IED life cycle management
A relay upgrade or retrofit project is more than the simple hardware replacement. New relay
firmware and function compatibility, the migration of the existing protection and control logic
and communication network requirements and device vulnerability to cyber security are some of
the important aspects that need to be considered and well planned ahead of time. Furthermore,
for a Utility that needs to upgrade thousands of relays, there must be a strategy on how to
perform the upgrade systematically and efficiently.
f) Visibility and user experience:
Improvements on the Human Machine Interface (HMI) are another driving force for relay
upgrade. Early IEDs were equipped with rather primitive front panel displays and key pads.
Up/Down or Back/Forward arrow buttons were used to browse the content or selecting the
inputs. The first generation relays had only seven-segment displays. Reading and entering
settings from the front panel was a tedious task wrought with a chance for error. The computer
software that communicates to the relays did not have a graphical interface, making it difficult to
display voltage and current phasor diagrams or even quantities in relation to each other. Modern
relays have dramatically improved user interfaces. The relays now not only have bigger LCD
displays and graphical setting software, but also added features (e.g. touch screen) to make it
more flexible and easier to browse the settings or test the protection functions. Many modern
relays have user programmable pushbuttons, which can be utilized to replace the conventional
panel mounted control switches and pushbuttons for general control purposes. Another notable
progress is the logic status monitoring, where the relay internal logic variables are displayed
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graphically in real time together with the logic diagrams. This feature is a great tool for relay
functional testing and troubleshooting. These new features address the quality of the actions
associated with the protective relays and increase the confidence level of the technician and
engineer working with these devices. The new features reduce the chance for errors, increase the
monitoring features and help the user with understanding the device.
g) Time synchronization
Some micro-processor based devices made in early 1990s have IRIG-B time synchronization,
which was the prevalent and the only feasible technology to realize time synchronization at that
time. IRIG-B used coaxial cables and can achieve 10 to 100 microsecond (0.1millisecond)
accuracy, which is sufficient for tagging the sequence of events, fault records and oscillography.
With the emergence of Ethernet in the substation and security concerns, network based time
synchronization method is feasible. It improves monitoring, saves the installation and
maintenance cost of the dedicated IRIG-B coax cable, and addresses some security concerns with
wireless time synchronization from satellites. Network Time Protocol (NTP) was the first one to
be adopted and when applied in electrical substations, the simplified version SNTP together with
a GPS clock could achieve a typical time synchronization accuracy of 1 to 10 milliseconds. The
NTP or SNTP time distribution is less accurate than the IRIG-B, but is still sufficient for many
applications. However, with the introduction of synchrophasor technology, IEC61850 process
bus, and some future applications of networked based protection such as differential protection,
precise time synchronization is required to ensure the accurate time-aligned measurement. The
implementation of Precision Time Protocol (PTP) according to IEEE 1588 allows multiple
clocks in the network to synchronize with one another with accuracy better than 1ns (1
nanosecond). The Power Profile (PP) is a PTP profile that suitable for use in power system
protection, control and automation applications with a worst-case time error of less than 1us over
a 16-hop network.
h) IEC61850
The standard enables interoperability among relays from different vendors and interoperability
among System Configuration Tools (SCT) from different suppliers. Interoperability in this case
is the ability for relays to exchange information and commands on the same network or
communication path, and for configuration tools to understand and configure each other's
configuration files.
i) Security and compliance
Modern IEDs provide network capabilities that can be used for peer to peer information
exchange or remote SCADA control and monitoring, EMS, Engineering, Operations and
Maintenance. Therefore, security that includes controlling the physical access as well as
protecting against malicious network related cyber-attacks and intrusion are critical. Security
features in modern IEDs have been enhanced to comply with the latest North American Critical
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Infrastructure Protection (CIP) standards. The security measures typically include strong
passwords, basic role-based password security within the device or server-based authentication,
which a centralized RADIUS server is used to authentic the access rights to the IED. The
increase of Ethernet based applications requires security measures to be implemented both in the
IED application/device level and the higher network level. In some instances, a substation
gateway may be used as a means of access control to the substation devices. Gateways and
firewalls may have additional authentication features for access control. In many instances, the
users have set-up a trial system to validate and perform comprehensive cyber security testing
using comparable setup and applications as the field prior to performing the IED relay upgrade in
a large scale roll out.
j) Maintenance cost
It takes a well-planned approach to develop a replacement strategy. This is no difference when
considering microprocessor based relays. Everything has a finite life and predicting the life of a
microprocessor based relay requires consideration of many variables. There are multiple ways to
determine the impending failure of an IED. The traditional method is to perform periodic testing
and/or maintenance on the relay. This requires technicians, asset planners, schedulers and
possibly protection engineers to take part in the planning process to isolate a relay and perform
the tests necessary to determine proper function of the relay. This costs the utility resources and
significant budget. IEEE has determined that the maintenance costs as an industry for protective
relaying as a whole will double in the next 10 to 20 years. This is a complicated concept as many
utilities are replacing EM relays with IEDs and as they are turning more and more of their fleet
into IEDs, the early relays have reached their end of life.
4.4 Modern Relay Operating Principles
Protective relays work in ‘synchronism’ with the sensing and control devices. They operate on
voltage, current, current direction, power factor, power, impedance, temperature etc. The relay
typically has user settings (pickup) to compare with the information derived from the CT and VT
inputs to make a trip/no-trip decision. The output of the relay is wired in the trip circuit of the
associated CB. The basic relay operating principle can be based on amplitude and phase
comparison. Amplitude comparators compare the magnitude of two input quantities irrespective
of the angle between them. One of the inputs is the operating quantity and the other a restraining
quantity. When the amplitude of the operating quantity exceeds that of restraining quantity, the
relay sends a tripping signal to the circuit breaker. The comparison is either by the algebraic
difference or comparison of ratios. The relays which use this principle include non-directional
overcurrent and overvoltage relays. The phase comparison technique, on the other hand, is the
most widely used one for all practical directional, distance, differential and carrier relays. If two
input signals have a phase relationship lying within the specified limits then the output occurs.
Both the input must exist for an output to occur. The operation is independent of their
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magnitudes and is dependent only on their phase relationship. The common types are vector
product and coincidence type phase comparators.
The operation depends on constructional features, i.e.
1. Electromechanical relays which works on electromagnetic attraction principle or
electromagnetic induction relay which works on electromagnetic induction principle. The
electromechanical protective relay converts the voltages and currents to magnetic and electric
forces and torques that press against spring tensions in the relay. The tension of the spring
and taps on the electromagnetic coils in the relay are the main processes by which a user sets
in a relay. Thus, conventional electro-magnetic relays operate by comparing operating torque
(or force) with restraining torque (or force).
2. In static relays
A) Solid state analog relay: use analogue electronic devices instead of magnetic coils
and mechanical components to create the relay characteristics. In this type of relay,
the incoming voltage and current waveforms are monitored by analog circuits, not
recorded or digitized. Since the output of CT and PT are not suitable for static
components so they are brought down to suitable level by auxiliary CT and PT. Then
auxiliary CT output is given to rectifier. Rectifier rectifies the relaying quantity i.e.,
the output from a CT or PT or a Transducer. The rectified output is supplied to a
measuring unit comprising of comparators, level detectors, filters, logic circuits. The
output is actuated when the dynamic input (i.e., the relaying quantity) attains the
threshold value. This output of the measuring unit is amplified by amplifier and fed
to the output unit device, which is usually an electro-magnetic one. The output unit
energizes the trip coil only when relay operates. The analog values are compared to
settings made by the user via potentiometers in the relay, and in some case, taps on
transformers. In some solid state relays, a simple microprocessor does some of the
relay logic, but the logic is fixed and simple. For instance, in some time over current
solid state relays, the incoming AC current is first converted into a small signal AC
value, and then the AC is fed into a rectifier and filter that converts the AC to a DC
value proportionate to the AC waveform. An op-amp and comparator is used to
create a DC that rises when a trip point is reached. Then a relatively simple
microprocessor does a slow speed A/D conversion of the DC signal, integrates the
results to create the time-over current curve response, and trips when the integration
rises above a set point. Though this relay has a microprocessor, it lacks the attributes
of a digital/numeric relay, and hence the term “microprocessor relay” is not a clear
term. User programming is restricted to the basic functions of adjustment of relay
characteristic curves. Therefore it can be viewed in simple terms as an analogue
electronic replacement for electromechanical relays, with some additional flexibility
in settings and some saving in space requirements.
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B) Digital Relay: measured ac quantities are manipulated in analogue form and
subsequently converted into square-wave (binary) voltages. Logic circuits or
microprocessors compare the phase relationships of the square waves to make a trip
decision. Compared to static relays, digital relays introduce Analogue to Digital
Convertor (A/D conversion) of all measured analogue quantities and use a
microprocessor to implement the protection algorithm. The microprocessor may use
some kind of counting technique, or use the Discrete Fourier Transform (DFT) to
implement the algorithm. The Microprocessors used in Digital Relay have limited
processing capacity and memory compared to that provided in numerical relays.
Digital relay consists of: (1) Analogue input subsystem, (2) Digital input subsystem,
(3) Digital output subsystem, (4) A processor along with RAM (data scratch pad),
main memory (historical data file) and Power supply. Digital relaying involves
digital processing of one or more analog signals in three steps: Conversion of
analogue signal to digital form; Processing of digital form; Boolean decision to trip
or not to trip.
C) Numerical Relay: measured ac quantities are sequentially sampled and converted into
numeric data form. A microprocessor performs mathematical and/or logical
operations on the data to make trip decisions.
D) Intelligent Electronic Devices (IEDs): the operating principle of a typical modern
protection relay is illustrated in Figure 2. The relay samples power system voltages
and currents, which are usually in kV and kA, respectively. The signal levels are
reduced by VTs and CTs typically to 110 V or 120 V and 1 A or 5 A nominal values
in Zambia or 67 V and 5 A in North America, respectively. The outputs of the
instrument transformers are applied to the analog input subsystem which provides
electrical isolation, reduces the level of the input voltages (using an auxiliary CT or
VT), converts the currents to equivalent voltages and removes high frequency
components from the signals using analog filters. The output of this subsystem is
applied to the analog interface which includes amplifiers, multiplexers and analog-todigital (A/D) converters. These components sample the reduced level signals and
convert their analog levels to equivalent digital numbers that are stored in memory.
The status of isolators and circuit breakers in the power system is provided to the
relay via the digital input subsystem and are read into the microcomputer memory. A
relaying algorithm, which is a part of the software, processes the acquired
information. The algorithm uses signal-processing techniques to estimate the
magnitudes and angle of voltage and current phasors. In some cases the frequency of
the system is also measured. These measurements are used to calculate other
quantities, such as impedances. The computed quantities are compared with prespecified thresholds (settings) to decide whether the power system is experiencing a
fault/abnormal operating condition or not. If it is, the relay sends a command to open
one or more circuit breakers for isolating the faulted zone of the power system. The
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trip output is transmitted to the power system through the digital output subsystem.
The relay settings and other vital information are stored in non-volatile memory of
the relay (ROM). The Random Access Memory (RAM) is used for storing data
temporarily. The power supply to a relaying microcomputer must be available even
when the system supply is interrupted. Arrangements are, therefore, made to provide
energy to the relay during normal and abnormal operating conditions of the power
system by means of a battery bank.
CB
CT
To rest of network
Isolator
VT
Isolation
filters
Surge
filters
Antialiasing
filters
Sampling
clock
Power
supply
Digital
input
subsystem
S/H
MUX
sample/
hold
multiplexer
Digital
output
Data request
and display
A/D
LCD
(information on V, I,
P, time, location etc,
setting)
Processor
PC
GPS
receiver
interface
Substation GPS
receiver
Data
logger
RAM
ROM
(settings, information
retrieval etc.)
EEPROM
Microprocessor based relay
(location and time
synchronization)
Figure 11. Modern relay operating principle
4.5 Relay terminologies and a summary of protection systems
1. Pickup level of actuating signal: The value of actuating quantity (voltage or current)
which is on threshold above which the relay initiates to be operated. If the value of
actuating quantity is increased, the electromagnetic effect of the relay coil is increased
and above a certain level of actuating quantity the moving mechanism of the relay just
starts to move.
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2. Reset level: The value of current or voltage below which a relay opens its contacts and
comes in original position.
3. Operating Time of Relay: Just after exceeding pickup level of actuating quantity the
moving mechanism (for example rotating disc) of relay starts moving and it ultimately
close the relay contacts at the end of its journey. The time which elapses between the
instant when actuating quantity exceeds the pickup value to the instant when the relay
contacts close.
4. Reset time of Relay: The time which elapses between the instant when the actuating
quantity becomes less than the reset value to the instant when the relay contacts returns to
its normal position.
5. Reach of Relay: A distance relay operates whenever the distance seen by the relay is less
than the pre-specified impedance. The actuating impedance in the relay is the function of
distance in a distance protection relay. This impedance or corresponding distance is
called reach of the relay
Table 3. Relay functions and their applications
Title
Overcurrent
protection (> I)
Earth fault
protection (> If)
Differential
protection
(vector
difference I1 – I2)
Distance
protection
(Impedance Z)
Carrier current
protection (phase
comparison of
carrier signals)
Principle
Relay connected in secondary of CT.
Overloads/short-circuits etc. cause increased
primary current/secondary current and relay
operates
Relay connected in residual circuit of three CT
secondaries. Earth fault current causes residual
current and relay operates
CTs connected on both sides of protected
equipment. Relay connected between pilot wires
to get differential current.
Applications
Feeders, lines, motors, generators,
transformers, load circuits,
individual loads etc.
Relay responds to ratio of V/I at relay location.
V/I = Z = distance between relay location and
fault on line relay operates if Z measured is less
than set value of Z
Signals are transmitted through the line at high
frequency. Fault produces phase difference in
signals. This actuates relays at both ends.
Protection of medium voltage
(MV) and High voltage (HV)
lines
Feeders, lines, large motors,
generators, transformers, load
circuits etc.
Large transformers, large motors,
large generators, large generatortransformer units, bus bars etc.
Feeders, long overhead lines etc.
4.6 Research Questions
QR1.
Compare and contrast relay tests for the EMR, solid state, microprocessor based
relays
QR2.
Discuss the reliability and failure causes of EMR, solid state, microprocessor
based relays
QR3.
Compare and contrast the communication network topologies used in substations
for protection and control.
QR4.
Discuss the communication requirements for EMR and solid state relays
QR5.
For IED protection relays, highlight the communication requirements for
a) line differential protection
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b) distance protection
c) time synchronization
d) measurement and control
e) SCADA
QR6.
State and describe some important communication protocols used in protective
relaying systems.
QR7.
Describe some of the programming and software features from different vendors
such as GE, SEL, ALSTOM and ABB.
QR8.
Compare the communication methods used for generator, differential, distance,
overvoltage, undervoltage and overcurrent protection by the different manufacturers such
as GE, ABB, SEL and ALSTOM
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