36 TRANSMISSION LINE CONSTANTS
70 DISTANCE-THE EARLY DEVELOPMENTS
94 THE MAGIC CURTAIN
Winter 2008
28 A PILOT PROTECTION SZSTEM FAILURE
protection
www.
automation
.org
and control
magazine
The Guru:
Sergei Yakovlevich Petrov
page 60
Winter 2008
$7 US
18
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contents
PROTECTION, AUTOMATION & CONTROL WORLD AUTUMN 2007/VOLUME 02
40
4 editorial
10 letters
70
11 news
77
The latest news from the world of electric
power systems protection, automation
and control
18 cover story
Hydro Quebec TransEnergie's system
presents some unique challenges to transmission line protection
94
27 IEC 61850 update
11
An update on the latest developments
related to IEC 61850. Covers the recent
activities of IEC TC 57 working groups.
18
60
56
60
83
Basic legal definitions crucial to the understanding of "negligence"
56 transmission protection
Transmission line protection challemges and
solutions in France, South Africa, Australia
and Brazil
60 the guru: interview
28 lessons learned
Sergei Petrov shares with us the story
of his life and his thoughts about our industry
Analysis of the failure of a pilot protection
system
70 history
34 blackout watch
This is the first article on the developments
of distance protection
Review of recent blackouts or disturbances
around the world
77 I think
36 line constants
Marco Janssen shares his consern about the
future of our industry
Analysis of the measurements of transmission line impedance constants
79 industry reports
40 protection: GOOSE
CIGRE B5 report on the impact of IEC
61850, as well as an IEEE PSRC report on
cyber security are discussed
Implementation and testing of high performance IEC 61850 GOOSE messages
91
55 legal issue
48 protection: 61850
Disscussions on non-conventional instrument transformers and their application for
protection
83 conference reports
Reports on conferences in Brazil, Australia,
Russia, Spain, India and the United States
91 photos of the issue
A selection of photos submitted by PAC
World members is presented
93 book review
94 hobby
PAC World Photo Gallery
presents Transmission Lines
in Digital Art
Andrea Bonnetti takes us behind the magic
curtain -presenting the world of magicians
98 final thoughts
98 events calendar
Go to pages 8 and 68
COVER PAGE: PHOTOGRAPHY BY FILIP 'MIAZGA' MARZEC, ILLUSTRATION BY Terry McCoy
PAC.WINTER.2008
by Alex Apostolov
Comment
from the editor
PAC World
is your forum
One of the goals of PAC World is to be the
forum of protection, automation and control
professionals from around the world where we can
talk about issues of importance to our industry.
To this end we decided to open a discussion in this
issue about transmission line protection.
Some of you may ask, “Why
do you start with this subject?
Transmission line protection has
been around for quite some time.
There are many books and a plethora
of papers and articles about it.” That
is true and is in fact the reason that
drove us to begin with this topic. Let
me explain:
When we have done some task
over and over for many years, using
the same tools, following the same
routine, we create a habit of doing
it in a certain way, regardless of the
functionality of the tool we use. For
example, I am writing this using
Microsoft Word 2003. This very
powerful word processing tool has
many features that can enable me
to make my work more efficient.
However, it will take me time to sit
down and learn how to use them.
However, I have no such time – or
at least this is my excuse. We have
excuses for everything that we do
not believe we need to do. If I can
write this column using the most
basic features of Word, why do I
need to learn the more advanced
features? When I think about it, the
answer is that I probably don’t need
to use Word for this task.
For good or bad, this is not the
only thing I need to write. When
I start thinking about papers and
especially large reports, many of
the features of Word that are not
necessary to write a PAC World
column suddenly become quite
handy. Not that you cannot write a
PAC.WINTER.2008
report without them, but it is much
more difficult and time consuming.
The automatic updates of the
Table of Contents, List of Figures,
spelling and grammar check, text
formatting, etc. now make a lot
of sense. Reflecting back to the
time when mechanical and later
electromechanical (very advanced)
typewriters were used makes me
appreciate the benefits of this new
technology.
I think you already understand
where I am going with these
thoughts about writing columns or
reports. It is because there are many
similarities between what I said and
protection of transmission lines.
For many decades we have
protected transmission lines
using electromechanical and solid
state relays with very limited
functionality. Two – three zones
of phase and ground distance
protection, a second similar or
simpler backup relay, autoreclosing
and maybe breaker failure protection
– that was (and still is in many cases)
what we do. It works. At least it
works most of the time.
Nevertheless, as we discovered
dur ing the North Amer ican
blackout in August 2003 and the
European disturbance in 2006,
when something bad happens, they
sometimes work when they should
not, or not work when they should.
However if we do it right, I believe
that we can almost certainly prevent
any blackout in the future.
For this to happen, we need to:
Understand the existing
protection philosophy
Understand the requirements
of the application
Understand the complete
functionality of the protection
devices that we have available
Keep asking questions and
learning from our and others
experience
To help in this process, to
t r ig ger some thought s and
hopefully generate an honest and
real discussion, in this issue we
asked some leading protection
experts from around the world to
share the challenges they face and
the solutions they apply for the
protection of the transmission lines
in their countries.
I know that it is impossible to
come up with a universal solution
for all transmission line protection
problems. Our intention is to
encourage you to think, to ask
questions, to look for new ideas
that will help us make the electric
power system more secure. Today’s
electric power systems are operated
very close to their stability limit. An
electric power system operating
under such conditions cannot be
successfully protected using the
old technology or moreover by
deploying the new technology in
the same way we used the old.
We can make a significant
difference by taking full advantage
of all features offered by relay
manufacturers in their state-of-theart multifunctional devices.
I know that this is a lot
of work…
but it is worth it!
Solveig Ward
Solveig received her M.S.E.E. from the Royal Institute of Technology, Sweden in 1977
and joined ABB Relays the same year. She has held many positions in Marketing, Application, and Product Management, was responsible for the application aspects in the
development of a numerical distance protection relay and in charge of marketing the product. After transferring to ABB in the US 1992, she was involved in numerical distance
protection design, and was Product Manager for ABB’s line of current differential and
phase comparison relays. Solveig is a member of IEEE, has authored many technical papers and holds one patent. In 2002 she joined RFL Electronics Inc. as Director of Product
Marketing and is involved in development of new products. In her spare time, Solveig
enjoys reading, cooking, crafts and trying to get back in shape.
Job track_ Experience_ Hobby_
contributors
Klaus-Peter Brand
Klaus-Peter Brand received his MS and Ph.D. in Physics from the University in Bonn, Germany. Working in Switzerland since 1976 for BBC and now ABB in different positions,
he was involved in creating the Substation Automation (SA) business and co-authored
the SA Handbook. He is now teaching and consulting at the ABB University. He is active
member of Cigre SC B5. In IEC TC57WG10 he is acting as expert, author and co-author
of IEC 61850 from the beginning. He is Senior Member of IEEE and chair of the Swiss
chapter of IEEE PES. For relaxation Klaus-Peter is reading books with scientific background. As member of the Swiss Alpine Club, he enjoys hiking to the tops of Switzerland. His
well-proven anti-ageing method is the creative confrontation with his growing family.
Andrei Podshivalin
Andrei Podshivalin received his B.Sc., M.Sc. EE and Ph.D. degrees from the Chuvash State
University in Cheboksary, Russia, in 2002, 2004, and 2005 respectively. Since 2001 he
has been with Research Centre BRESLER, Cheboksary, relay protection and automation
equipment producer. His primary research activities are transmission line protection and
fault location. Andrei introduces scientific research into his developments. He has been
first student member (2003) and then member of the IEEE Power Engineering Society.
He likes swimming, playing beach and indoor volleyball, tennis and ping-pong.
He loves traveling. Whatever the event, he makes pictures and
takes part in the PAC World photo contest.
Jorge Miguel Ordacgi Filho
Jorge Miguel Ordacgi Filho is a Professional Electrical Engineer who graduated from Universidade Federal Fluminense. During his carrier as a protection engineer (1974 – 1998)
with FURNAS Centrais Elétricas, Itaipu Hydro and ELETROBRÁS he worked on settings
calculations, analysis, transmission line protection (up to 500 kV) and power plants.
He later joined the Brazilian ISO managing the implementation of special protection systems
and was later involved with Control Center Automation Systems, SCADA, etc. 1975 - 1992
he taught Power System Protection at Universidade Veiga de Almeida in Rio.
Jorge is the Brazilian Member of CIGRÉ SC B5 - Protection and Automation.
He used to play drums - jazz and bossa nova - just for fun. Now his free time is dedicated to
his granddaughter Sofia and Persian cat Ico!
PAC.WINTER.2008
When we decided to
expand our testing
capabilities, we knew
things would change.
Transformation is often a
natural progression. In our world you
either change with the times or you are
gone with the wind.
For years we have been leading
the way, and now with more
expansions, new products
and a larger scope of resources
our test systems reach new
heights... providing new solutions for
your testing needs. For more information,
please call or visit our website.
ing
And now introduc
6
the CMC 35
CMC 256
CPC 100
CPC with CP TD1
CPC with CP CU1
FRAnalyzer
Protection Relay &
Meter Testing
(including IEC 61850)
Transformer &
Substation Testing
Power Factor Testing
Impedance Measurements
Frequency Response Analyzer
CT Analyzer
OMICRON electronics Corp. USA • Houston, Texas • Tel: +1 713 830-4660, +1 800-OMICRON
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continued on pages 26 and 68
GALLERY
Photography by William
Terry McCoy,
Davis.
HawkEye Communications,
Houston, Texas.
The End of the Day
Shot with a Fuji FinePix S9000
Lens: f = 6.2-66.7 mm
1:2.8-4.9
PAC.WINTER.2008
PAC.WINTER.2008
10
letters
Don't hesitate.
Tell us what you
like, and what we
can do better. Share
what you think
your thoughts and
experience.
Please send Tutorial on Protection,
Substation Automation, Communications,
Testing of Protection, IEC 61850 and Fault
& Disturbance Analysis.
I.E Hernan Giraldo
PAC World: Dear I.E., we are not a distributor of any books, CDs, DVDs, etc. On
the web site there is a Tutorial section,
where we intend to post tutorials and
white papers on many issues of interest.
It is up to our readers to share their knowledge with the rest of the industry.
While searching for real world customer
deployment of IEC 61850, I happen to run
into your web site and I am very impressed
with the content and quality.
There isn’t a "whole lot" (information overload) but whatever is there is pure technical/ useful/ real world content - please
keep the web site this way. I would love
to spread the good word about your site
and explore contributing to a column for
Network and Communication focus- to include hardened wired and wireless Ethernet, optical communication for substation
automation and the work I am doing in designing network architectures to support
IEC 61850 and IEEE C37.118 deployment.
A User hit stats by geography would be
a useful aid for users like me who have a
global role. You can place this in the bottom corner. A web master should be able
to slap this.
Pradeep Kumar, IEC 61850 Evangelist
PAC World: Dear Pradeeep, we encourage you, as well as all our readers, to become contributors. Please send an e-mail
to editor@pacw.org with your contribution
or a list of subjects that you can submit
The PAC world magazine is really an excellent effort for educating all protection
and automation professionals and to keep
them aware of latest trends in technology. This is really best for the utilities and
manufacturers.
I will be grateful, if you can tell me about
software for load flow studies, short circuit
calculations, relay co-ordination... etc.
of your country or any other customer,
concerning remote access of protection
relays, fault recorders and data recorders,
for fault analysis, fault statistics and power
quality assessment purposes.
The question is whether it is established
a wide area alarming and supervising system, by which from a central evaluation
center all data, alarms, fault recordings etc
from protection is collected enabling the
timely fault diagnosis and fault analysis.
Consider that in a system the majority of
relays are digital, new substations have
SCADA systems, etc.
Stefanos Sofroniou
PAC World: Dear Stefanos, we hope
that all readers that have any information
to share regarding your questions are going to send it to PAC World, so it becomes
available not only to you, but also to any
other readers that might be interested.
Vikas Marwah
PAC World: Dear Vikas, the Spring 2008
issue of PAC World will have as a main
theme analysis, coordination, modeling...
Please advise us briefly on the practice/experience or if it is included in any
future plans in the electricity company
pac world
Thank you for sending the PAC World
magazine. I enjoyed it a lot. Particularly the
Rogowski coil's article, Mr. Sabato's interview and the PAC History section. It's a
very interesting magazine, because it's not
just a technical one. Congratulations.
João Ricardo da Mata Soares de Souza
address
Editor in chief: dr. Alexander Apostolov (USA)
Advisory Board: dr. Damir Novosel (USA),
PAC World (Email: editor@pacw.org)
Managing Editor: Izabela Bochenek (Poland)
prof. Peter Crossley (UK), prof. Paul Lee (Korea),
8 Greenway Plaza, Suite 1510
Editors: Clare Duffy (Ireland),
prof. Xinzhou Dong (China),
Houston, TX 77046, USA
Christoph Brumer (Switzerland)
prof. Mohindar Sachdev (Canada),
The PAC World magazine is published quarterly by PAC World. All rights
Design Layout: Marek Knap (Poland)
Jorge Miguel Ordacgi Filho (Brazil),
reserved. Reproduction in whole or in part of any material in this publication
Graphic Design: Terry McCoy (USA),
Rodney Hughes (Australia),
is allowed.
Iagoda Lazarova (USA), Dan Serban (Romania)
Graeme Topham (South Africa)
Parent company: OMICRON electronics Corp. USA
PAC.WINTER.2008
industry
+tech
news
11
1
Understanding Cyber
Security
Standards
Electric power system protection,
automation and control devices
perform many functions over
different communications
interfaces. This requires careful
consideration by industry experts in
order to ensure that all developed
standards and recommendations
can be successfully implemented
without causing a decrease in the
performance of any of the system
components or functions.
These are some of the reasons
to start a new task force in the
IEEE PES Power Systems Relaying
Committee (PSRC) to help the
community understand the
requirements of the substation
cyber security standards, such as
NERC CIP, IEEE P1686, IEC 62351.
Steven Kunsman initiated this
effort and chaired a double
session during the joint meeting
of several IEEE PES committees
held in San Antonio, Texas, USA
in the first half of January 2008.
The objectives of the meeting
were to address utility and
vendor issues with cyber security
standards, meet representatives
from various standardization
bodies and identify if a potential
harmonization working group is
required to oversee the various
standardization efforts
After presentations by leading
experts involved in the standards
development and very interesting
discussions, a decision was made
to continue work on this subject for
one more meeting as a task force.
The result will be a proposal to
the Communications and System
Protection subcommittees of the
PSRC to start one or more working
groups that will address the cyber
security issues from the point of
view of different protection and
protection-related applications and
provide input to all standardization
bodies.
PAC.WINTER.2008
Task force
meeting in San
Antonio, USA
you can't miss it
industry news
12
2
Tough Ethernet Switch
Operates in Extreme
Conditions Without
Losing Data
Schweitzer Engineering Laboratories,
I n c . ( S E L ) i s n ow s h i p p i n g t h e
SEL-2725 Five-Port Ethernet Switch,
an unmanaged edge switch and
media converter, Connect the wired
Ethernet ports of four devices to an
SEL-2725 using Category 5 shielded,
twisted-pair cables. Safely link to a
station Ethernet network with the
fiber-optic port.
The SEL-2725 is a tough, reliable
solution for a wide variety of
applications, withstanding vibration,
electrical surges, electrostatic
discharge, fast transients, and
extreme temperatures. It meets
or exceeds IEEE 1613 (Class
2) standards for substation
communications devices and
drops no packets throughout this
rigorous testing!The SEL-2725 is
available now for $450.
4
3
AREVA T&D
opens North American Center
of Excellence
In order to optimize the service level for
its Protection and Substation Automation
customers in North America, AREVA's
Transmission and Distribution (T&D) Division has
created a center of excellence at its existing site in La Prairie, Quebec.
As of December 1st, 2007, Protection, Substation Automation and
associated service activities, currently conducted out of AREVA's
Bethlehem, PA facility in the U.S., are transferred to its Montreal
site. All AREVA's Measurement Products (usually conducted under
the BiTRONICS brand) will continue to be designed, manufactured,
delivered and served from AREVA's factory in Bethlehem and are not
affected by the transfer.
AREVA's North American Protection and Control Center
of Excellence will act as the repair, maintenance and technical
support center for the full installed base of Protection products and
Substation Automation systems in North America. Damien Tholomier,
Commercial Director of AREVA's North American Automation
products said, "We are constantly striving to provide quality, reliable
and high-performance products and systems, along with outstanding
service based on fast response critical to operations. The creation of
this center of excellence in our existing site in La Prairie, Montreal
is just another example of AREVA's dedication to its North American
customers."
Successful Site Trial
of Toshiba’s Ground-Breaking Relay
Toshiba’s new line
differential protection
GRL150 has been
successfully applied
on a 33kV cable-feeder
circuit with UK utility
SP Power Systems.
GRL150 is an advanced
numerical relay which
can act as a direct
replacement for
conventional analogue
pilot-wire differential
relays, connecting
directly to the metallic
PAC.WINTER.2008
pilots via integral
5kV isolation without
the need for external
modems or other
equipment. In addition
to phase-segregated
differential protection,
GRL150 also
provides signalling
channel supervision,
transfer trip, inrush
restraint and back-up
protection functions,
and can also be
applied over fibre
optic communication
links. During the
course of a 1 year trial,
a number of primary
system faults occurred
(both internal and
external to the
protected zone), with
GRL150 performing
correctly in each case,
its communication
system proving highly
robust under severe
conditions in terms of
channel noise.
EID
EID
5
GARD 8000
IEC 61850 Compliant System
The GARD 8000 Communications
and Relaying System from
RFL Electronics, Inc. includes
an Ethernet communication
module that provides a “bridge”
for substation-to-substation
communications in an IEC 61850
application.
The communication media between
the substations can be any of the
media GARD 8000 supports; fiber,
7
T1/SONET (E1/SDH), audiotone or
Power Line Carrier.
Alternatively, the Ethernet
communication module can be used
for teleprotection signaling over an
Ethernet network, using GOOSE
messaging. Back-to-back operating
time is 3 ms (typical) which makes
it an attractive solution for any
teleprotection needs over an
Ethernet network.
Powerful Dynamic Range
Test Equipment
OMICRON electronics proudly
introduces the CMC 356, uniquely
designed for the modern requirements
of protection & control testing
and commissioning/maintaining
substations. It exceeds expectations
with powerful, wide dynamic range
current sources (1mA resolution,
6x32A or 3x64A or 1x128A rms @
max 6x430VA). Unmatched versatility:
test high-burden, electro-mechanical
relays (or an entire panel of them),
up to 12 additional low-level analog
outputs, and optional: IRIG-B sync for
End-to-End or PMU testing, IEC 61850
device testing, or EnerLyzer (analog
measurement)
with just one
test set – it’s a
commissioning
engineer’s
prayer.
Wide Area Coordination Study
of Protection Coordination in the Transmission System
and Boundaries
Initial study results:
Left: 28% of simulations show some type of miscoordination. After readjustment, right: only 1%
of the simulated faults produce a transmission
mis-coordination.
Coordinated operation
Transmission mis-coordination
Detecting a lack of coordination
before relay misoperations occur
reduces risk of interruptions in
service, brownouts, and blackouts.
Automated Wide Area Coordination
reviews are a practical way to
increase system reliability.
Distr./General mis-coordination
In 2006, Rede Eléctrica de España
(in Madrid) conducted a wide area
review of protection coordination in
a large portion of their transmission
network, including the boundaries
between generation, transmission,
and distribution. Their study used an
Coordination-cannot be solved
automated application of Electrocon
International’s CAPE software,
uncovering hidden miscoordinations
and other protection problems.
You can request the 2007 WPRC technical paper:
eii@electrocon.com or www.electrocon.com
PAC.WINTER.2008
you can't miss it
6
GARD 8000
industry news
13
you can't miss it
industry news
14
Remote HMI
PAS CC Client
WinCC
8
Non-Operational
Data Access
Enterprise
Accessing breaker wear, fault records and
oscillography from relays is now easier through
the use of a set of software tools for the Orion
Automation Platform. NovaTech's Orion Software
Suite includes tools to:
Access relays remotely, through Orion
Make Breaker Wear, History and Short Event
Summaries available to SCADA
Automatically retrieve, parse and disseminate
Full-Length Event Report to enterprise PCs
Display relay data on pre-formatted web pages
served from Orion.
Traditional automation function, such as
accessing SCADA data, retrieving time stamps
and sending down IRIG-B, are also supported in
the Software Suite.
Local HMI
SICAM PAS CC
WinCC
Relays
SIPROTEC
IEC 61850
Ethernet/Profibus
PC - SICAM
PLC - S7
MODBUS/CANcus
Hard Wire DVR
Fiber
PAC.WINTER.2008
9
Generator Protection
Control
The SICAM &
SIPROTEC Generator
Protection, Control
& Monitoring System
is a complete ready
to install solution for
local plant power
generation and
distribution systems.
The system is suitable
for integration into
most generator
manufacturer's digital
engine and voltage
controls. It can be
extended into other
distribution switchgear
l ineups to provide
Switch
Engine
& DVR
Control
Substation
Electrical
complete automated
logic control and
interlocking for entire
distribution systems.
The settings of the
relays are included
and all functionality
is tested and proven
prior to delivery.
Generators can be
securely paralleled
using the 7VE6 Relay
synchronization
algorithms.
An HMI provides clear
local or remote control
& monitoring. The
system architecture
is designed to digitize
all pieces of primary
gear. This information
is then shared on a
common IEC61850
bus with peer to peer
"GOOSE" messaging.
Unlike standard
solutions available
in the market, this
system does not
require any additional
control hardware for
generator paralleling.
This sytem is complete
protection control and
gererator paralleling
solution using
SIPROTEC relays and a
PC or PLC.
1
technology news
15
Wireless
Power Transfer - it is Real!
I believe everybody was happy when we
were able to get rid of all the phone and Ethernet
cable and connect to the Internet using WiFi. But
we still need to plug in all our electronic devices to
charge their batteries. An d with all of them having
different adaptors, connectors, voltage levels, etc.,
they create a big mess around us. The dream for
wireless power transfer is not something new.
A team from MIT's Department of Physics,
Department of Electrical Engineering and
Computer Science, and Institute for Soldier
Nanotechnologies (ISN) has experimentally
demonstrated an important step toward
accomplishing this vision of the future.
The team was led by Prof. Marin Soljacic. Realizing
their recent theoretical prediction, they were able
to light a 60W light bulb from a power source
seven feet (more than two meters) away; there
was no physical connection between the source
and the appliance. The MIT team refers to it as
"WiTricity" (as in wireless electricity).
Various methods of transmitting power wirelessly
Magnetic
Theory
Experimental k
have been known for centuries. Perhaps the best
known example is electromagnetic radiation, such
as radio waves. While such radiation is excellent
for wireless transmission of information, it is not
feasible to use it for power transmission. Since
radiation spreads in all directions, a vast majority
of power would end up wasted into space.
WiTricity is based on using coupled resonant
objects. Two resonant objects of the same resonant
frequency tend to exchange energy efficiently,
while interacting weakly with off-resonant
objects. The MIT team focused on magnetically
coupled resonators. The team explored a system
of two electromagnetic resonators coupled mostly
through their magnetic fields. They were able to
identify strongly coupled regime in this system,
even when the distance between them was several
times larger than the sizes of the resonant objects,
thus enabling efficient power transfer
The team
members are
Andre Kurs,
Aristeidis Karalis,
Robert Moffatt,
Prof. Peter Fisher,
and Prof. John
Joannopoulos
(Francis Wright
Davis Chair and
director of ISN),
For more information go to
led by Prof. Marin
http://web.mit.edu/newsoffice/2007/wireless-0607.html
Soljacic.
Experiment
1.0
coupling is
0.9
particularly
0.8
0.7
suitable for
applications
because most
common
materials
interact only
very weakly with
0.5
(Efficiency)
everyday
0.6
0.4
0.3
0.2
0.1
0.0
75
100
125
150
175
Distance (cm)
Wireless Power Curve
Experimental Setup
KS
200
225
Wireless power transfer demonstration
K
Details on
KD
A
the principles
B
and setup are
available at:
magnetic fields
S
D
http://www.
sciencemag.org
PAC.WINTER.2008
consider future applications
technology news
16
Image cortesy
2
Impact of Sun Storms on GPS
based devices
The impact of sun storms
on electric power grids
has been subject to many
papers, articles and reports
during the last two decades.
System disturbances caused
by solar activity can disrupt
complex power grids due to
the geomagnetically induced
currents (GIC) resulting from
the interaction of the Earth's
magnetic field and ionized
particles carried by the solar
wind. Severe magnetic storms
induce electric fields in the
Earth that create potential
differences in voltage
between grounding points
and causes GICs to flow
through transformers, power
system lines, and grounding
points.
The appearance of a spot
(an area of highly organised
magnetic activity) on the
surface of the Sun that
produced two solar blasts
in January 2008 signalled to
scientists around the world
the beginning of a new solar
cycle - ‘Cycle 24’. Each solar
cycle lasts an average of 11.1
years. This cycle is expected
to build gradually, with the
number of sunspots and solar
storms reaching a maximum
by 2011 or 2012. However,
intense solar activity can
occur at any time. More
information on this new cycle
is available at: http://www.
esa.int/esaCP/SEMT1J3MDAF_
index_0.html
The impact of solar activity
on the power grid is not the
only concern for protection
specialists. The last few
years have seen a significant
increase in the interest and
use of synchrophasors. The
wide acceptance of IEC
61850 and the benefits of
process bus will lead to the
replacement of copper analog
circuits with fiber cables
transmitting sampled analog
values. Both technologies
require time synchronization
Artist Interpretation of GPS satelite
of NASA
Composite Sun Flare Image: cortesy of NASA
with accuracy better
than 1 microsecond. Time
synchronization of different
intelligent electronic devices
(IEDs) in substations is based
on GPS signals.
The concern regarding the
impact of solar activity on
time synchronization of
substation devices is based
on the fact that a solar
flare creates radio bursts
that traveled to the Earth,
covering a broad frequency
range, affecting GPS and
other navigational systems.
The radio waves act as noise
over these frequencies,
including those used by
GPS and other navigational
systems that can degrade a
signal. Several major events
of such nature have already
occurred. For example
the satellite-based GPS
was seriously disrupted in
December 2006 by a solar
storm. The unexpected solar
radio burst on December
6 affected nearly all GPS
receivers on the lighted half
of the Earth.
The impact of GPS systems
failure on the performance of
critical electric power systems
protection and control
functions needs to be studied
and well understood in order
to determine if any changes
in the design of devices with
time synchronization are
required
See: http://www.noaanews.noaa.gov/stories2007/s2831.htm.
PAC.WINTER.2008
17
3
Microsoft "Surface"
Puts People in
Control
Imagine being able to place a relay on your desk,
and the desk suddenly comes alive, pops-up the
settings of the distance zones, shows the loading
of the transmission line it is installed on and the
apparent impedance seen by the relay, while at
the same time your colleague is looking at the
COMTRADE file from the latest relay operation.
This and much more will be soon possible with
the recently announced Microsoft Surface.
“With Surface, we are creating more intuitive
ways for people to interact with technology,” CEO
Steve Ballmer said. It is designed to put people
in control of their experiences with technology,
making everyday tasks enjoyable and efficient.
Microsoft Surface provides an intuitive
user interface that works without a traditional
mouse or keyboard, allowing people to interact
with content and information on their own or
collaboratively with their co-workers, just like
in the real world. Surface is a 30-inch display
in a table-like form factor that small groups
can use at the same time. It also features the
ability to recognize physical objects that have
identification tags similar to bar codes. When a
user simply sets a device on the surface of a table,
the system could provide information about the
object they are using, the tools that can be used
with it, its configuration or maintenance history,
the devices it is communicating with and a lot
more.. The experience could become completely
immersive, letting users access information on
similar products, the state of the system and
the potential need for adjustments or change of
setting groups or a virtual test of the relay under
the system conditions combined with a predefined type of fault at a location you just pointed
your finger to on the system one-line diagram.
Surface computing, features four key attributes:
Surface computing
recognizes points of
contact.
Microsoft
Surface is
designed as a
30-inch table
like display.
To share your ideas
about what we can do
with Surface, please
send an e-mail to:
editor@pacw.org
Direct interaction. Users can actually “grab”
digital information with their hands, interacting
with content by touch and gesture, without the
use of a mouse or keyboard.
Multi-touch. Surface computing recognizes
many points of contact simultaneously, not just
from one finger like a typical touch-screen, but up
to dozens of items at once
Multi-user. The horizontal form factor makes
it easy for several people to gather around surface
computers together, providing a collaborative,
face-to-face computing experience
Object recognition. Users can place physical
objects on the surface to trigger responses,
including the transfer of digital content
Surface computing at Microsoft is an
outgrowth of a collaborative effort between the
Microsoft Hardware and Microsoft Research
teams, which were struck by the opportunity to
create technology that would bridge the physical
and virtual worlds. What has started as a highlevel concept has grown into a prototype and
evolved to today’s market-ready product that will
transform the way people work and live It’s a
major advancement that moves beyond the
traditional user interface to a more natural way of
interacting with devices and information and can
revolutionize the PAC world as well
PAC.WINTER.2008
Microsoft
Surface
creates a new
environment
that
allows the
development
of a new
range of
power system
engineering
tools and
applications
By SSimon
imon Chano
Cha
no HQT Cana
no,
Canada
da
Chano,
Hydro-Québec TransÉnergi
TransÉnergie
ie ((HQT
(HQT)
HQT)
Q ) oper
operates
p ates
t tthe
he mostt e
extensive
xte
t nsive
i transmiss
transmission
i ion sy
system
stem
t
iin
nN
North
orth
th A
Ameri
America.
ica. TTo ensure correctt operati
operation
tion
of the protection system under many different abnormal conditions, HQT uses redundant sets of protective relaying schemes to
NPCC
improve reliability by increasing the availability of the protection system and follows the N
PCC criteria to ensure that protection
systems are designed to per
p
perform
form in accordance to high degree of dependability and security.
by Simon Chano, HQT, Quebec, Canada
Transmission Line Protection
cover story
20
Simon R. Chano
began his career
at Hydro Québec
as a protection
and automation
engineer in 1979.
His primary focus
has been in the
areas of protection
settings and relay
coordination of EHV,
HV, MV and LV networks. He is Senior
Member of IEEE and
Member of CIGRÉ
B5 committee. He
served as Chair in
many IEEE PSRC
working groups and
was Chair of the "K"
Substation Protection Subcommittee
of PSRC.
He is the Secretary
and Convenor of several CIGRÉ B5 working groups. He has
lectured graduate
and undergraduate
electrical engineers
on various programs
with several Canadian universities.
Each bulk transmission
line is equipped with two
independent protection
systems capable of clearing all
faults in the shortest
practical time.
The Hydro Québec Transmision Grid
Hydro-Québec TranÉnergie (HQT) operates the most
extensive transmission system in North America. The system
comprises 32,826 km of lines at different voltages ranging
from 765 kV to 69 kV or less that deliver reliable power from
508 transmission substations and 18 interconnections to
customers in Québec, other parts of Canada and the United
States. Extreme long 735 kV transmission lines of more than
1,000 km from James Bay and the Manic-Outardes complex
deliver a winter peak load of 36,251MW in 2007 mainly
from 54 hydroelectric generating stations. Almost 96% of
the installed system capacity is from hydroelectric generation
serving customers throughout a territory of 850,000 sq. km.
To offset the effects of distance between generating facilities
and load centers, and maintain in the mean time a reliable
and secure system, HQT has installed series compensation
on many strategic 735 kV lines to enhance the system
robustness . Today, HQT uses different modes of reactive
power compensation to control the voltage and employs a
multi-terminal direct current link from northern Québec to
NEPOOL over a distance of 1,200 km.
Hydro-Québec TransÉnergie within a regulatory
context
For the bulk system, HQT must meet all regulatory
requirements as per the North American Electric Reliability
Council (NERC) and the Northeast Power Coordinating
Council (NPCC). NERC sets operating and planning criteria
to ensure reliable power system operation. On the other
hand, NPCC of which Hydro Quebec is a member, establishes
reliability criteria for all power systems in the Northeast.
HQT coordinates its activities with the "Régie de l'énergie
du Québec" (RÉQ) which has the role to establish or adjust
transmission rates and conditions, authorize the acquisition,
construction or disposal of transmission assets and study
customer complaints regarding application of transmission
tariff.
HQT Approach to Bulk Transmission Line
Protection
HQT uses redundant sets of protective relaying schemes
to improve reliability by increasing the availability of the
protection system and follows the NPCC criteria to ensure
that protection systems are designed to perform in accordance
to high degree of dependability and security. In this regard,
PAC.WINTER.2008
dependability is related to the degree of certainty that a
protection system will operate correctly when required
to operate. Security relates to the degree of certainty that a
protection system will not operate when not required to
operate. Redundancy at HQT is considered with a special
focus on simplicity, operational and maintenance flexibility
. Operational flexibility is desirable for maintenance
considerations by allowing the transmission line to remain
in service with one set of redundant protection out of
service.
Implementing the Rules
Each bulk transmission line is equipped with two
independent line protection system capable of clearing all
faults in the shortest practical time with due regard to
selectivity, dependability and security. The total clearing time
of every protection system is coordinated with the stability
margins of the network.
Every protection system should not constitute a loading
limitation nor should it be affected by any stable system
swings.
Every protection component including control cables
and wiring has physical separation to minimize the risk of
disabling both protection systems by fire or accidents.
Both protection systems " Main 1 and Main 2" are
provided in separate panels. They are supplied from separate
voltage and current secondary windings.
Communication channels and equipments associated to
both protection systems have physical separation to minimize
the risk of disabling both protection systems by a single event
or condition. In the early 90's, two different communication
paths were used on analog microwave - direct end-to-end
path between two substations and a loop path through
different substations before arriving to final destination. At
the present time, HQT has migrated the majority of its
microwave analog communication means to digital
microwave radio and implemented optical fiber in order to
make better use of these technologies. Physical path separation
of telecommunication for both protection systems is possible
with optical fibre. However, should the microwave radio
tower collapse, a common failure mode will not be avoided.
1 Hydro-Québec within a regulatory context
NERC
HQT
NEB
National
Energy
Board
NPCC
R
É
Q
Régie de
l'énergie
(Québec)
Remote Back-up
Remote back-up protection is completely independent of
the main local protection devices including their associated
current and voltage transformers, auxiliary D.C. supply
system and breakers. In general, remote back-up has a certain
degree of limitation and requires special considerations
regarding the operational strategy of the system. Protection
selectivity, sensitivity and speed are some additional factors
that need to be considered if remote Back-up is envisioned.
Local Back-up
Local back-up is applied at the local Station to trip local
breakers in case the primary protection fail to operate. If the
primary relays fail, Local back-up relays will trip the local
breakers. Local Back-up offers faster clearing time than remote
Back-up and limit CB tripping to one location. Breaker failure
protection is initiated locally if CB fail to trip. Local back-up
can be subdivided into two groups: Substation local back-up
and Circuit local back-up.
Substation Local Back-up Protection
Although powered by the same DC supply of the
substation, this form of local back-up protection is similar to
remote back-up as it is independent of the primary protection
devices including CTs, VTs and other auxiliary trip devices.
Substation local back-up offers protection to faults in
outgoing transmission lines with certain limitation in meshed
networks which constitute short, medium and long lines.
4
2 Series compensated transmission line - Current Reversal
E
VR
IS
VR
IS
Microwave Tower
E
IR
E
IR
IS
E
Transmission Line Protection
Two station service ac supplies are provided in each
substation capable of carrying all critical loads associated with
the protection systems.
Every protection system is supplied from separate direct
current (dc) supply and charger in order to ensure proper
operation despite the loss of a single dc source.
All circuit breakers for Extra High Voltage (EHV) and
Ultra High Voltage (UHV) systems are provided with two
trip coils and each independent system protection initiate
tripping to both of the breaker's trip coils.
Back-up Protection issues
The term "Back-up" is normally looked at from the point
of view of dependability but at the expense of security in the
advent of incorrect operation of the primary protection. In
normal life, events may cause circuit breakers and associated
equipment not to always operate correctly and as a general
practice, it is necessary to take some remedial measures
to successfully isolate the fault on the system. Back-up is
considered as a device that operates independently within a
certain coordinated time delay with the associated primary
protection functions.
The main protection and the back-up protection may
sometimes be provided in a different substation (Remote
Back-up) or in the same substation (Local Back-up). In case
of Local Back-up, a special consideration is given between
substation Local Back-up and Circuit Local Back-up.
cover story
21
IR
F
XC
XS
XC
>
XR
XL
S
R
XS
Main 1 Superimposed directional principle
Main 2 Current differential principle
Back-up Impedance measurement
3 Series compensated transmission line - Voltage Reversal
Microwave
E
E
VR
IL
IR
IR
channels
IR
VL
VL
XSL
to ensure
XC
F
XSR
XL
E
E
IL
XC
Main 1 Impedance measurement
are used
clearing
IR
< XSL
Main 2 Phase comparison
fast fault
Back-up Modified impedance
PAC.WINTER.2008
Transmission Line Protection
cover story
22
Circuit Local
Back-up Protection
Due to limitations
in remote back-up,
Circuit local back-up
protection operating
on different principles
or not subjected to the
same conditions as the
primar y protection
dev ices c an play a
favorable role in the protection of transmission lines. For
example, the HQT 735 kV series compensation transmission
lines have communication dependent schemes in both main1
and main2 protection devices. In this case, it is important
to assume a communication independent Circuit local
back-up scheme of a different principal. An impedance based
measurement protection scheme is an ideal Circuit local
back-up protection in this case.
Breaker Failure Protection
At present, HQT uses one set of independent Breaker
Failure protection scheme. This is viewed as part of the Local
Back-up protection scheme. The Breaker Failure protection
trip the adjacent breakers when the main breaker does not
interrupt the fault current. Each of the redundant relaying
systems independently initiate the breaker failure function as
needed. In general, breaker failure logic based on overcurrent
detection is commonly used but in some cases, this function
is also achieved by breaker auxiliary switches.
HQT Series Compensated Transmission Lines
Since the early 90's, HQT has implemented series
capacitors on the 735 kV EHV transmission system mainly to
increase the power transfer capability and improve the system
stability. The transmission grid which carries high power
over long distances play a key role in areas with bulk power
transmission, where power generation plants are more than
1000 km away from load centers.
Based on extensive system studies, series capacitors
were mainly installed at one end of the line and in some
locations, in the middle of the transmission line. The level of
compensation varied between 20 to 44% of the transmission
line impedance. Common and crucial issues that need to be
considered are in terms of correct relay selection, logic, setting
and testing yielding to adequate protection performance.
Transient simulator testing was determined to be the most
effective approach to study all complex issues in relation to
weak in-feed, harmonic and sub-harmonic components,
superimposed on fault current waveforms, low frequency
current oscillation, the effect of zero sequence mutual
impedance of parallel lines, voltage and current reversals,
shunt reactor switching and line reclosing are also issues that
need to be considered.
Short-circuit currents are also influenced by series
capacitors. To protect the capacitor during high levels of
short-circuit currents, the series capacitor is protected with
air-gaps, metal oxide varistors (MOVs), current limiting
PAC.WINTER.2008
devices, and bypass switches. Operation of air-gaps and
conduction of MOVs introduce transients and unbalances that
must be taken into consideration to ensure that the integrity
of the line protection scheme is not adversely affected.
Issues Related to Series-compensated Lines
The effect of series compensation on transmission
line distance protection depends on the location of the
series capacitors, the degree of compensation, network
configuration, and line parameters. The most common effect
of series capacitors is voltage reversal. For this reason it is
absolutely essential that the line protection use the polarized
or the memorized voltage for the determination of the fault
direction on series compensated lines.
Figure 3 shows a typical voltage inversion at Bus L
assuming a three phase fault with XC < XSL. Current inversion
could also take place in a series-compensated network.
This takes place when the reactance from the fault point to
and including the source reactance is net capacitive. Figure
2 illustrates the condition for current reversal. However,
during the TNA simulation studies at the research institute of
Hydro-Québec (IREQ), current inversion was not observed
due to the level of series compensation together with the
ZnO protective arrestors across the series capacitors.
HQT Series Compensated Transmission System
Criteria
A strict total fault clearing time is imposed on the HQT
series compensated transmission system. All circuit breakers
provided for these lines have isolation capability between
33 to 42 ms. All circuit breakers tripping orders are three
phase initiation. Reclosing is only permitted on single phase
faults. Priority to reclose first on line ends away from series
capacitors. All protection and control schemes block reclosing
at the remote end of the line when reclosed on permanent
faults.
Transmission Line Protection
Communication channels & equipment
associated to both protection systems
should have physical separation.
Series capacitors
on the 735 kV
EHV transmission
system increase
power transfer
and improve
system stability.
Relay Selection
Many relays were put on extensive
TNA testing program at IREQ but only two types of
Main protections have passed all tests according to the
HQT criteria within the timeframe of the testing period.
The non-communication based Impedance relays were also
carefully evaluated according to the real topology of the series
compensated network. For all relays, settings were evaluated
in real time testing according to various philosophies and
relay characteristics. It was noted that the modified starting
unit characteristics of those relays gave good results and
restrained from false operations during all type of faults and
during normal system switching. See Figures 7, 8.
Superimposed Directional Detection Principle
This principle is based on voltage and current deviation
where the incremental impedance Δ Z is computed based on
the phasor difference between the voltage during the fault V
D and the voltage immediately prior to the fault V A divided
by the phasor difference between the current during the
fault and the current immediately prior to the fault. The use
of superimposed components allows the relay to determine
the direction of a fault very quickly, typically in 4 ms. This
type of protection is totally communication dependent
with the remote terminal of the line and provide ultra high
speed tripping if no blocking signal is received from the
remote end of the line. The transient change of ΔV and Δ I
for a forward line fault initiated on the positive cycle of the
voltage waveform will be located in the II and IV quadrant
as illustrated in the figure 5. Settings fix the boundaries for
cover story
23
the relay to emit a trip signal in the dependent mode to the
remote end and to block for normal line and shunt reactor
switching. See Figures 5, 6.
Current Differential Principle
The scheme is based on a percentage bias current
differential principle, and respond according to the operating
and restraining characteristic. This principle passed all TNA
tests which included stable and unstable power swings. The
integrity of the communications channel is very important
for the operation of this scheme. Analog communication
channels if used have to be reliable. Digital fiber-optic
communication channels are rapidly replacing the analog
channels for high-capacity performance and speed. However,
communication interfaces and propagation delays between
the sending and receiving end of the line gave conclusive
results during the early series compensation on the system .
This simple current differential technique can be used for all
type of series compensated or uncompensated lines regardless
of the length of the lines since it is not affected by voltage
reversals for faults near the series capacitors nor it is affected
by low fault current contribution from the remote end of the
line. Adequate settings, proper CT selection, Channel-delay
asymmetry, CT saturation and out-feed current are issues
worthwhile the attention for this particular scheme.
Phase Comparison Principle
The scheme is channels communication dependent. The
relay compares the local square wave and the received remote
square wave on one half-cycle. A trip permissive signal is
asserted only for internal faults. See Figure 9.
Series compensated lines Back-up Protection
As Main 1 and Main 2 series compensated protection
lines are totally dependent on communication channels, an
impedance based measurement relay was also selected as
a result of TNA testing. The starting element controls the
PAC.WINTER.2008
Transmission Line Protection
cover story
24
The effect
6 Superimposed voltage and
5 Superimposed directional principle
(+)
V
VA
II
current
VA
I
VD
V (t)
0
(-)
ID
I
V
(+)
V (t)
III
(-)
IV
measurement elements and has a modified lens characteristic
to avoid being sensitive to load and power oscillations. From
careful settings, all back-up impedance based measurement
relays selected for series compensated lines were stable for all
transient conditions and dynamic series compensation issues
on the system.
HQT General Guidelines for the 735Kv to 69Kv
Transmission Lines
Overhead transmission lines have to be protected
against phase and ground faults. Today's HQT practice is
to provide two redundant line protection schemes from
different manufacturers and in some cases an additional
individual back-up scheme. The primary protection schemes
are considered as Main 1 and Main 2 or protection "A" and
protection "B". The numerical relays are connected to separate
7 Series capacitors
of series
0
t
IA
CT coils and voltage transformer (VT) coils. Where possible,
the tripping signals are sent to separate tripping coils of the
circuit breaker (CB). The communication medium is usually
by fiber-optic (FO) and digital microwave. There are fewer
applications with PLC and analog radio microwaves.
Other multiple adequate schemes could also be envisioned
depending on system studies and requirements.
Auto-reclosing Function
Since the majority of line faults are transient in nature, it
is necessary to de-energize the faulted phase and allow for arc
de-ionization before initiating a reclose command to circuit
breakers. Only three phase automatic reclosing is used on the
735 kV transmission system initiated by single phase fault
detection. Depending on certain applications, some principles
are used:
installed at the beginning of the line
R
XC
ZS R
compensa-
S
ZL
ZS S
tion on
Relay
transmission
line distance
protection
Main 1 Superimposed directional principle
8 Series capacitors
Main 2 Current differential principle
Back-up Impedance measurement
installed at mid section of the line
R
depends on
ZS R
XC
S
ZL
ZS S
the location
of the series
capacitors.
t
Relay
Main 1 Impedance measurement
PAC.WINTER.2008
Main 2 Phase comparison
Back-up Modified impedance
9 Phase comparison protection
Substation
"A"
Functional testing plays an
important role in ensuring
correct protection
operation.
a certain delay on operation and drop-out. Another method
of communication will be to connect a optical fiber between
two identical relays using the integrated communication
technology within the protection devices.
List of functional tests
During the tests for internal and external faults, closing
and drop-out contact time are measured for all type of
distant position faults. Fault incidence angle is varied (ex. 20
faults/cycle; every 18 deg.) and the tests are performed for:
Short Lines; Long lines; Strong or weak sources ; Mutual
coupling lines; Series compensated lines; CT and CVT
models, etc. Other tests are performed to verify: SOFT; Fuse
Supervision; Resistive faults; Evolving faults; Reclosing on
permanent faults; reclosing logic functions; "Weak- infeed"
logic; Instantaneous overcurrent to verify speed, sensitivity,
directionality and hysteresis. Also included in the test
program are the following functions: Current reversal; SIR;
Load encroachment logic; CT Saturation ; Harmonics;
Breaker failure; Phase discrepancy; Power oscillation; Fault
Location; Overvoltage/Undervoltage detectors; Current
Supervision; Grounding tests, Frequency tests; CVT
Modelling; Three terminal lines with outfeed, etc.
- Internal fault condition
I
F
X
I KEY
Substation
I
"B"
S
I KEY
LP
LN
LP
LN
Signal TP
Reception TN
{
TRIP
1
0
1
0
1
0
TP
TN
}I
KEY
PAC.WINTER.2008
Transmission Line Protection
Single phase auto-reclosing is easily achieved by line
differential protections, where faulted phase segregation and
separate trip outputs are provided.
Single phase auto-reclosing is also achieved by
permissive under-reach distance protections, provided the
use of 4 independent acceleration channels per line protection
function. A logic confirming the presence of zero sequence
current is conditioned with the acceleration signals.
Three phase or single phase auto-reclosing for other high
to low voltage transmission system are subjected to system
studies. Multi-phase faults could also initiate three phase
auto-reclosing in special cases provided that the system is not
impacted.
Functional Relay Testing
List of Functional tests for Line protection
The functional testing of protection relays plays a very
important role in ensuring their correct operation when
installed in the field. The functional tests listed in this article
are viewed as specific tests during the process of protection
verifications. The inclusion of specific functional tests is
typically required in order to verify a specific application on
the power system or to verify a specific application based on
previous "lesson learned" undesired relay behavior as a result
of a disturbance. This functional relay testing list is used by
test personnel to define the test program carried on tools
such as" Hypersim" transient network simulator and other
standard test boxes.
Functional type test implementation strategy
The majority of functional type tests performed on
distance relays are based on individual relays. However,
certain tests are carried out according to a complete protection
scheme to include two distance relays with communications.
The latter will be a simulation of a tone unit which includes
cover story
25
continued on pages 8, and 68
GALLERY
Photography by William Davis.
Crossroad
Shot with a Olympus E510
Lens: f = 14-42 mm
1:3.5-5.6
PAC.WINTER.2008
by Christoph Brunner
Funtional
Hierarchy
During the recent IEEE relay meeting, the issue about functional hierarchy was once again raised and the
question was asked, whether this will
be addressed in IEC 61850, Edition 2
and if yes, how? The short answer is
yes – that will be addressed. It is described as "management hierarchy" in
the current draft of IEC 61850-7-1,
Ed 2..
For the long answer, we will
need to have a look at some technical
details of IEC 61850. As a reminder:
in IEC 61850 logical nodes are
modelling functional elements
or more precise, the information
of functional elements that is
externally visible and accessible
through the communication. An
example is the logical node called
PDIS that is the information model
of a distance element. Logical devices
are a grouping of logical nodes.
One purpose of that grouping is to
provide the possibility to enable
or disable a function that is created
out of multiple logical nodes. This
is possible by enabling or disabling
the logical node zero (LLN0)
that contains the information of
the logical device. Alternately,
it is possible to enable or disable
individual functional elements by
enabling / disabling the specific
logical node.
An IEC 61850 IED can have
multiple logical devices that contain
multiple logical nodes. A logical
device can not contain another
logical device. This hierarchy is as
well reflected in the mapping on
MMS according to IEC 61850-8-1
and in the naming of the logical node
instances. A logical device maps on
an MMS domain; a logical node on
an MMS named variable within that
domain.
Unfort unately, real life is
sometimes more complicated than
models. If you take the example
of a multifunctional protection
relay, one function may be an
overcurrent function. Within that
we may find the phase overcurrent
and the ground overc ur rent
subfunctions. these subfunctions
will be implemented with multiple
instances of logical nodes (e.g.
PTOC, PIOC). To reflect hierarchies
as described in that example, IEC
61850, Edition 2 will support
a nesting of logical devices. As
mentioned above, the logical node
LLN0 is representing a logical
device. For Edition 2, a data GrRef
(group reference) will be added to
LLN0. This is a pointer to another
LLN0 that represents a logical device
at a next higher hierarchical level.
Taking the previous example,
we will have one logical device (e.g.
"gnd") for the ground overcurrent
protection subfunction and one
logical device "phs" for the phase
overcurrent protection subfunction.
We will have a third logical device
"ocp" for the overcurrent protection
function. In both LLN0 of the
logical devices "gnd" and "phs", the
data GrRef will point to "ocp". This
means that the logical devices "gnd"
and "phs" are a part of the higher
level function "ocp" represented by
that logical device.
As a consequence, the logical
node LLN0 of the logical device "ocp"
will control all its subfunctions. E.g.,
if the mode of ocp.LLN0 is disabled,
this will have an impact on all logical
nodes of the logical devices "gnd"
and "phs". This functional hierarchy
will however not be reflected in
the data structure. The name of the
logical device "gnd" will not include
"ocp" as its parent logical device.
Also, a directory service applied
on the logical device "ocp" will not
return the logical devices "gnd" and
"phs".
The working group plans to
release the major parts of IEC 61850
as Edition 2 CDV (Committee Draft
for Voting) in February this year.
They will be translated to French
and circulated in April. Please check
with your national committee or
the UCA International Users Group
to receive these CDVs for a review
and provide your comments! Your
feedback is important to make these
standards such that they fulfil all
requirements.
PAC.WIINTER.2008
IEC 61850 update
27
by Collin Martin, Oncor Electric Delivery
Protection Failure
lesson learned
28
A Pilot
Protection
System Failure an
Investigation
Protection system failures are sometimes hard to detect, especially
in the case of electromechanical
relays with no inherent self-testing
or alarming. It often takes a misoperation of the protection system and
the following investigation to discover the problem. At this point it
is too late and the damage is already
done. This paper examines an event
on the Oncor Electric Delivery system in which a critical customer, normally served by four
138kV transmission lines, was left hanging on a single feed due to a fault and two relaying system failures. Subsequent investigation revealed that both relaying system failures had been
present for extended periods of time. Recommendations for future changes are presented.
1 System Configuration 6.5 Cycles into Fault
The fault is no longer a simultaneous fault, but is a single-line-to-ground fault
W KIRKLAND E
PARK
015
122
Cap
Bank
138 kV
UG Cable
#1
6.99 mi
012
555
032
6.5 -
012
015
SCHROEDER
ROAD
5035
1.14mi
055
Northaven
052
Greenville
022
Centerville
032
Centerville
042
0.83 mi
121
#1
JUDD
COURT
0.46 mi
122
#2
045
042
0.0 mi
022 6.99 mi 035
012
055
042
CLTE
138 kV
UG Cable
0.5 mi
121
#1
WALNUT
ST
AIR
LIQUIDE
015
Auto
RENNER SW
138 kV
666
0.89 mi
A-G Fault
045
025
345 KV
NHVN
DALLAS
0.46 mi
0.40 mi
138 KV
050
050
121
1.57 mi
032
022
PAC.WINTER.2008
4.5 -
0.74 mi
Northaven
035
052
Greenville
025
042
121
#2
0.17 mi
#1
North Central Expressway
US 75
COIT
ROAD
0.17 mi
Collin M. Martin
received his B. S. in
Electrical Engineering from Texas A&M
University in 2002
and his M. E. in Electrical Engineering
from Texas A&M University in 2003. He is
currently employed
by Oncor Electric
Delivery as the
Protection & Control
Manager for the
Odessa/Big Spring/
Sweetwater district.
Before moving to
Odessa he was a
Senior Engineer in
their System Protection group. Collin is a
licensed professional
engineer in the State
of Texas.
Cap
Bank
2
The cause of the
failure to send a trip
permissive is improper
functional testing
during checkout
Relay coordination is challenging because of the number of short
lines in the area as well as the number of Y-Δ-Y transformers and their
FID ratings. Within just the four
lines serving Dallas there are twenty-one Y-Δ-Y distribution transformers which are zero sequence
current sources.
FID ratings can cause coordination problems because they are
blocked from tripping for faults
over 16,000 amperes. Relays on
both ends of the line must trip for
the 16,000 ampere faults because
of the POTT pilot logic used. This
requires unusually large distance
relay reach settings because fault
duties in the corridor range from
30,000 – 60,000 amperes.
Oncor Electric Delivery maintains an extensive digital fault
recorder (DFR) network. Approximately 230 DFRs are scattered
around the system and capture
more than 15,000 records a year.
After the records are collected, they
are automatically converted into
a standard report and sorted into
low, medium, and high priority
groups. The low priority group accounts for 95% of the records and is
generally made up of records triggered by remote faults that contain
limited useful information. The
medium priority group consists
of correct fault operations and accounts for about 4% of the records.
The high priority group is made up
of the remaining 1% of the records
that indicate possible slow breakers, slow relays, breaker failures, or
carrier problems.
System Configuration After Fault was Cleared
Dallas is being served by a single 138kV line from Renner CB 035
015
122
Cap
Bank
138 kV
UG Cable
#1
DALLAS
6.99 mi
0.46 mi
0.40 mi
032
012
555
42 -
666
6.5 -
012
025
015
SCHROEDER
ROAD
035
1.14mi
055
Northaven
052
Greenville
022
Centerville
032
Centerville
042
0.83 mi
121
#1
JUDD
COURT
0.46 mi
122
#2
042
0.0 mi
0.89 mi
5-
045
022
345 KV
NHVN
1.57 mi
032
138 KV
050
050
121
0.74 mi
Northaven
035
052
Greenville
025
042
4.5 -
0.17 mi
W KIRKLAND E
PARK
121
#2
0.17 mi
#1
North Central Expressway
US 75
COIT
ROAD
045
36 -
0.5 mi
Auto
RENNER SW
138 kV
022 6.99 mi 035
012
055
042
CLTE
138 kV
UG Cable
015
Cap
Bank
AIR
LIQUIDE
121
#1
WALNUT
ST
PAC.WINTER.2008
Protection Failure
Primary relaying system
failures are associated with long
fault durations because backup relaying must be relied upon to clear
the fault. A slow trip and the accompanying long-duration voltage
dips can be very costly to sensitive
customers, such as semiconductor
manufacturers, due to product loss.
An even worse scenario would be
to unnecessarily trip one of these
sensitive customers and completely
put them in the dark.
The area of the system in which
this event occurred is especially important for several of Oncor Electric
Delivery’s critical customers. The
Dallas Switching Station is served
by four 138kV lines which are protected by permissive overreaching
transfer trip (POTT) schemes using
various electromechanical and microprocessor relays. POTT schemes
over tone are used to provide high
speed tripping and increased security against undesirable trips for
external faults.
lesson learned
29
Protection Failure
lesson learned
30
Faults with
known locations
are used to verify
the system
model.
DFRs are powerful tools to use
when analyzing system operations, but they are only as good as
the information being fed to them.
Sometimes they contain very valuable “hidden” information that can
easily be missed at first glance. The
rest of this article describes the process through which Oncor Electric
Delivery went to get to the bottom
of a relaying system failure, and find
the true root cause.
EVENT
On May 5, 2006 at 2:55:34AM
an apparent lightning strike occurred on a double circuit 138kV
transmission line approximately
one mile north of Kirkland Park
Switching Station causing simultaneous A-phase to ground faults
on the Kirkland Park – Coit Road
and Kirkland Park – Dallas circuits.
The line at this point has a concrete/steel pole construction with
a single static wire on top and one
vertical circuit on each side. The
top conductor on each circuit is
A-phase.
From fault inception, Coit Road
CB 015 tripped in 4.5 cycles followed by Kirkland Park CB 035 at
5 cycles followed by Kirkland Park
CB 032 at 6.5 cycles. At this point
the Kirkland Park – Coit Road line
is open and the Kirkland Park end
of the Kirkland Park – Dallas line is
open. The fault is no longer a simultaneous fault, but is a single-lineto-ground fault being fed radially
by Dallas CB 042 (Figure 1).
In this configuration, Renner
CB 045 tripped at 36 cycles (Zone
2/Time flags) and Dallas CB 042
tripped to clear the fault at 42 cycles
PAC.WINTER.2008
(ground time-overcurrent flags). At
this point, Dallas was being served
by a single 138kV line from Renner
CB 035 (Figure 2). This configuration continued for 4 seconds until
Renner CB045 reclosed.
Two separate misoperations can
be observed from the sequence of
events:
Dallas CB 042 did not trip on
pilot, causing the fault to last 42
cycles
Renner CB 045 overtripped
for the fault
The analysis of the first misoperation is included in this article,
while the analysis of both is available in the online version.
MODELING
It is very important to have an
accurate system model to use when
making relay settings and performing fault locations. Faults with
known locations are used to verify
the system model.
Usually, the system model
matches the DFR values within
5-10%. In some cases the model
deviates more than usual due to
zero sequence mutual coupling,
large numbers of Y-Δ-Y transformers, system changes, and modeling
errors. Large differences between
the model and DFR data are investigated to help improve the model
by revealing modeling inaccuracies
and changes in system topology.
These differences can also be an indicator of mismatches between the
DFR configuration and actual connected CT ratios.
The fault location for the 5-5-06
event was estimated to be one mile
north of Kirkland Park Switching Station. Lightning detection
software verified that there was
lightning at that time and location.
Physical evidence of the fault location was not found even after flying
the line and performing inspections
from the ground. Kirkland Park,
Dallas and Renner are equipped
with DFRs which successfully recorded the fault. Table 1 shows the
modeled vs. observed residual fault
currents and the percent differenc-
es at two points during the fault.
The first point is fifteen cycles into
the fault as shown in Figure 1, the
second point is forty cycles into the
fault when the fault is being served
radially from Renner CB 035. This
analysis used corrected data for
Renner CB 035 and CB 045 as described in the online version.
The low percent differences,
especially for Renner CB 045 and
Dallas CB 042, verify that the system model is accurate and can be
used to analyze the relay operations
with confidence.
RELAY SYSTEM FAILURE #1
All lines directly connected to
Dallas use a POTT scheme to provide high speed tripping with increased security. POTT schemes
require that a permissive signal be
received before Zone 2 and directional ground relays are allowed to
trip without a time delay.
Figures 3 and 4 show the DFR
traces for Kirkland Park CB 035 and
Dallas CB 042.
Dallas CB 042 did not receive a
trip permissive signal from Kirkland Park CB 035 and, thus, did not
issue a high speed pilot trip. After
42 cycles, Dallas CB 042 eventually tripped on ground time-overcurrent to clear the fault. Figure
3 clearly shows that the DFR for
Kirkland Park CB 035 observed a
trip permissive signal being sent
to Dallas CB 042. The question is
why did Dallas CB 042 not receive
the permissive signal.
It was found that Kirkland Park
CB 035 failed to send a trip permissive to Dallas CB 042 because of a
diode across the operate coil of a
high speed auxiliary tripping relay
Why did Dallas
CB 042
not receive
the permissive
signal?
lesson learned
31
3 Kirkland Park CB 035 DFR Record
The protection relay sent trip permissive signal to Dallas
138kV BUS POT. VA
138kV BUS POT. VB
138kV BUS POT. VC
Protection Failure
CB 035 IA
CB 035 IC
CB 035 IR
138kV East BUS POT. VR
CB 035 TRIP 1 & 2
CB 035 CLOSE
CB 035 POSITION
CB 035 GUARD RECEIVE
CB 035 TRIP RECEIVE
CB 035 TRIP XMIT
EAST BUS PRI TIMERSTART
4
Dallas CB 042 DFR Record
The protection relay did not receive trip permissive signal from Kirkland Park
138kV EAST BUS VA
138kV EAST BUS VB
138kV EAST BUS VC
TX-042 KIRKLAND PARK IA
TX-042 KIRKLAND PARK IC
TX-042 KIRKLAND PARK IR
138kV EAST BUS VR
TRIP 1 TX-042
TRIP 2 TX-042
CLOSE 1 TX-042
TONE TRIP RECEIVE TX-042
TONE TRIP TRANSMIT TX-042
TONE GUARD RECEIVE TX-042
POSITION "B" SW TX-042
TIMER START 62EP
PAC.WINTER.2008
Protection Failure
lesson learned
32
that is used to key the transmitter.
The diode caused the relay coil to
be shorted out and never pickup
even though voltage was applied.
The nameplate Style # and Internal
Schematic # attached to the high
speed auxiliary tripping relay did
not call for a diode. Relays with a diode are a completely different Style
# and Internal Schematic #, so it is
still unknown as to how the relay
was mislabeled or if it was modified
in the field. The correct relay schematic is shown in Figure 5.
Polarity of the coil does not matter for this style of relay. Figure 6
shows the incorrect relay schematic
that corresponds to what was actually installed at Kirkland Park CB
035. It is crucial to have the correct
polarity for this style of high speed
auxiliary tripping relay. Figure 8
shows the diode across the relay
coil found at Kirkland Park CB 035.
The relay (85/XX) was wired
according to the print (shown in
Figure 7), which calls for terminal 9
to be positive and terminal 10 to be
negative. This caused the coil of the
relay to be shorted out by the parallel
diode. If the coil polarity had been reversed as it is required for that style of
relay, then the POTT scheme would
have operated correctly.
This relay was installed when
the Kirkland Park – Dallas line was
converted from DCB to POTT in
2000. It is now obvious that a full
functional test was not performed
when the POTT scheme was put
in service. The functional test
would have included keying the
local transmitter via the local relays and verifying that the remote
end received a permissive signal. If
a proper functional test had been
performed when the relay was installed, then the diode would have
been discovered.
The root cause of the failure
to send a trip permissive is improper functional testing during
checkout.
Contributing Factors
Three factors were identified
that perpetuated the problem and
kept it from being caught sooner:
Testing procedure – A full
functional checkout of the scheme
was not performed. This is the root
cause of the failure.
Relay did not match nameplate – It is reasonable to expect a
relay to be wired correctly, have the
correct components, and match the
attached nameplate.
DFR records - Kirkland Park
CB 035 DFR records show that a
Nameplate style
did not call
for a diode
permissive signal was being transmitted to Dallas CB 042. This is
because the DFR key permissive
digital input was monitoring the
DC voltage going to the high speed
auxiliary tripping relay coil, not the
actual key permissive contacts. The
DFR sensed the voltage at the relay
coil and indicated that a permissive
signal was being sent even though
the relay coil was shorted.
This contributed to the belief
that the POTT scheme was working correctly.
Preventable
Clearly, this misoperation could
have been prevented by performing a full functional test of the
POTT scheme, but there were also
two opportunities to discover the
problem by analyzing DFR records.
On 10/5/2001 and 5/25/2003
there were phase-ground faults on
the Kirkland Park – Dallas line that
5 Correct and 6 Incorrect Schematic
according to style number
1
2
as-found in the field
1
2
Data was available that, if analyzed
3
4
3
4
5
6
5
6
properly, would have detected the
failures and thus avoided the entire
situation. The event, relaying failures,
7
8
7
10
9
8
contributing factors, and how the situation could have been avoided are
9
T
NEG.
PAC.WINTER.2008
T
10
POS.
discussed.
Three factors were
identified that
perpetuated the
problem and kept it
from being caught
sooner:
-DFR records,
-testing procedure,
-relay did not
match name
plate.
since it showed that the POTT
scheme operated correctly for the
Kirkland Park end, the Dallas CB
042 record was given a cursory
glance and assumed to be correct.
It is also possible that the engineer
assumed the permissive received
digital at Dallas CB 042 was not
hooked up to the DFR. If this was
the case, field personnel should
have been notified, and the problem should have been investigated.
This misoperation could have been
avoided by spending the time necessary to fully understand and investigate DFR records for all faults.
Immediate Fixes
The remedy for this problem
was very straightforward – replace
the “bad” high speed auxiliary
tripping relay and perform a full
functional test.
Table 1 Modeled vs. Recorded Fault Currents
15
15Cycles
Cycle into
intoFault
Fault(A)
(A)
Terminal
Renner CB 035
Renner CB 045
Dallas CB 012
Dallas CB 022
Dallas CB 032
Dallas CB 042
Model IR
DFR IR
%Diff
Model IR
DFR IR
%Diff
1471
1507
1960
1939
962
10720
1587
1571
2024
2070
924
10429
-7.3%
-4.1%
-3.2%
-6.3%
4.1%
2.8%
2014
474
2378
780
8393
2400
564
2840
850
8127
-16.1%
-16.0%
-16.3%
-8.2%
3.3%
7 Kirkland Park CB035
8 Kirkland Park CB035
Keying Circuit
9
10
40
40Cycles
Cycle into
intoFault
Fault(A)
(A)
Relay, close-up of diode across relay coil
ETSNS
85
XX
8
85
XX
6
R3-2
ETB5
R3-3
ETB10
TH12
TH60
TH2
TYPE 40 TONE
TH11
TH59
ETB2
TH1
R3-1
PAC.WINTER.2008
Protection Failure
were both cleared in approximately
5 cycles even though this was after
the line was converted to POTT
and the “bad” high speed auxiliary
tripping relay was installed. These
two faults happened to be close
enough to the Dallas end of the line
for Dallas CB 042 to trip on ground
instantaneous instead of requiring a permissive signal. If the DFR
records for these faults had been
checked closely, then it would have
been apparent that Dallas CB 042
never received a permissive signal
even though the fault was in the
protected line section.
In defense of the engineers
checking the DFR records, the fault
cleared quickly and, at first glance,
the operation may seem correct. It
is possible that the Kirkland Park
DFR record was checked first, and
lesson learned
33
system
power
outages
34
Nampa,
Idaho, USA
8 January
2008
St. Katherine
Jamaica
9 January
2008
Watch
blackout
Southern
Oregon, USA
18 October
2008
by Clare Duffy, ESBI, Ireland
Analysis of system power outages can help us learn
and avoid similar events in the future. If you have
information on any blackouts, please e-mail to:
http://editor@pacw.org
PAC.WINTER.2008
A widespread out age that
interrupted power transmission to
about 30 thousand Pacific Power
customers in Southern Oregon,
USA, was caused by switch failure
inside the Vilas Road substation,
triggering failures at six other
substations. Power was restored
within an hour.
A fault at the major transformer
(T2) at the Taman Tshun Ngan
substation in Sandakan, Malaysia,
caused a major blackout in various
part of the municipality at 7.50pm.
Power in most areas was restored in
about two hours.
A blackout after a power trip at
about 3.30pm at the Tenaga
Nasional Bhd (TNB) substation in
Juru, Malaysia resulted in an outage
that affected most of Penang Island
in about 90 minutes.
Failure in two power stations - in
Baghdad and Basra, Iraq, knocked
out electricity across the Iraqi
capital. It resulted in loss of about
400 MW at Al-Quds station and 150
MW in Khor Al-Zubair station.
A faulty device that tripped a
transformer in the Clarkson
substation in Western Australia, as
well as blown fuses, were blamed
Albania,
Greece, Kosovo,
Montenegro
16 January
2008
Baghdad, Basra
Iraq,
29 December
2008
Zambia,
19, 21, January
2008
Zimbabwe,
19 January
2008
for blackouts that started on
Christmas Eve and affected about
15,000 households. Western Power
said this had nothing to do with
scorching temperatures.
A blackout struck Iloilo City,
Philippines, at 11:57 p.m. and
dampened the excitement of city
residents as they prepared to
welcome the New Year. Some
officials speculated that it was
caused by firecracker hitting a line.
A cat that entered an electrical
substation, caused a short that blew
out 9 feeder lines, causing a power
outage that blacked out more than
12,000 consumers in Nampa,
Idaho, USA. Service was restored in
about 3 hours to most customers.
A system shutdown in Jamaica
was initiated by the collapse of a
ut ilit y pole on the 138K V
transmission line connecting the
Duhaney P ark , St . Andrew,
substation to the Tredegar Park
station in St. Catherine. This led to
the collapse of a circuit breaker,
which further led to the shutdown
of the Old Harbour Power Station.
In southern Albania, a near 45
minutes blackout was caused by a
problem at a substation. The
Zemblak-Kardia transmission
interconnector with Greece tripped
causing other substations and
power connections in Montenegro
and Kosovo to trip as well.
Zambia was hit with t wo
nationwide blackouts in three days.
Iloilo
Philippinies
31 December
2007
Juru,
Malaysia
20 November
2007 Sandakan,
A blackout occurred on Saturday
Malaysia
19th and it took about eight
9 November
hours to restore power. On
Monday evening a second
2007
nationwide blackout occurred
around 7.30pm and it took 4 to
restore power. The country's power
authority said there had been a "high
voltage" occurrence on the network
but gave no further explanation as
they are still investigating. It is
unclear if the second outage was not
connected to regional problems
with electricity supply.
A major blackout caused by a
failure on the transmission grid,
occurred in Zimbabwe. It affected
the capital Harare, e.g. Bulawayo,
Mutare, Victoria Falls and Kariba,
suffered power cuts. Power was
restored gradually, but parts of
Harare were said to be without
electricity almost 24 hours later.
Zimbabwe has been experiencing
power supply problems for awhile .
PAC.WINTER.2008
Clarkson,
Australia,
29 December
2007
Time and
location of the
System & Power
Disturbances in
2008
by Jeon Myeong-ryeal, Oh Sei-ill, Lee Hee,Shin Chang-gyun, Electric Power Research Institute, Korea
Line Constants
Wide Are Monitoring
36
Analysis of
Measured
Transmission
Line Constants
The accuracy of line impedance data
has great impact on system analysis
The transmission line constants are the most important
element of data needed for the operation of an electric power
network. It comprises positive-sequence impedance (Z1),
zero-sequence impedance (Z0) and admittance.
The parameters of line constants are conventionally
computed by calculation programs, and the measured values
of transmission line constants have been utilized as reference
data when a newly built generating plant or substation
undergoes a commissioning test.
Notwithstanding, it is known that the conventional
method of reading voltage drop after applying voltage to
the transmission would not work effectively in energized
substations due to the influence of induction voltage.
However, the new type of measurement equipment
introduced hereon is unique in terms of injecting electric
1 Line Constants
Measuring Circuit
Impedance
measurements setup
current through the circuits and measuring the voltage
raised from the loaded test current. Because this new
measurement device is equipped with an additional feature
for selecting variable frequency for the source current, it
could advantageously perform measurement of transmission
constants without receiving any interference from induction
voltage of the frequency in use.
The measurement of transmission constants as described
below has been conducted with the help of the new
sophisticated measurement equipment to verify and analyze
the deviation between calculated and measured values of
transmission constants.
Representation of Line Constants Measurement
The transmission line constants are defined as the
constants showing electrical impedance values between
busbars of transmission lines in electric power networks.
These data are crucial in the electrical interpretation of power
networks. The transmission constants are also utilized in the
construction or expansion of power facilities as basic data
for areas such as the simulation review of load flow and fault
2 Measuring Schematic
for Transmission Line Constants
Captured
data was used
Positive Sequence Impedance Z1 Circuit
A S/S
(Measuring Point)
Line PT
CB
Line DS
to examine
instantaneous phase
Line EDS
Zero Sequence Impedance Z0 Circuit
Injection
B S/S
angles
CB
Line DS
between
Rockport and
Line EDS
Marysville
PAC.WINTER.2008
T/L
by Jeon Myeong-ryeal, Oh Sei-ill, Lee Hee,Shin Chang-gyun, Electric Power Research Institute, Korea
37
current, voltage stability and the protection relay settings.
While the calculated values have been conventionally
used in specifying transmission constants for the reasons
of physical obstruction to the field measurement of
transmission line constants, there has been growing support
for adopting the new measuring equipment featured with a
frequency-dependent device.
Therefore, we have responded by demonstrating
measurement of transmission line constants with the new
equipment as described in this article.
The new data obtained by this measurement will be
utilized as basic materials for future management of and
policies for transmission line constants by analyzing and
comparing calculated and values measured.
Measurement of Transmission Line Constants
There are three methods of applying test voltage and
current to transmission lines, i.e., phase-to- ground,
line-to-line, and 3-phase combined-to-ground. The positive
sequence impedance was measured by the line-to-line
method, while zero sequence impedance was measured by
3-phase combined-to-ground method.
The impedance was computed by measuring the results of
test voltage applied by the test equipment, and the admittance
by measuring the transmission charging current at the time of
initial energization.
Measurement Equipment
The measurement equipment used is as follows:
A compact multifunctional primary test set capable
of applying up to 2000V and 800 A, with a frequency range
of 10-400 Hz
Coupling unit
We need to highlight that measurement is impossible
with induction voltage exceeding 500V (as is the case with
345kV overhead transmission lines.) See Figure 3.
Biographies
Measurement Schematic for Line Constants
The transmission constants were measured, as shown
in Figure 3, by connecting the measurement equipment to
the EDS terminal behind the line DS at measuring end of
Substation “A”, and grounding 3-phase combined via EDS
at the other end of Substation “B”. See Figure 2.
Computation of Transmission Line Constants
The transmission line constants were computed, as
shown in Figure 4, by using a frequency-dependent method
at frequencies of 20, 40, 80 and 100 Hz, respectively to
find corresponding R and X values, which were averaged to
produce mean values.
However, the 60-Hz setting was excluded taking
into account noticeable errors due to the surrounding
electro-magnetic induction.
Figure 6 clearly shows that the resistance component
remains almost constant with variation of frequency, while
the reactance linearly increases as frequency rises.
Measurement of Transmission Line Constants
Approximately 5% of all transmission lines have been
selected for measurement of transmission constants for
analysis of deviation between calculated- and measuredvalues. These data will be used as basic material when
management and policies are established for overall
transmission constants in the future.
The transmission line circuits were tested during a 12
weeks period between 18 September and 15 December
2006 are as follows:
A total of 86 circuits of 154 kV transmission lines
under jurisdiction of 11 KEPCO Power Transmission
District Offices and Jeju Branch Office. (10 out of 96 circuits
are not considered due to suspended power supply)
34 circuits of overhead transmission lines (cable types:
ACSR 330, ACSR 410, and ACSR 410B)
Jeon Myeongryeal received
Bachelor of Science
degree in Electrical
Engineering from
In-Ha University
1983. In 1983 he
joined KEPRI (Korea
Power Research
Institute) in DaeJeon, South Korea.
His current position
is Leader of Power
Facility Technology
Service Group.
Oh Sei-ill received
Bachelor of Science
degree in Electrical
Engineering from
Seoul National University of Technology in 1987.
In 1987 he joined
KEPRI (Korea Power
Research Institute)
in Dae-Jeon, South
Korea and is currently Senior Member of Technical
Staff in the Power
Facility Technology
Service Group.
3 Arrangement
of Equipment for Measurement of T-line Constants
A Phase B Phase C Phase
CP CU1
I_AC
INPUT
FUSE 30 A
POWER TRANS
100/2.5A CT
L2
L1
BOOSTER
BOOSTER
V
I-OUT(0-100A)
CP GB1
V-Meter
VI_AC
INPUT
CPC-100
L3
V_SENSE(0-600V)
600/30V PT
PAC.WINTER.2008
by Jeon Myeong-ryeal, Oh Sei-ill, Lee Hee,Shin Chang-gyun, Electric Power Research Institute, Korea
Line Constants
Wide Are Monitoring
38
46 circuits of underground transmission lines (Cable
types: XLPE, OF, CV, and CNCV)
6 complex circuits
Analysis and Comparison of Calculated
and Measured Values
The results for overhead and complex transmission lines
are summarized in Figure 4.
For positive sequence impedance (Z1) transmission lines
with error rates exceeding 5% included 4 out of 40 circuits
with a maximum error rate of18.4%.
Statistics by error range are shown in row 1 of Table 1
with an average X1/R1 value equal to 6.17.
As protection relay settings assume about 5% of error
rate for transmission line constants values, the use of present
calculated values seems not problematic.
For zero sequence impedance (Z0) transmission lines
with error rates exceeding 5% included 14 out of 40 circuits
with a maximum error rate of 18.9%.
Statistics by error range are shown in row 2 of Table 1
with an average X0/R0 value equal to 4.88.
For the positive sequence admittance (Y1) statistics by
error range are shown in row 1 of Table 2.
The error seems to arise from calculation error as well as
from change of the fringing field underneath transmission
lines, such as change of ground altitudes (growth of bush
and trees, etc.).
Positive effects from improving the accuracy of
admittance measurements are that when formulating
reactive power compensation plan, investment cost for
phase modifying equipment may be reduced.
For the ratio of zero sequence (Z0) to positive sequence
impedance (Z1) the following results were obtained:
Average value of calculated Z0/Z1 = 2.69
Average value of measured Z0/Z1 = 2.66
4 Transmission Lines
Measuring the impegance
of transmission lines is
important for improving the
system model
The results for underground transmission lines are
summarized in Figure 5.
For positive sequence impedance (Z1) transmission lines
with error rates exceeding 5% included 23 out of 46 circuits
with a maximum error rate of18.4%.
Statistics by error range are shown in row 3 of Table 1
with an average X1/R1 value equal to 6.21.
The calculated values are not suitable for application to
protection relay settings as error rates are high (about 10%)
and error ranges vary widely depending on the installation
condition of underground transmission lines.
For zero sequence impedance (Z0) transmission lines
with error rates exceeding 5% included all 46 circuits.
Statistics by error range are shown in row 4 of Table
1 with an average X0/R0 value equal to 1.90. 2) Zero
sequence impedance (Z0)
The transmission district offices having substantial length
of underground transmission lines require procurement
of new test equipment for physical measurement of
transmission lines. Research needs to be tasked to raise
accuracy of calculation program.
For the positive sequence admittance (Y1) statistics
by error range are shown in row 2 of Table 2. The ratio of
5 Transmission Lines
Overhead Lines - Overhead & Compex Lines
Underground Transmission Lines
Measured / Calculated Value Rate of Overhead
Line Constant
[Unit: %]
400
Measured / Calculated Value Rate of Underground
Line Constant
[Unit: %]
1200
1000
300
800
200
600
400
100
200
0
0
R1
Average
Max.
Min.
87.9
99.8
71.9
Standard
Deviation %
PAC.WINTER.2008
6.2
X1
Z1
R0
X0
Z0
Y1
100.1
112.8
82.0
99.7
111.7
81.6
87.6
132.0
66.8
100.2
118.6
84.8
99.5
118.9
84.9
148.0
279.1
70.3
4.8
4.8
13.4
7.6
7.6
62.4
R1
Average
Max.
Min.
Average
Deviation %
87.9
99.8
71.9
37.2
X1
Z1
R0
X0
Z0
Y1
100.1
112.8
82.0
99.7
111.7
81.6
87.6
132.0
66.8
100.2
118.6
84.8
99.5
118.9
84.9
148.0
279.1
70.3
7.9
8.0
217.4
333.1
283.7
61.3
by Jeon Myeong-ryeal, Oh Sei-ill, Lee Hee,Shin Chang-gyun, Electric Power Research Institute, Korea
Table 1 Statistics by Error Range and by Average
row
5%
5
10%
10
15%
15
29%
20
25%
Total
1
2
3
4
35
25
22
0
2
6
14
14
1
7
6
12
2
2
2
3
o
o
2
17
40
40
46
46
Table 2 Statistics by Error Range and by Average
row
10%
20
50%
50
100%
100
200%
200
300%
Total
1
2
17
5
9
28
5
9
9
2
o
2
46
46
6 T-line Constants
Line Constants
T-line Constants with Variable Sequences
Impedance versus Frequency
3.0
2.5
Impedance [0 hm]
average to calculated values is 131.9±61.3% .
The measured values of admittance of underground
transmission lines were found to be lower than those of
overhead transmission lines.
For the ratio of zero sequence (Z0) to positive sequence
impedance (Z1) the following results were obtained:
Average value of calculated Z0/Z1 = 0.48
Average value of measured Z0/Z1 = 1.87
Transmission line constants per unit length for different
conductors for admittance are shown in Figure 7 and for
positive and zero sequence impedance - in Figure 8.
The analysis of the measured data obtained in this
research clearly shows that:
The constants of overhead transmission lines are
excellent as they stay well within acceptable error range.
The constants of underground transmission lines are
remarkably high, particularly in zero sequence impedance
due to underground cable grounding system, such as
whether the close bond grounding is provided at one end
or at both ends of cable spans. Further research must be
conducted to review the accuracy and application problem
with the calculation program for constants of underground
transmission lines.
Also, as the importance of transmission line constants
is expected to be emphasized with the innovation of
power network operations and techniques, measurement
equipment will be broadly introduced to enable extensive
measurement and analysis of transmission line constants,
so that an expanded data base can be effectively utilized.
Building an accurate data base of transmission line
constants will greatly improve the quality of interpretation
of electric power networks, and will further contribute
to stabilization and optimum operation of electric power
systems.
2.0
1.5
1.0
0.5
0.0
0.0Hz
20.0Hz
40.0Hz
60.0Hz
80.0Hz
100.0Hz 120.0Hz
Frequency [Hz]
R (x)
X (f)
Rcalc(60.0Hz)
Xcalc(60.0Hz)
8 Impedance
7 Admittance
For different conductors
Positive Sequence and Zero Sequence Impedance
Measured Line Constant per 1 km
[unit: /km]
1.5
Measured Admitance per 1 km
[unit: Mho/km]
1.0
400
300
0.5
200
0.0
0
Average
Max.
Min.
ACSR
330
5.41
9.30
2.44
ACSR
410
ACSR
410B
XLPE
OF
CNCV
5.2320
9.4066
3.7320
6.3307
9.7944
5.0557
100.03
173.43
16.46
210.70
329.42
153.17
138.04
207.97
83.85
A C S R
Average
100
330
410
410B
XLPE
OF
CNCV
R1
0.0861
0.0702
0.0375
0.0256
0.0261
0.0281
X1
0.4616
0.4690
0.3323
0.1676
0.1573
0.1321
Z1
0.4696
0.4742
0.3344
0.1696
0.1598
0.1351
Wide Are Monitoring
39
R0
0.2478
0.2566
0.1818
0.1544
0.1450
0.0546
X0
1.2296
1.1855
0.9606
0.3009
0.2513
0.1008
Z0
1.2544
1.2135
0.9757
0.3412
0.2950
0.1149
PAC.WINTER.2008
Implementation
Time
IEC
GOOSE
61850
GOOSE
SE GOOSE
O
O
G
OSE
O
G
GOOSE GOO
GOOSE
SE GO
E
S
OS
O
O
E
G
GOOSE
SE GOOSE
O
O
G
GOO
OSE
SE
O
G
by Hachidai Ito and Kenichiro Ohashi , Toshiba Corporation, Japan
of
High Performance
and Protection
Relay Testing
EAF
Transformers
IEC 61850 GOOSE messaging is applied for Substation Automation
Systems and for status interactions between IEDs by replacing the conventional
method of using binary inputs/outputs and wires with communication over
Ethernet cables/fibres.
With its fast transfer characteristics, it is also applied for
GOO protection testing purposes.
SE
In
order to confirm the basic
functionality of IEC 61850 and
GOOSE messaging, conformance
tests are mandatory for basic
multi-vendor interoperability.
IEC 61850, the new communication standard for power
substations, is now being widely used in practical applications. In particular,
GOOSE (Generic Object Oriented Substation Events) messaging has
been applied not only for SAS (Substation Automation System) control
and monitoring of primary equipment and IED status, but also for status
interactions between IEDs including protection relays by replacing the
conventional method of using binary inputs/outputs and wires with
communication by GOOSE messages over Ethernet cables/fibres. This is
achieved through much simpler engineering based on the multi vendor
interoperability described in the IEC 61850 standard, which enables the
easy connection of different IEDs, including relays supplied by different
vendors.
PAC.WINTER.2008
protection
40 41
by Hachidai Ito and Kenichiro Ohashi , Toshiba Corporation, Japan
IEC 61850
protection
42
Hachidai Ito
was born in Osaka,
Japan, in September
15, 1956. He joined
Toshiba in 1981,
and worked as a
development engineer and a manager
of Protection and
Control Development Department.
He is now a Chief
Specialist in Power
System Protection &
Control and is principally responsible
for technology and
overseas marketing
of protection and
control products
in Toshiba Corporation. He is a senior
member of IEEE, and
a member of CIGRE,
IEEJ and IEICE. Also
he is a secretary of
Japanese National
Committee of IEC/
TC95, a convenor
of its MT1 (Maintenance Team 1)
and a member of
its other 3 working
groups, and also a
member of several
working groups in
IEEE/PSRC...
In order to confirm the basic functionality of GOOSE
messaging in protection relays, functional conformance
testing at an independent test laboratory is mandatory for
multi vendor interoperability. However, an IEC 61850
device certificate does not fully ensure conformity to the
IEC 61850 standard. Furthermore, in some cases, the
correct behaviour of an IED is not clearly described in the
standard. Hence, performance testing for GOOSE messaging
must be considered as an important item in the product
type test and/or the routine test because this is critical for
practical substation applications. It should be noticed that
performance testing for GOOSE messaging is not covered
by conformance tests at present.
In order to replace the conventional method of using
contacts and wires, the performance of the GOOSE
messaging, i.e. transfer time should be less than 3ms for
a Trip GOOSE command and 20ms for a Block GOOSE
command as specified in IEC 61850-5 'Communication
requirements for functions and device models’. It is clear
that new methods for testing GOOSE messaging including
performance and interoperability must be carefully
considered, not only by vendors but also by the end users
who evaluate system performance in the field.
GOOSE APPLICATIONS FOR PROTECTION
Advantages of GOOSE for protection devices
GOOSE messaging is a very important function in
achieving multi-vendor interoperability as described in
IEC 61850. The purposes and associated advantages are
considered as follows:
Instead of connecting conventional metallic wiring and
other ancillary equipment between protection devices, or
between protection devices and primary equipment, only a
single LAN cable/fibre is required. This results in a reduced
total cost of building a system in a substation.
Connection between IEDs provided by different
vendors is much easier to achieve.
Modification or addition of data communications
between IEDs can be easily achieved by the simple
re-configuration of the IEDs’ GOOSE settings, rather than
by complex metallic wiring.
Figures 1 and 2 show an example of the differences
between the conventional method and that utilising GOOSE
messages where communication between a protection
relay and a primary CB (Circuit Breaker) is required for an
Autoreclose function.
Possible GOOSE application for protection and
related ongoing activities
GOOSE messaging in IEC 61850 can also be utilised in
the following protection functions:
Autoreclose (between relay and CB)
Intertripping (between relay and relay)
Interlocking (between bay control unit and relay)
Some utilities consider and plan contingencies in
the case of a protection failure in a system. In order to
minimize the damage caused in the case of a primary fault
to the zone protected by the equipment that has failed,
messaging between protection relays is very important.
This subject is being discussed in CIGRE/SCB5/WG16:
Busbar protection. There is a possibility to use GOOSE
messages for information communication between
the various items of equipment contained within the
substation
ACHIEVING INTEROPERABILITY
Functional conformance test See Figure 3.
UCAIUG (http://www.ucausersgroup.org) defines
the conformance test procedure which is detailed in IEC
61850 part 10 (Conformance testing). The test procedure
contains two types of test;
11
22
Connections between Relay
and CB by conventional methods
Connections between Relay
and CB by GOOSE
Protection Relay
Binary output
Trip/Autoreclose
GOOSE for Trip/Autoreclose
Binary
input
100 BASE/10 BASE HUB
Primary CB
GOOSE for CB Condition
CB Condition
Dedicated metalic cable (s)
PAC.WINTER.2008
A LAN cable
by Hachidai Ito and Kenichiro Ohashi , Toshiba Corporation, Japan
Positive test: Checks with correct parameters.
Negative test: Checks with incorrect parameters.
However, there are some points that we must be
cognizant of with regard to conformance testing;
‘Conformance’ does not mean ‘Interoperability’.
Only basic functional tests are undertaken, no
performance tests are carried out at present.
IEC 61850 communication interfaces in the IED form
the main part of the test, but the connections between
prot ec t ion applic at ions and their IEC 61850
communication interfaces are too complex and varied to be
comprehensively tested.
Regarding standardisation and guidance on testing,
functional testing of IEC 61850 based systems is now
being discussed in CIGRE Subcommittee B5 Task Force
92. The technical brochure will define the functional
aspects of testing which are not defined in IEC 61850-10
(Communication networks and systems in substations
-Part 10: Conformance testing). It deals with the functional
parts not covered by the IEC 61850 device certificate
which is based only on IEC 61850-10. This will have an
impact on the work of the protection engineer, and this
kind of functional testing approach should naturally be
carried out for all existing IEC 61850 conformant devices
and systems.
Importance of performance testing for GOOSE
messaging
In order to achieve multi vendor interoperability in
GOOSE messaging in consideration of an actual practical
situation within a substation, it is important that not only
the functional conformity to IEC 61850 be tested, but also
performance conformity to IEC 61850 must be tested, by
vendors, as a type test of the IED.
Performance criteria examples of GOOSE messaging
defined in IEC 61850-5 'Communication requirements for
functions and device models’ are given as follows:
3ms: ‘TRIP’ GOOSE information (class P2/P3)
20ms: ‘BLOCK’ GOOSE information (class P2/P3)
The transfer time definition is described in IEC 61850-5
(see Figure 4). IEC 61850-5 states that the transfer time
of GOOSE messaging for a Trip command shall be such
that the command should arrive at the destination IED
within 3ms. For a single IED, by assuming the time for
the publishing process and the subscribing process are
approximately equal and if ‘tb’ can practically be ignored,
then at least half of the defined time is needed for the IEDs
to process the message (i.e. 1.5ms for ‘TRIP’ GOOSE). See
Figure 4.
PROTECTION RELAY TESTING USING GOOSE
Comparison with the conventional method
Figures 5 and Figure 6 simply show the difference
between the conventional test method used to measure
tripping time and the method used to measure the ‘Trip’
GOOSE transfer time using an IEC 61850 GOOSE
enabled test set. In order to simulate network traffic,
possibly caused by other equipment connected to the same
network, a network traffic simulator running on a PC is
used. It is considered very important for the product type
test to have a similar environment to that found within the
23
24
An IEC 61850 device certificate
IEC 61850
Conformance with
the performance criteria
defined in IEC 61850-5
should be tested.
protection
43
Kenichiro
Ohashi
was born in MiyagiPref., Japan, on
March 5, 1973. He
joined Toshiba in
1995. He is currently responsible
for product development of protection and control
systems as a quality
assurance/testing
engineer in Toshiba.
He is a member
of IEC/TC95/MT2
(Maintenance Team
2: EMC standards
for measuring relays
and protection
equipment).
GOOSE transfer time
IEC 61850 -5
The UCA International
Transfer time t = ta + tb + tc
Users Group defines
ta
tb
tc
the conformance test
procedures required for
issuing IED conformance
f1
Communication
processor
Communication
processor
f2
GOOSE
transfer time
is the time
certificates.
between
Physical device PD1
Physical device PD2
fuctions in two
devices
PAC.WINTER.2008
by Hachidai Ito and Kenichiro Ohashi , Toshiba Corporation, Japan
IEC 61850
protection
44
Implementation and test
results satisfying the
performance criteria are
described along with methods
for evaluation.
substation, and this is a key point in GOOSE testing. See
Figure 5/ Figure 6.
The advantages in testing with GOOSE messaging are
considered as follows:
Dedicated metallic cables in the connection between
the relay and test equipment and/or cables used for testing
can be reduced.
Performance evaluation is more accurately achieved
in GOOSE messaging since hardware overhead time on
conventional binary inputs/outputs can be ignored.
The limitation in the number of binary inputs/
outputs can be covered by GOOSE.
The timing of all GOOSE can be monitored by an
external IEC 61850 protocol analyzer connected to the
network.
Expanding flexibility in testing with GOOSE
IEC 61850 GOOSE, with its fast transfer characteristics
within a network environment (<3ms as defined by
the standard), is now being widely used for protection
purposes in place of conventional dedicated wiring. As
described, this brings great benefits to the user since
dedicated wiring can be reduced.
In the same way, GOOSE can be applied for testing
purposes. All signals, even those used internally in the
execution process of software for a numerical protection
relay, can be assigned to GOOSE. This results in reduced
wiring during testing and also facilitates the realisation of
more detailed testing.
Figure 7 shows a practical example of the test result of
a switch-on-to-fault case utilizing GOOSE for a certified
IEC 61850 conformant numerical transformer protection
relay.
In this case, the COMTRADE waveforms calculated
by RTDS with a simulation of both CT saturation and
transformer inrush under a switch-on-to-fault condition
were played on a test set. At the same time the relay’s
internal signals for 2nd harmonic inrush current detection
and CT saturation detection which are used to block
tripping were observed along with the trip signal, without
any wiring connection but by monitoring GOOSE
messages on the network.
The waveform can be seen to consist of fault current
and transformer inrush components. In response to
this unusual waveform, the relay firstly detects second
harmonic to temporarily block tripping and then
subsequently issues a trip, which is considered to be the
expected result.
In the past, there would have been many limitations in
the flexibility of this kind of test, e.g. resulting from the
delay time of mechanical contacts.
PERFORMANCE AND ITS EVALUATION
GOOSE messaging implementation to achieve
satisfactory performance
It is important to minimize the transmission time of
the GOOSE packet within the IED in order to achieve
the GOOSE performance of class P2/P3 which is defined
15
26
Example of physical
connections for a conventional test
Communi-
Protection Relay
cation
replace hard-
Protection Relay
Binary output
messages
Trip/Autoreclose
GOOSE for Trip/Autoreclose
Binary
input
CB Condition
between a
test device.
Network
traffic simulator
Testing
Tool
Binary
input
wired signals
relay and
Example of physical
connections for GOOSE based test
HUB
GOOSE for CB condition
Binary output
Voltage/Current
Voltage/Current
Dedicated metalic cable (s)
PAC.WINTER.2008
Test Device
A LAN cable
Test Device
Testing
Tool
by Hachidai Ito and Kenichiro Ohashi , Toshiba Corporation, Japan
45
in the standard. One area in which we have been able to
make significant savings in processing time is in the way
in which we process the sending and receipt of GOOSE
messages. Another opportunity was taken to reduce the
time overheads incurred between the GOOSE packet
receiving process, the interpret/response/generate GOOSE
packet process and the sending process. Implementation
of the application software is designed such that the three
processes referred to above are executed in series in a task
activated in a very short period of time together with the
primary protection/measurement etc. functions as shown.
See Figure 8.
Methods for performance evaluation in GOOSE
communication
Figure 9 and table 1 show a test result for the ‘Trip’
GOOSE transfer time in a certified IEC 61850 conformant
numerical distance protection relay as a performance
type test. An IEC 61850 GOOSE enabled test set is used
with 0.1ms resolution. During the performance type test
of an IED, transmission traffic must also be considered.
By calculating the maximum possible traffic on the LAN
to which the IED is intended to be connected, or stating
the maximum traffic value for which the IED can either
publish or subscribe to GOOSE within the specified time,
the performance criteria must be stated by the vendor.
In practical situations, there are many kinds of GOOSE
published by other IEDs and by primary equipment. All of
these frames and also frames of other protocols could be on
the same LAN network simultaneously. This point must,
therefore, be considered when the possible maximum
network traffic is calculated. A performance calculation
example is also included in Appendix I of IEC 61850-5.
Table 1: An example of the test result for GOOSE
transfer time.
27
Example of utilizing GOOSE
for protection testing purpose
28
Simplified sequence model
of procedures in a time crucial proces
GOOSE packet
receive
IED primary
process
GOOSE packet
send
Table 1
Test results for GOOSE transfer time
Network
Traffic
(*1) (*2)
Maximum response time
of GOOSE (*2)
Autoreclose by
GOOSE (*2)
50 Kb/S
100 Kb/S
200 Kb/S
< 0.7 MS
< 0.7 MS
< 0.7 MS
Successful
Successful
Successful
*1 Simulated only by GOOSE which were all captured and processed by
GRZ100 at the same time
*2 Test condition/hardware configuration is same as Figure 6
Table 1 shows an example of the test result
for GOOSE transfer time (‘ta’ in Figure 4) and
of the result of Autoreclose utilizing GOOSE
for all interaction signals in a certified IEC
61850 conformant numerical distance protection relay with simulated network traffic.
29
Trip GOOSE transfer time
measurement results
PAC.WINTER.2008
It is important
to reduce the
time between
the GOOSE
receive and
response.
by Hachidai Ito and Kenichiro Ohashi , Toshiba Corporation, Japan
IEC 61850
protection
46
To obtain
the expected
benefits of
As another aspect of performance evaluation for a single
IED, the GOOSE response time shall be checked since it
directly affects the system performance.
As part of system evaluation, an easy way to test the
response time of an IED could be by the ‘Ping-Pong’
technique as described below. This method is very efficient
because it can check the subscribing time (‘Tc’ of Figure
4) and publishing time (‘Ta’ of Figure 4) at the same time
without other external inputs or triggers.
Set the IED to publish GOOSE (A) when GOOSE (B)
is subscribed.
Arrange external equipment connected to the LAN to
publish GOOSE (B).
Observe the behaviour of GOOSEs with external
equipment connected to the LAN.
Figure 10 shows the test result of an IED, a certified IEC
61850 conformant numerical distance protection relay,
with an IEC 61850 GOOSE enabled test set.
As shown, the response time here is sufficiently fast
to adhere to the requirements defined in the standard
(Figure 10). However, as it is only a single test result then
to actually verify the performance, we must repeat the
same case at least e.g. 100 times and check the maximum
response time under simulated network traffic.
As an extension of these procedures, this ‘Ping-Pong
GOOSE’ can be played continuously between two or
more IEDs without any external equipment. In case of
two IEDs, the same settings as shown above are sufficient
with the exception of exchanging GOOSE (A)/GOOSE
(B) and inverting their logic at one IED. An IEC 61850
network analyzer could observe the continuous ‘Ping-Pong
GOOSE’ rally, and as for evaluation, it is only necessary to
determine how many GOOSEs were issued to the network
in a certain time period, i.e.
10
[ Time period ] / [ Number of GOOSE issued ] =
[ Average response time ]
Here is a test result captured by an IEC 61850 protocol
analyzer, which was carried out between two certified IEC
61850 conformant devices (Figure 11). Furthermore in
this case, once the ‘Ping-Pong’ is set, the IEDs start playing
‘Ping-Pong’ as soon as the IEDs are connected to the
network. Therefore, it could be used also for the purpose
of increasing the network traffic.
Note that cases utilizing GOOSE introduced here can be
basically also applied to all IEC 61850 conformant devices
which support the service for GOOSE.
In order to obtain the expected benefits of IEC 61850
it is of critical importance to apply IEDs which provide
sufficiently high performance of GOOSE messaging.
IEC 61850 GOOSE messaging is now widely used
in substation applications replacing methods using
binary inputs/outputs and wires. GOOSE messaging
performance evaluation for certified IEC 61850 conformant devices is one of the critical issues in achieving required substation functions such as sending
trip commands or exchanging interlock status.
11
Single 'Ping-pong GOOSE'
for performance evalation of an IED
Rally of 'Ping-pong GOOSE'
between two IEDs
Protection Relay
Protection Relay
IEC 61850,it
Test Device with IEC 61850
2. GOOSE (A)
1. GOOSE (B)
is critical to
apply IEDs with
sufficiently high
performance
of GOOSE
messaging.
PAC.WINTER.2008
Protection Relay
GOOSE (A)
GOOSE (B)
www.utinnovation.com
info@utinnovation.com
The Combination Is Even Sweeter
by Damien Tholomier and Denis Chatrefou , AREVA T&D
IEC 61850
Process Bus - It is Real!
The new international standard for substation communications IEC
61850 allows the development of a new generation of substation protection,
automation and control systems that results in significant reduction of the overall
cost of such systems, while at the same time improves the functionality of different
applications. Non-conventional instrument transformers with digital interface
based on IEC 61850-9-2 process bus eliminate some of the issues related to
differences in protection and metering requirements. The data can be processed by
any device to perform different protection, automation and control functions.
61850
protection
48
The IEC61850 international
standard for communications in
substations brings a new era in
the development of substations. It
affects not only the design of the
substation protection, monitoring
and control system, but also the
design of the substation secondary
circuits. High-speed peer-to-peer
communications using GOOSE
messages and Sampled Analog
Values allow development of
distributed applications based
on current and voltage values
communicated between devices
Damien Tholomier received an Electrical Engineering degree from the Ecole Polytechnique Universitaire de Marseille,
France. He joined GEC Alsthom in Stuttgart, Germany as Power System Application Engineer. In 1997 He became Marketing Manager with Alstom T&D Protection & Control in Lattes,
France. From 1999-2001 he was Sales & Service Director for
Mediterranean Countries and Africa. From 2002, he is presently Marketing Products Director for Areva T&D Automation.
Damien is CIGRE, IEEE, IEC TC95 and GIMELEC member.
Denis Shatrefou obtained his Engineering Degree in Optics
from Ecole Supérieure d'Optique in 1977. He was involved in
optical signal processing for Radar’s at ONERA (French Aerospace Research Center) and C.E.A (French Atomic Research
Center). He joined SCHLUMBERGER in 1985 to develop an Optical Current & Voltage Instrument Transformer. These activities
were transfered to ALSTOM (now AREVA) in 1988. He is now,
Technical Director of the High Voltage Sensors & Electronics
Activity (HVSE). He is Senior Member of SEE.
PAC.WINTER.2008
connected to the process and
substation local area networks.
Over the past few years, the
market surge towards to IEC61850
has been evident for suppliers and
customers alike. Much of this interest
has centered on the migration
from manufacturer-driven station
bus implementations, towards
substation automation systems
that fully integrate IEDs such
as protection relays on the new
accepted international standard.
This approach has largely
concentrated on the IEC61850-8.1
st at ion bus , emulat ing and
improving on the conventional
SC ADA approaches and the
replacement of hard-wired signal
exchange between substation
protection and control devices
with GOOSE messages. However,
the station bus is only a part of the
advancement that IEC61850 can
offer, with IEC61850-9.2 being
largely unexplored. IEC61850-9.2
is the part of the standard that brings
non-conventional instrument
transformer technology (NCIT)
into play, breaking the shackles and
constraints of conventional CTs
and VTs with iron wound cores at
their heart. NCIT has some relative
advantages such as elimination of
transients, improvements in safety
and accuracy, reduction in wiring
costs, and the resulting effect on
substation topology. More than
15 years of advanced research and
different projects around the world
are proving the great potential of this
technology
Non-Conventional
Instrument Transformers
The successful implementation
of NCIT in various applications (AIS
and GIS) requires the availability of
a full range of products. Laboratory
type tests and field experiments
have been running for more than
15 years and successfully show
the technical feasibility of sensors
and their implementation in high
voltage networks within the ruling
specifications.
All configurations require
one unique secondary electronic
rack, the so-called Merging-Unit
(MU). This is a device that includes
sensor electronics and different
kinds of interface, compatible with
protection and metering devices.
Technical solutions based
on Optical and Hybrid sensors
integrate the best advantage of the
technology in AIS substations. The
CTOE “Current Transformer based
on Optic-Electronics sensors” and
the VTCE “Voltage Transformer
based on Capacitor-Electronics
by Damien Tholomier and Denis Chatrefou , AREVA T&D
49
sensor” are the optimum solutions
proposed. However, mainly due to
interface modifications there have
been a limited number of industrial
applications in substations. Recent
works on international standards
by working groups under IEC
resulted in the definition of digital
communications that allow some
interoperability experiments
between NCIT and other equipment
used by automation, opening the
door to complete applications in HV
and EHV substation. (Figure 3)
The solution consists in the use
of following devices:
Current Transformer based on
Optical sensors and primary
Electronics (CTOE)
Voltage Transformer based on
Capacitor divider and primary
Electronics (VTCE)
Merging Unit (MU)- an
electronics device containing the
necessary electronics for sensors and
the digital interface according to IEC
61850-9-2 the Standard
Intelligent Electronic Device
(IED) with protection functions,
compatible with digital interface
according to the IEC standard for
Sampled Values communications
The C TOE and VTCE are
connected to the merging unit by
optical fibers transporting digital
signal according to a proprietary
protocol. The MU elaborates the
standardized digital frame according
to an IEC 61850 implementation
guideline published by the UCA
International Users Group: IEC
61850-9-2-LE. An Ethernet switch
allows all devices that subscribe to
the sampled values to connect to the
merging unit.
In order to understand better the
advantages of non-conventional
instrument transformers, let us
consider the operating principles of
this sensor technology and how they
are implemented in real devices.
Optical Current Sensors and
Primary Electronics
Current Transformers with
Optical sensors and Primary
Electronics (CTOE) are devices
able to measure the current of High
Voltage lines for revenue metering
application, as well as for protection
and redundancy features.
One phase unit includes:
Head with a primary optical
sensor (number can be up to 3 for
redundancy)
Composite insulator,
comprising optical fibers
Base, including a junction box
containing optical connectors and 2
redundant electronics boards for
digitalization and transmission to
the merging unit
Optical cable to the MU
IEC 61850 allows
interoperability
between IEDs and
non-conventional
sensors
The Faraday sensor:
The Faraday Effect or the
magneto-optic effect describes the
influence of a magnetic field on a
transparent optical medium. The
magnetic field alters the electron
path in the medium, which
acquires a circular birefringence
(the phenomenon of double
refraction of light wavefronts
in a transparent, molecularly
ordered material produced by the
existence or orientation-dependent
differences in refractive index)
and affects the polarization state
of a monochromatic light beam
propagating in the same direction
as the magnetic field. As a result,
the light acquires a rotation of
polarization state. (Figure 2)
The design of an optical sensor
is a very important factor in its
performance. We need to keep in
mind that such devices, depending
3
1 Ring glass design 2 Faraday sensor principle
Optyical current transformers are based on the
Faraday effect - influence of magnetic field
on transparent optical
LED
medium
PAC.WINTER.2008
Figure 3
NCIT based
solution
61850
protection
50
A Merging
on where they are installed, may be
exposed to some extreme weather
conditions. The choice of ring glass
solution that gives good temperature
response and also important benefits,
such as easiness of manufacture,
industrialization and possible use
of multimode components such
as larger optical fiber core, easier
connectors, LED (Light Emitting
Diodes) instead of LD (Laser Diode).
(Figure 1) The optical detection
is used to transform the Faraday
polarization modulation in a light
intensity modulation by addition of
a “polarimetric system”, including
two polarizers oriented at 45° from
each other, with Faraday medium
between them. Furthermore, the
light intensity is a measurable value
and can be converted into electric
signals by special opto-electronics
components called photodiodes .
Primary Converter in the
base of the CTOE
A primary electronics board
allows converting the light power
traveling in the sensor in electronics
signals transmitted digitally to
the merging unit. These primary
electronics includes:
LEDs that emit a
quasi-monochromatic light. This
light is coupled to a fiber included
in the composite insulator,
transmitted to a Faraday sensor,
and coupled in a return fiber.
The beam light, modulated
by the magnetic field, is detected
by a photodiode (PD) and then
converted in an electronic analogue
signal.
An analogue to digital converter
associated with a micro-controller
of communications used to send
the sampled values of the signal to
the merging unit through a classical
communication optical fiber.
Secondary Converter in the
Merging Unit - MU:
A secondary electronics board
in the merging unit performs the
signal processing necessary to
make available through the process
bus communications the sampled
values of the currents.
Optical Cable:
The optical cable, between
the C TOE and the merging
unit is not standardized in IEC
61850. In one implementation it
packages standard communication
62.5/125 multimode optical fibers
that, as well as the connectors may
be chosen by the user.
CTOE Unit:
Head , including pr imar y
conductor, high voltage terminals,
Non-conventional
instrument
transformers may
be exposed to
extreme weather
conditions
and a housing box containing the
optical sensors:
2 redundant protection
channels
1 metering channel
Composite insulator,
including optical fibres for the
optical sensors
Insulator junction
Base with optical connection,
or primary electronics, and fibre
transmission.
Voltage Transformer Based
on Capacitor Divider and
Primary Electronics (VTCE)
The Voltage Transformers based
on a Capacitive Divider and Primary
Electronics (VTCE) are devices able
to measure the voltage of High
Voltage lines for revenue metering
application, as well as for protection
and redundancy features.
Relay with station
4 Simplified block diagram of a merging unit 5
and process bus
Unit can be
Merging-Unit
considered
as a remote
analog input
Calibrator
Amplifirs, Filters
Analog
circuit
Group Delay D1
DSP
Signal
Processing
Group Delay D2
Analogue
to Digital
ADC
board of an
IED
DELAY D1+D2
Synchro 1 pps
Synchronized and dated
samples with 1pps
PAC.WINTER.2008
Digital communications to
Merging Unit (MU).
The solution offers also the
Power Quality capability, allowing
harmonics measurements up to
the 100 of the rated frequency.
The VTCE Unit:
The VTCE unit includes:
Head, including primary
conduc tor to hi g h volt a g e
terminals
Composite insulator,
including the capacitive divider
Capacitor junction
Base with primary electronics,
and fibre transmission.
IEC 61850-9-2 Digital
Interface for Sampled Values
Electronics technology has
fully evolved in the last decade
and the consequence is the
generalization of digital hardware
designs for electronics devices
like Merging Units (MU) and
Intelligent Electronic Devices
(IED), including protection relays
and meters, as well as the digital
communications between them.
A previous RTE experiment at
Vielmoulin 400 kV substation
has successfully demonstrated
during more than three years the
feasibility of such a digital link.
Unfortunately, there was a delay
6 Analog signal phase shift
of several years before receiving a
standard communications protocol
that is accepted worldwide. This
fact has considerably slowed down
the NCIT applications.
We also need to remember that
the technology of optical sensors
is well proven. Indeed, since the
end of the nineteen’s many CTO
units for revenue metering and
protection function have been
installed at the HV terminals of IPPs
(Independent Power Producers).
These devices have the major
advantage of extra high dynamic
range for current measurement that
can be achieved with conventional
current transformers only by using
separate CTs for protection and
metering.
A s already ment ioned
previously, the publishing of IEC
61850 creates a great opportunity
because of its main objective – to
ensure “Interoperability” between
IEDs comin g from v ar ious
suppliers, to enable the unrestricted
exchange and usage of data to
perform their individual dedicated
functionality.
This is not an easy t ask ,
especially if we consider the
many different requirements for
various substation and power
61850
One phase Unit includes:
A capacitive divider, isolated
w ith film-paper-oil, or SF6
technology represents technology
that is well-known and mastered
by many manufacturers
A redundant Primary
Conver ter, replacing the
conventional transformer in the
bottom of CCVTs ; these electronics
are designed for digitalization and
transmission to the merging unit
with an optical cable.
Advantages of the VTCE
solution:
T h i s N o n C o nv e n t i o n a l
C a p a c i t o r d i v i d e r Vo l t a g e
Transformers, where the magnetic
part is replaced by electronics
Primary Converter, offers many
advantages:
Takes advantage of inherent
low cost technology (CCVT)
Uses standard products
manufactured in several unit of
production ; proven solution for
capacitor divider using mixed film/
paper/oil technology
EHV-VTCE could be developed
for Extra High voltage applications
and improves measurement
performances by offering:
Harmonics capability
Extended metering Class
protection
51
NCITs are
successfully
implemented
in high
voltage
substations
in different
countries
7 La Prairie substation CTOs
signal
time
DELAY D1+D2
PAC.WINTER.2008
61850
protection
52
system related applications. Many
chapters exist in this standard that
define several levels of abstract
c o m m u n i c at i o n s a n d t h e i r
implementation in real substation
communication networks - in
particular Parts 8-1 and 9-2 that are
respectively dedicated to defining in
detail the digital protocols between
the different types of substation
secondary devices.
The three main t ypes of
substation communications are:
Client (mostly an HMI or
other substation level function) Server (IED)
Peer-to-Peer based on GOOSE
(Generic Object Oriented
Substation Events) between IEDs
Instrument Transformers
( C o nve n t i o n a l
o r
Non-Conventional) to IED – based
on the sampled values produced by
a Merging-Unit
Because the IEC 61850-9.2 was
a protocol largely open to the future
that should not restrict any possible
applications, there were many
parameters that are not fixed and
are subjected to different technical
choices. This supports the required
flexibility of the standard that
makes it future-proof. However, it
introduces an interoperability issue
that had to be resolved.
The joint efforts of several major
manufacturers under the umbrella
of the UCA International Users
Group resulted in the publication
of implementation guidelines for
substation applications.
Interoper abilit y bet ween
merging units and protection,
control, monitoring or recording
devices is ensured through this
document. Two modes of sending
sampled values between a merging
unit and a device that uses the
data are defined. For protection
applications, the merging units send
80 samples/cycle in 80 messages/
cycle; i.e each Ethernet frame has
the MAC Client Data containing
a single set of V and I samples. For
power quality monitoring and
waveform recording applications
PAC.WINTER.2008
such sampling rate may not
be sufficient. That is why 256
samples/cycle can be sent in groups
of 8 sets of samples per Ethernet
frame sent 32 times/cycle.
The information exchange
for sampled values is based on a
publisher/subscriber mechanism.
The publisher writes the values in
a local buffer, while the subscriber
reads the values from a local buffer
at the receiving side.
A time stamp is added to the
values, so that the subscriber
can check the timeliness of the
values and use them to align the
samples for further processing.
The communicat ion system
shall be responsible to update the
local buffers of the subscribers. A
sampled value control (SVC) in
the publisher is used to control the
communication procedure.
Figure 4 shows a simplified
block diagram of a merging unit
including amplifiers, filters, analog
to digital converter and DSP signal
processing. The merging unit is
synchronized using 1 PPS signal
from a GPS receiver. As can be seen
from the figure, there is a time delay
D = D1 + D2 introduced within
the device. If this time delay is not
compensated, it will be seen as a
phase shift (Figure 6) that will affect
all functions using the sampled
analog values.
The receiving devices then
process the data, make decisions
and take action based on their
funct ionalit y. The act ion of
protection and control devices in
this case will be to operate their relay
outputs or to send a high-speed
peer-to-peer communication
message to other IEDs in order to
trip a breaker or initiate some other
control action.
There is an important detail
that needs to be considered when
processing the data by the receiving
IED. The sampling rate in the
merging unit is fixed, because the
samples/cycle are defined at the
nominal frequency of the system.
At the same time, the protection
algorithms in most cases are based
on frequency tracking with a fixed
number of samples/cycle at the
frequency of the system.
Many devices that are used both
as conventional IEDs and IEDs with
process bus interface capabilities
have sampling rate different from
the 80 samples/cycle. This will
require re-sampling in order to run
the different protection and other
algorithms. (Figure 5)
A doc ument itself can
never convince a user that all
interoperability issues are resolved.
Especially protection engineers.
They need to see it to believe it. That
is why multiple interoperability
demonstrations between major
manufact urers on NCI T and
protection and other IEDs were
organized to show that this is not
emerging, but existing technology.
The recent CIGR E 2006
DEMO presented a small part of a
substation where several devices
from different vendors were
involved in an IEC 61850 process
bus interoperability demonstration
involving both merging units and
protection devices. The test device
injected currents and voltages into
the different merging units that
were interfacing with IEDs from
a manufacturer different from the
one that produced it.
The Demo was a real success
and the perspective of using this
technology excited many visitors.
Following the very successful
experiment made with NCIT and
distance protections interfaced by
The Process Bus
information
exchange is based on
publisher/subscriber
mechanism
Another result is the practical
elimination of C T saturation
because of the elimination of the
current leads resistance RL.
In this case the CT secondary
is connected to the phase current
inputs of the Merging Units and
RL is practically equal to zero. The
knee-voltage then will be only
dependent on
Process bus
based applications
offer some
important advantages
over conventional
analog circuits
61850
a digital communication at EDF/
RTE France during more than three
years, several other pilot projects
were launched:
NGT (U.K.), Osbaldwick 400
kV GIB, with hybrid sensor like :
Rogowski coils and capacitor
electronics
RTE (France), Saumade 245
kV GIS substation with hybrid
sensors, MU and dist ance
protections,
HQ (Canada), La Prairie 315
KV AIS substation , with CTOs,
and conventional CCVTs mixed in
the Merging Unit. (Figure 7)
The first experiment is
conduc t ed w ith NG T on a
GIL connecting two parts of
a substation. Osbaldwick and
Thornton substations, separated
by thirty miles, are involved.
A differential line protection is
installed working with NCITs on
one end and conventional ITs on
the remote end.
The second one with RTE is
Saumade GIS 245 kV substation,
using NCI T based on hybrid
technology (Rogowski coils and
capacitors), connected on the
merging-unit and interfaced
digit ally w ith t wo Dist ance
protections, provided by Areva and
Siemens, and a Landys+Gyr meter.
The third one is driven by
Hydro Quebec and shows an
application with optical Faraday
sensors at 315 kV, in the substation
La Prairie, near Montreal. Extreme
temperature variations make a good
demonstration of the technology
reliability and stability in accuracy.
Here again, protection devices
come from different manufactures,
showing interoperability. (Fig. 8)
Process Bus Benefits
Process bus based applications
offer some important advantages
over conventional hard wired
analog circuits. The first very
important one is the significant
reduction in the cost of the system
due to the fact that multiple copper
cables are replaced with a small
number of fiber optic cables.
protection
53
VK = f ( RCT, RRP )
In this case the impedance of
the merging unit current inputs
RRP is very small, thus resulting
in the elimination of CT saturation
and all associated with it protection
issues.
An addit ional benefit of
process bus based solutions is the
improvements of the safety of the
substation by eliminating one of
the main safety related problems an open current circuit condition.
Since the only current circuit is
between the secondary of a current
transformer and the input of the
merging unit located right next
to it, the probability for an open
current circuit condition is very
small. It becomes non-existent if
optical current sensors are used.
Last, but not least, the process
bus improves the flexibility of the
protection system. Since current
circuits can not be easily switched
due to open circuit concerns, the
application of bus differential
protection, as well as some backup
protection schemes becomes more
complicated.
The above is not an issue with
process bus, because any changes
will only require modifications in
the subscription of the protection
IEDs receiving the sampled analog
values over IEC 61850 9-2.
The Future
The process bus is a ver y
promising technolog y. First
experiences have proven its
feasibility. The simultaneous
experimentation of NCIT and
process bus has first been driven by
the NCIT in order to connect them
to protection systems. The test of
both technologies is probably one
of the reason of the limited use
today of the process bus. The focus
on purely the process bus with
conventional sensors is likely to
develop the business, for instance
for retrofit (replacement of cable)
and voltage distribution (also in
MV) applications.
The industrial optimisation
phase shall now start in order to
bring fully cost effective solutions
and be generalized. New IEDs based
on IEC61850-9-2 (protective
relays , Int elli g ent Mar gin g
Unit, etc.) will become available
progressively, while in parallel, the
utilities will gain confidence in
“protection over process bus”.
8 Protection panel with merging unit
Merging unit
interface
with different
protection
devices
PAC.WINTER.2008
TVA has paved the way.
ABB is a proud supplier for TVA’s
Bradley Substation Project
Every innovation needs to prove its
readiness and benefits, and a partner
willing to take the first step. ABB
thanks TVA for the excellent project
cooperation and is committed to further IEC 61850 projects on any scale.
Selected for the Bradley project, ABB’s 670 series family of relays and controllers is one of the first to prove the multi-vender interoperability of IEC
61850 on a commercial scale. Packed with functionality, the 670 series is
also DNP 3.0 compliant, has an intuitive relay setting tool, and a creative
packaging concept. As part of the extensive ABB portfolio, the 670 series
will enable you to improve you system’s reliability now and into the future.
Visit www.abb.com/substationautomation
© Copyright 2007 ABB
Power and productivity
for a better world TM
Iana A. Apostolova J.D.
Basic Legal Terms
Possible
Legal
Concerns
"Negligence" is a legal term of
significant importance in determining
the liability of a person or any other
legal entity.
In its coverage of legal matters, the media generally focuses
its attention on “juicy” criminal
cases and rarely pays attention to
lawsuits in other fields, such as
the electric power industry. One
of the rare occasions when this
does happen, is when a blackout,
or other major disturbance, hits a
large metropolitan or geographical
area. Power interruption to many
utility customers may result in
significant losses. In order to compensate their losses customers may
file individual lawsuits, or when
the number of affected customers
is rather substantial – a class action
lawsuit.
This is not just speculation – there
are recent examples that demonstrate the exposure of the utility
industry to such legal actions. For
example, shortly after the August
14, 2003 blackout, Cauley, Geller, Bowman and Rudman, a New
York based law firm, filed a classaction lawsuit on behalf of the 50
million people who lost power during the blackout. One of the questions that protection, automation
and control professionals should
ask, is what can be done to reduce
the exposure of a utility to such
lawsuits, especially in cases of different types of power interruption
that are caused by the operation of
different protection, automation
and control systems. In order to
understand the legal exposure of
electric power suppliers, we need
to define further some legal terms
related to negligence. There are
different levels of negligence, and
liability is dependent on the findings of what degree of negligence
can be asserted in a lawsuit.
Black’s Law Dictionary is widely
held as the authority for definitions of legal terms in the legal
community. Regarding negligence, Black’s Dictionary (7th Edition)
states, in part: Negligence is “The
failure to exercise the standard
of care that a reasonably prudent
person would have exercised in a
similar situation; any conduct that
falls below the legal standard established to protect others against
unreasonable risk of harm, except
for conduct that is intentionally,
wantonly, or willfully disregardful
of others’ rights.”
Legal Issue
55
Gross negligence is defined as “A
conscious, voluntary act or omission in reckless disregard of legal
duty and of the consequences to
another party, who may typically
recover exemplary damages.”
Criminal negligence is “Gross negligence so extreme that it is punishable as a crime.”
It is obvious from the above definitions that the determining factor in any specific case will be to
establish what the “standard care”
is and what a “reasonably prudent
person” would do.
One of the challenges in resolving
these issues is the fact that the
technology is changing very fast,
with computer and communications based systems enabling new
ways for limiting the impact of abnormal system conditions on
sensitive customers. So something
that might have been a reasonable
solution in the world of electromechanical and solid state devices,
may be considered inappropriate
in the world of the new technology. The protection, automation
and control industry needs to carefully consider and establish references that will help professionals
in the field understand what a “reasonably prudent person” would
do in a specific application in order
“to protect others against unreasonable risk of harm”
PAC.WINTER.2008
Biography
Iana graduated
from UCLA in
2001 with a
major in Political
Science. In 2005
she was awarded
the degree of
Juris Doctor,
from Loyolla Law
School.
During her
studies, Iana
worked for Soft
Power Int., where
she became well
aquainted with
the engineering
world. She
furthered
her business
knowledge
working for
Insurance
Marketing Inc.
Upon graduating
from Law School,
Iana joined the
Criminal Defence
field, where she
has devoted her
talents to fight
for her clients.
Iana is currently
working on her
MBA from Ashford
University.
by Volker Leitloff, France
Transmission Protection
France
56
RTE uses on
transmission
lines 2 main
protections
from different
manufacturers.
RTE Transmission Line Protection
(Issues and Solutions)
RTE is the French Transmission
System Operator. It operates a
network comprising approximately
100 000 km of lines and 2450
substations. Almost half of the lines
correspond to the transmission level
(400 kV and 225 kV) including the
interconnections to the neighbor
countries, the other half belong to
the regional sub-transmission level
(90 kV and 63 kV). Today, RTE
operates approximately 16,000 line
protection relays, 15% of which are
digital.
RTE has elaborated a set of
documents used as reference
for the protection of all network
components. The protections to
be used are defined depending on
the voltage level, the component to
be protected and its characteristics
(underground or overhead lines,
busbar, transformers, etc.) and the
importance of this component in the
network. One of the main principles
applied to the protections by RTE
is that a protection should only
clear faults related to short circuits
or other equipment failures. That
means that protections must neither
trip under overload conditions
nor due to power swing. There are
specific automatons dedicated to
Volker Leitloff, earned the Dipl.-Ing. degree from the University
of Stuttgart/Germany in 1991 and the Dr. INPG from the Institut National Polytechnique de Grenoble (INPG) in 1994. From
1994 to 2002 he was with the R&D Division of EDF working on
fault location and HIF detection in compensated MV networks,
protection of transmission networks, power transformers and
network technologies. Since 2003 he has been with the French
Transmission System Operator RTE where he is in charge of the
development of a Digital SAS for small HV substations.
PAC.WINTER.2008
detect these conditions and to trip,
if required, in a controlled and preset
way that limits the consequences to
the network
In this context, a "short line" is
defined as a line for which the zone 1
of distance protections cannot be set
to 80% of the line length, requiring
thus a blocking scheme with the
associated telecommunication
equipment.
The main problems RTE is
confronted with at the moment as
far as line protection is concerned
arise from the fact that several
regions have a highly meshed
network, leading to particular
constraints in the coordination
of the protections of several
substations. The installation of
capacitor banks, transmission lines
with high load capability, phase
shifting transformers, SVC's and
multi-terminal lines have been
RTE
Highly meshed
networks lead
to constraints
in protection
coordination
adding constraints over the past
decade.
For transmission lines (400
kV and 225 kV) RTE uses 2 main
protections (Distance and / or Line
differential), each from a different
vendor. The power supply of these
protections relies on the same
battery and charger. The circuit
breakers have in some particular
cases a redundant trip coil and single
pole tripping. RTE also uses an
elaborated reclose scheme. For this
voltage level, RTE uses a permissive
tripping scheme of the distance
protections. For the HV voltage
level, only three-phase tripping and
reclosing is normally used.
On the sub-transmission level,
line bays are equipped with one main
and one backup protection. Except
the lines where blocking schemes
have to be applied (short lines)
or for cables (current differential,
sometimes transfer trips), there is
usually no communication between
the relays at the ends of the line.
The new equipments appearing
in the network (those mentioned
above and probably others to come)
increase both the need for selective
tripping and the difficulties to
obtain it.The growing complexity
of setting parameters, the proper
administration of hard- and
software versions of protections and
of the associated setting parameters
are included in the challenges the
protection engineers will have to
face in the coming decade.
by Graeme Topham , S. Africa
One of the main challenges currently being faced is an increase in the
number of high resistance faults which fall outside the capability of the impedance
protection. The current solution being considered is to apply direction earth-fault
comparison protection as an additional protection function.
Eskom is the South African
electricity utility, generating 95%
of the electricity used in South
Africa. Eskom’s total net generation
capacity is 40 GW.
Rapid growth in the country
in recent years has seen the load
increase so that the current spinning
reserve is less than 8 %. This has
put immense pressure on the
transmission system in terms of
transferring the required power
from the generation to load centres.
The 28 000 km transmission
system includes lines above 132
kV at voltage levels of 220 kV,
275 kV, 400 kV and 765 kV. Also
included is 1 000 km of 533 kV
d.c. used for importing power from
ESKOM
the neighboring Cahorra Bassa
scheme. In the mid-1980s, Eskom
commissioned the first 765 kV
transmission line and currently has 1
153 km of 765 kV lines in operation.
As part of the current 42 billion
USD expansion programme over
the next 5 years, Eskom is building
an additional 1 500 km of 765 kV
lines to strengthen the transmission
capacity between the generation
pool in the North East to the Cape
(one of the main load centres in the
South West of the country).
Lines having a length of more
than about 200 km are considered
to be long whereas short lines
are generally those less than 10
km. However, from a protection
perspective, the Source to line
Impedance Ratio provides a better
assessment in terms of the protection
needs. Duplicated protection is
used for all transmission lines, with
duplicated impedance being applied
in the majority of cases. For short
lines, duplicated current differential
protection is used. In most
instances, identical relays are used
for Main 1 and Main 2. The decision
to apply identical protection systems
is based on a number of considered
issues (e.g. training, spares holding
etc.) and also on doing rigoros type
and model power system simulator
testing on all relays before applying
them to the network. To date, this
philosophy has proved successful.
All transmission stations are
equipped with dual battery systems
feeding each Main protection
system. Trip coils are also duplicated
in all instances. Approximately 30
% of transmission line protection
relays applied are of numerical
technology.
A number of the 400 kV lines
are series compensated, with plans
to add additional series capacitors
to both the 400 kV and 765 kV
networks. Single-pole tripping and
reclosing is applied on the majority
of the transmission lines. There are
some exceptions where operational
requirements or limitations of
equipment preclude the use of
single-pole tripping and reclosing.
On the impedance-based protection
schemes, Permissive Overreaching
is applied. In addition, a separate
channel for direct transfer tripping
is employed to facilitate the transfer
tripping of the remote line end
when required.
All impedance relays are selected
to block for power swing conditions.
Separate power swing tripping relays
are applied at strategic locations to
measure out-of-step conditions
and to effect system separation at
pre-determined locations so that the
resultant sub-systems are viable and
stable with the minimum of load
shedding needing to be applied.
One of the most important
issues related to transmission line
protection is ensuring that the
engineered protection schemes meet
the increasingly demanding needs of
the Eskom power system.
Transmission Protection
ESKOM - Transmission Line
Protection Issues and Their
Solutions
South Africa
57
Graeme Topham holds a bachelor degree in electrical engineering from the University of
the Witwatersrand. He is a registered professional engineer in
South Africa and his experience
includes 27 years in the field
of power system protection.
Graeme is currently Corporate
Consultant (Protection) in the
Engineering Department of
Eskom Enterprises and is the
South African member of Cigré
Study Committee B5.
PAC.WINTER.2008
by Dean Sharafi, Western Power, Australia
Transmission Protection
Australia
58
When both
protections
are of the
same type,
they are from
different
manufacturers
or principles.
Western Power
Transmission Line
Protection Design &
Philosophy
Western Power is the
state-owned utility of Western
Australia and operates varios
voltage levels in Transmission and
Distribution network. Transmission
voltages include 66KV to 330KV
covering a large area connected
through the network (South West
Interconnected System-SWIS). It
contains around 88000 km of power
lines with load around 3600MW.
The complete scheme for 220KV and
330KV lines consists of duplicated,
fully independent and discriminative
protections capable of providing
high-speed fault clearance over the
entire line length. These protections
may be either unit types, such as
differential, phase comparison,
or distance with tele-protection
signalling (using direct or permissive
transfer tripping).
These protections use separate
tele-protection signalling equipment.
A single communication bearer
to accommodate all the signalling
channels is considered acceptable
except where both protections
require information from the
remote end for its basic operating
characteristics. In this case, each
protection has independent bearer.
The complete scheme for major
transmission inter-connectors
(132kV and below) consists of
duplicated, fully independent and
Dean Sharafi graduated Isfahan University of Technology in
Applied Physics and Power and Water Institute of Technology in Electrical Engineering (Power Systems). He obtained
a Graduate Certificate in Business from Curtin University of
Technology in 2007. He currently manages the Transmission
Field Engineering Section of Western Power, the state owned
utility of Western Australia
PAC.WINTER.2008
discriminating protections capable
of providing high speed local fault
clearance and high speed remote
fault clearance on one protection,
and medium speed remote fault
clearance on the second protection.
These protections may be unit,
interlocked distance or plain distance
types. Regional inter-connecting
lines at 132kV and 66kV have the
same philosophy for protection.
Regional transmission feeders from
major transmission substations
enjoy the same st andard of
protection with addition of a remote
backup protection (of the form of
an IDMT overcurrent function) to
cover conditions on the regional
transmission network outside the
scope of normal design. Designing
the protection for each line category
depends on the length of the line.
Short lines are less than 10 km,
intermediate lines - up to 25 km and
long lines - more than 25 km.
Fault levels in the major transmission
network are high, for example, 20
GVA at 330kV. One of the main
Western Power
limitations in our system design is
the speed at which high power faults
can be cleared from the system,
particularly three phase faults.
The types of protection schemes
adopted for transmission lines are:
Current differential (comparison
over microwave radio/optical fibre)
Circulating current/opposed
voltage (pilot)
Interlocked distance
Distance
Over-current and earth fault
Unit protection schemes (eg. pilot
protection) and non-unit protection
schemes (eg. distance protection) are
often used on the same line to take
advantage of their complementary
performance. Protection No.1 has
arbitrarily been chosen for the unit
protection, or the protection with
the highest speed.
Where both protection schemes on
a line are of the same type (eg. double
distance protection) they are based
on different operating principles
or are sourced from different
manufacturers. This is to reduce the
risk of common mode protection
failure.
Where duplicate unit schemes
(eg current differential) are used
they use separate communications
bearers over different routes. Voltage
transformer supervision is used in
conjunction with all distance relays.
Earth fault relays are used on all lines
(as part of Protection No 2) to help
detect high resistance earth faults
outside the sensitivity of the main
protections, and to provide general
system back up protection.
Breaker failure protection is
installed with the fastest and most
comprehensive protection.
Single shot reclose is used for feeders
at metropolitan substations and
two shot reclose for feeders at rural
substations. On newly designed
EHV lines high-speed single phase
auto-reclosing scheme is used to
improve reliability of the system.
In our transmission network 90%
of relays are micro-processor based.
Older relays are constantly replaced
with new micro-processor ones.
by Iony Patriota de Siqueira
59
The main issue related to
transmission line protection
seems to be the large number
of specific cases.
The Br a zili an elec tric
system is singular due to its large
geographical area, supplied mainly
by hydro power plants located on
rivers far from the load centers. The
main generation source is Itaipu,
a bi-national (Brazil & Paraguay)
power plant with an installed
capacity of 12,600 MW. Large
portions of the Brazilian territory,
mainly on the Amazon region,
remain attended by isolated thermal
systems, with scarce transmission
resources. At the other extreme,
highly dense load centers are located
on main industrial and metropolitan
areas on the Atlantic coast. The
main transmission corridors and
international connections of this
system cover an area superior to that
of the whole Western Europe
To cover such a large area,
Brazilian electric system has
more than 1150 transmission
lines (greater than 69kV) at 138,
230, 345, 440, 500 and 750kV,
linking over 600 substations, most
considered long transmission lines
(> 30km). The highest voltage in
use links Itaipu power plant to the
Sao Paulo area by two 565 mile (910
km), 750-kV AC lines and two 600
mile (980 km), 600-kV DC lines.
The 500-kV technology is mostly
based on compact transmission lines
with self-supporting steel towers
that have been successfully used
on the Brazilian system for more
than 10 years. Load concentration
has also determined the need for
short transmission lines (< 30km)
connecting mainly urban stations.
Many special issues need to be
dealt in the protection of a system
this large, from zone reach settings
and selectivity of short lines to high
line charging with low short circuit
current in 500kV long lines. On
series compensated lines, several
special measures are taken: zone 1
setting is disabled when capacitor
is located at the remote end and
the line is 70% compensated
(overreaching of 2nd/3rd zones
may occur, especially when there are
capacitors at the remote end or at the
beginning of the next line).
Voltage inversion is dealt using
positive sequence voltage memory
polarized relays, while overreaching
due to sub-synchronos resonance
between line and capacitor is
compensated for Zone 1 (when
enabled) by means of a security
factor. Fault location errors occur for
specific cases. Current inversions are
not common, but have been recently
detected during a protection type
test using RTDS for some lines in
the Southwest 230 kV system.
In mutually coupled lines,
overreaching of ground Zone1
due to zero sequence current
reversals dictates the use of mutual
compensation. In lines with
tapped loads, Zone1 settings are
Brazil
Transmission Protection
Brazilian
Transmission
Line Protection
Issues & their Solutions
CHESF
compensated for under-reaching
due to in-feed effects.
The follow ing protect ion
philosophies are used: two identical
distance or differential plus distance
protection (Main 1 and Main 2) for
all 500kV and new 230kV lines
(after Grid procedures took place),
with redundant batteries and trip
coils. Primary and backup distance
plus ground overcurrent protection
continues to be used in old 230kV
lines, with single battery and trip
coil. Single pole trip and reclosing is
used on selected 500kV lines for SLG
faults. Communications are used for
some line differential protection and
teleprotection (all 230kV and above)
in several schemes: Permissive
Overreaching Transfer Trip (POTT),
Permissive Under-reaching Transfer
Trip (DUTT), and Direct Transfer
Trip (DTT). Blocking is used for
power swings, with tripping when
separation of interconnected systems
is required. Load encroachment has
not been necessary but is available
on the relays.
Adaptable multifunctional digital
relays, supporting interoperability
with other schemes look like the
right direction to their solution.
Iony Patriota de Siqueira, was born in 1951 in São José do Egito, Brazil. He graduated in Electrical Engineering, with an M.Sc.
degree in operations research from Federal University of
Pernambuco and an MBA on Information Systems from Catholic University of Pernambuco. He is a member of Cigré and
IEEE, Manager of Protection and Automation at Chesf Hydro
Electric Company of San Francisco River) and Regional ViceDirector of Abraman, the Brazilian Maintenance Association.
PAC.WINTER.2008
p
s e
et
rg
r
e o
i v
the guru
Still too
many things
interest
me.
1943
PAC.WINTER.2008
Wo
rki
ng
Solving
two or even
more tasks
simultaneously
is more brain
training than
complication.
19
47
I would like
to work as long
as my head can
be of any use...
It is interesting
to solve difficult
problems.
Feodosia 193
6
Yakovlevich
60
the guru
Biography
Sergei Yakovlevich Petrov was born
in Achinsk, Krasnoyarsk in 1922.
His studies in the Moscow Electric
Power Institute were interrupted by
the attack of Germany on Russia in
1941. He was sent to Military School
and after graduation as a lieutenant
was sent to the front. In December
1942, near Stalingrad, he was heavily
injured and lost his leg. He later
continued his education, graduated
in 1947 as an Electrical Engineer
and started his carrier in the electric
power research and design institute
Energosetproekt in Moscow.
During his carrier reached the
position of Deputy Principal
Engineer and worked on a wide
range of projects – from generator
to extra-high voltage transmission
line protection. He was USSR’s
representative to CIGRE Study
Committee 34 and participated
in international projects in India
and Bulgaria. In 1962 he received
the Lenin’s award in science and
technology. He retired in 1991, but
still works as Principal Specialist in
power system protection.
Sergei Yakovlevich Petrov
Interview by Andrei Podshivalin: PAC World Correspondent
PAC.WINTER.2008
Sergei Yakovlevich Petrov
the guru
62
Team district champioship 1954
As a student I
PAC World: Sergei Yakovlevich, you have left behind
several historical epochs. Could you tell us about your
childhood??
SP: I grew up in Feodosia (Crimea, Ukraine). I graduated
school with excellent marks. This would be equivalent to
a “gold medal”, but there were no medals (for excellent
studies) at that time. I was going to become a doctor,
but my father convinced me it was a very demanding job.
I was later sometimes sorry for not becoming a doctor
because I wanted to do work in “folk medicine”. I consider
this would have been the most interesting.
PAC World: What seemed attractive in folk medicine?
SP: I like to solve problems. I consider this task as very
promising and comprehensive. Nevertheless, I like my
present profession. There is certain gain, advantages
and pleasure in relaying. It attracts me; I strive for deep
knowledge and try to relay my experience and my love for
our profession to young engineers. In general, tasks can
be found everywhere. You know, even a street can be
swept in different ways: boring and droning is one way;
creative and permanently improving is another. If you like
your profession, the knowledge is revealed in the work
PAC.WINTER.2008
process. The more you know the more
interest you take on. My father loved his
Institute chess profession too. He organized the first
T.B. prophylactic centre.
team.
PAC World: You seem to have a broad
outlook. Tell us about your education.
SP: I was getting a home education until
the forth grade. I took classes in music
and French. At school I also studied German. I remember
most of what I studied at school: genetics, history etc.
It is interesting that everything was taught in a different
way. It was Soviet time, and we were children of the
Soviet epoch. We sang revolutionary songs: “Our steam
locomotive rushes on…”, “We don’t want a single inch of
foreign land…”, “If the enemy attacks…”, “Steamship goes,
starting waves…”.
PAC World: How did it happen that you became a power
engineer?
SP: At that time the country lived in five-year plans that
had to be accomplished in four years. Personnel are
everything – that was the slogan at the time. The country
was building communism. I wanted to build too. I entered
played for the
Sergei Yakovlevich Petrov
the power engineering department of the Moscow Power
Engineering Institute.
PAC World: And why relay protection?
SP: When I was a child, I was interested in radio
engineering, just as many other boys. I assembled several
types of receivers. I was proud of one of the radios
– it was tuned by rotating one coil towards another.
Unfortunately, I have not saved this apparatus. There was
something in relay protection that attracted me most:
one may find a problem, design a solution, introduce new
features, and implement it. It was much easier then for a
novice to assemble a relay or another device, implement
your ideas yourself.
PAC World: Did you have other interests in your youth?
SP: I played football and volleyball for the Crimea junior
team. Once I became a chess champion of Feodosia.
However, the childhood was not easy - we were three
children in our family. My father worked hard: in addition
to the T.B. centre he worked in other sanatoria in order to
live decent life. It was a time of hunger since the country
was still recovering after the civil war.
PAC World: Were you a hard-working student in school?
SP: I wouldn’t say it. My sister often did my homework.
I used to replace my music classes with football games.
Now I am sorry for that since playing the piano is relaxing
and allows me express my emotions and feelings. To add
to this, I have always had a small zoo. I had dogs, rabbits,
a turtle, goldfish, a siskin, a rat – Anfisa. There was even
a hedgehog. It was always interesting with them and I
learned something new every time.
PAC World: Let’s continue to your student years.
SP: At the institute I wasn’t an exemplary student again.
I did not attend all the classes and studied every subject
by myself. I was successful in this self-education. At that
time I played for the institute chess team. I remember
one match with Averbach. He became a chess Grand
master later. Still being a student, I was awarded a Stalin
scholarship for excellent studies. I was not involved in
scientific research at that time.
PAC World: Then the war began. Did it influence your
life?
SP: It was after my second year at the institute, on
June 22, 1941, when we (students) listened to the radio
speech of Molotov. It was not a surprise. In fact, we were
spiritually ready for the war. We knew about the two
confronting worlds: capitalism and socialism. The public
also knew Hitler. In general, we were prepared for the war,
but we did not expect such a war, on our territory, with
great losses. There was mobilization. After a single-month
courses I became a trolleybus driver in Moscow. On
October 16, the enemy army was close to Moscow, most
establishments evacuated. I remember one scene from
that day. Passing close to a cinema, I noticed such a long
queue to the ticket-office. It was astonishing. Moscow was
under siege, but life continued, it did not stop. Together
with other students, we came to the institute. Everything
the guru
63
was in disorder - chaos, papers scattered, generally
empty. As a student, I was evacuated to Leninogorsk
(Kazakhstan) together with the institute. Then, there was
the second draft. This is how I ended-up in the military
school in Tashkent. I graduated as a lieutenant. It was a
brief education. The intention was to make me a teacher,
but we longed to defend our Motherland.
PAC World: What did the war change in your life?
SP: The army disciplines people, makes them more
accurate. I was a platoon (about 30 people) commander
on the battlefield, but I did not have a chance to fight for
long. At the end of 1942 in a village close to Stalingrad
(Volgograd now) I was wounded in the leg, in fact it was
torn off. I crawled somehow out of the combat zone and
hid in a basement. I did not feel it, but the blood loss was
huge. I was discovered by some soldiers and taken to a
hospital. The first half year I did not react much to the
outside world, but I mostly recovered in a year and was
released from the hospital. After that I went back to my
parents in Petropavlovsk (Kazakhstan) and decided to
continue my education.
PAC World: Was it easy to go back to school and adapt
to the new environment?
SP: Yes, it was. I entered the third year at the institute.
Most of the classmates were three years younger, but
that was not an obstacle to our friendship and common
studies. I continued self-education by books and passed
exams easily. After graduation, I was assigned to the
Teploenergosetproekt. Our division was then reformed
and named Energosetproekt. This is still my place of
employment.
PAC World: Did you have any remarkable events at the
PAC.WINTER.2008
Sergei Yakovlevich Petrov
the guru
64
Utilities should
try, test and
investigate.
institute?
Only this can
SP: I was lucky to enter the Relay
Protection, Automation, Stability, make it public
and Modeling department, where I
participated in research and design and let new
of the systems, development of
the techniques and the guiding techniques
documents, relaying principles, as
well as application. Most papers develop.
made by the department are still
of very high value and interest. This
work has always been and remains
interesting to me. There were many talented engineers
and scientists in charge of the department: A.M.Fedoseev,
V.L.Fabrikant, A.B.Chernin, V.M.Ermolenko, D.I.Azaryev.
I have always been active in international cooperation. I
was a representative in CIGRE Study Committee 34 for
quite a while. And I have never stopped playing chess and
participated in different competitions for the institute.
We had a special “Feodosia” society, for people originally
coming from Feodosia. I spent a lot of time in India during
our cooperation as part of a “friendly aid” initiative. We
built a power station close to Delhi. In order to be able
to communicate with my Indian colleagues I had to
learn English. India was a very interesting experience. In
addition, obviously I had new “pets” at home: a mongoose,
a hedgehog, a monkey and a wombat. I have many
impressions out of that. The mongoose is a dreadful, but
beautiful predator.
PAC World: During this period you were honored with
the Lenin award (the top award in the Soviet Union).
Tell us about it?
PAC.WINTER.2008
SP: Well, yes, our department was awarded in 1964.
At the institute we dealt with turn-key projects
for power utilities. Our work on ultra-high voltage
projects development was in fact awarded. We made
possible extra-long-distance transmission projects:
Kuybishev-Moscow, Stalingrad-Moscow. It was a miracle
at that time. Transmission was straight and several
intermediate switching substations did not change the
nature of this long line. Now you will not find such lines
on the map; they are transformed by the introduction
of generation in between. We solved this task together
with ChEAZ (Cheboksary, Russia) and VNIIR (Cheboksary,
Russia). This award let me feel like real relaying specialist.
PAC World: What other projects did you find most
interesting?
SP: All of the projects were interesting. First, I would
mention the microprocessor-based relay technology. We
had to master it. Second, I was the author of protection
implementation guidelines for most applications, including
distance protection. I believe it was an extremely needed
work. Nowadays every company is trying to conceal the
real operating principles. This is wrong from the utility
and application point of view, as far as every relay should
be set and coordinated. Sometimes this work helped to
discover mistakes in manufacturer’s formulae and relay
design. There were samples, which had been produced for
25 years, but not tested thoroughly enough.
Our level of scientific work was really high. I have never
felt that domestic relays lack features compared to the
world leaders. Unfortunately, there are less and less broad
specialists in the world. In relay protection, one must
always think of systems: design of a single protection
The Lenin award
for science and
technology made
me feel like relay
specialist.
scheme determines requirements for all other schemes.
Different kinds of protection are closely correlated.
PAC World: What do you think of the modern state of
relay protection?
SP: Most modern relays available on the market are
more or less equal in basic features and characteristics.
Most manufacturers perform all kinds of control and
tests before the product leaves the factory; sometimes
even soldering joints tests for conductivity, optical
monitoring etc. Nevertheless, even this high quality of
production cannot guarantee absence of failures but the
manuals rarely tell about reliability. I am glad that Russian
producers are at the same level with the leaders in basic
characteristics. I like the development teams in some
enterprises. They are researchers applying new scientific
features in their products. Long ago, we cooperated with
VNIIR. It was learning experience for all of us: we studied
relays, while the VNIIR staff learned the theory.
PAC World: What protection issues are most interesting for you now?
SP: Stability and reliability issues. These problems are of
minor priority now, while sooner or later we will be forced
to deal with them. Some time ago, it was easy to estimate
the reliability of electromechanical and static relays. It
was determined using the reliability of a single element.
PAC.WINTER.2008
Sergei Yakovlevich Petrov
Interconnections were plain and enumerable. In modern
relays this has not been investigated. The research work
is too expensive and no company can afford it. The leading
companies assume certain levels of reliability as postulates.
As an example, we can see installation of three protection
relays on a single line, which is considered “redundant”. The
question is if it is technically and economically justified.
I am glad that at the last CIGRE conference in Cheboksary
(Russia) speakers presented several reports on stability
and reliability. This type of studies cannot be private - they
should be led by governmental organizations in protection,
which, as far as I know, are currently missing in Russia.
Manufacturers’ mean time between failures equal to 30
years seems very low in the modern world. When there
are many elements in a substation, we should think of
some other units to measure reliability. Consider the case
when we have hundred devices in substation. What shall
we do then? However, I estimate the reliability of the
modern systems close to 0,97 - 0,98.
PAC World: What are your personal achievements?
SP: Achievements ? Well, I probably collected much
knowledge and I can continue working over the problems,
I can help young people get to know the nature of relay
protection. I am thinking about expressing this knowledge
on paper. There are proposals from magazines, but, you
know, I wasn’t used to publishing many papers. It was
mostly institute proceedings and application guidelines.
However, I think I was lazy. I am not satisfied with this
part of my professional life. I could publish more, even
my teaching materials at the qualification courses. When
there is a task to solve, it is of interest; when I find the
solution, my interest fades away and there is no personal
reason to write a complete paper.
PAC World: What do you think of the “protection concept” being under development in Russia?
SP: My opinion is that this concept already exists as a
general idea. The concept is providing an uninterrupted
power supply to the consumer, ensuring reliability. To
implement the concept a number of solution
criteria should be invented. I'm not familiar with the
final review of the document and, therefore, cannot
evaluate it.
PAC World: What obstacles in remote back-up protection do you see?
SP: I The main problem is the remote-end in-feed for
the remote faults. It decreases the sensitivity of the
protection. Therefore, my suggestion is a single weak
component principle. This gives some advantages. All
protections in series are coordinated with each other. This
makes settings of protections at the sources very high.
The weak component will decrease these settings. Of
course, the sequential tripping of the element is a sacrifice.
This solution is currently not applicable if the substations
belong to different owners. People forget that the power
system is our common roof and if it somehow collapses,
the consequences are common too. This is the main idea
of my papers and recent reports. These problems should
the guru
65
the guru
66
Protection specialists are much more than
relaying specialists - we must have understanding
of other areas like primary equipment: machines,
Sergei Yakovlevich Petrov
transformers, switchgear, automation.
be solved in the new economical environment. One of the
main problems is that the new technology is laid onto
the Procrustean bed of old regulations. As a first step,
we should revise regulations and instructions, which is
also very expensive. However, there are many parties
interested in this process.
For now, there are two such organizations in the world –
IEC and CIGRE. These two organizations develop standards,
which are then adapted in many countries. There is a
good example with EMC tests, which are acknowledged
almost everywhere. This was a tremendous work based
on lots of measurements. This investigation required
special equipment, which was designed and actuated. The
results are now excellent. Now we need to create a similar
Russian interagency organization dedicated to the relevant
problems. This group should unite manufacturers, as well
as utilities in order to be legitimate. It should develop the
unified technical policy. These functions were assigned to
ORGRES in old times.
PAC.WINTER.2008
PAC World: What do you think of the new generation?
SP: Unfortunately, in my opinion, the personnel are
undereducated now. The quality of teaching should be
the main task. The scientific level should be improved too.
Studies performed by specialists in different companies
are often not published. Twenty years ago, these functions
were over VNNIE, which has almost disappeared. The
scientific tradition should be maintained. Utilities should
try, test and investigate. Only this can make it public and
let new techniques develop. This can be the role of the
scientific schools that we have.
PAC World: What is your attitude towards new technology in relay protection, for example IEC 61850?
SP: I do not have deep knowledge of the protocol, but I
see very positive tendencies in it. Protection schemes
should be somehow standardized. Utilities are just
starting to accept this protocol. It will take some time
before it is broadly implemented. This raises the question
of reliability once again. This concerns data transmission
and processing times, processing techniques and many
other issues to be solved for every device separately.
Nevertheless, this protocol has definitely a positive impact.
Unfortunately, domestic producers are still not compliant
with the standard.
PAC World: How do you identify retirement?
SP: Retirement is fading. When one works all his life and
has to leave it, it is a great tragedy. I would like to work
as long as my head can be of any use. I have worked in a
single company (the institute) for sixty years and reached
as high as the Deputy Chief Engineer (or Design Director).
It is interesting to solve difficult problems. Still too many
things interest me. Protection specialists are much more
than relaying specialists - we must have understanding
of other areas like primary equipment: machines,
transformers, switchgear, automation, fault modeling and
stability issues.
Interview by Andrei Podshivalin:
PAC World Correspondent
continued on pages 8 and 26
GALLERY
Photography by William Davis.
Op-art
Shot with a Olympus E510
Lens: f = 14-42 mm
1:3-5.6
PAC.WINTER.2008
PAC.WINTER.2008
PAC history
70
A protection device with the basic
functionality of a distance relay was
proposed in 1904 based on simultaneous detection of increase in current and voltage drop.
Biermanns J.
Dr. Rolf Wideröe
History is the tutor of life.
Westinghouse-Distance Protection
Wideröe-Relays, NJEV, 1933
Distance protection became the
most important protection technology in the twentieth century.
Wideröe-Relays, NJEV, 1933
One Relay
Impedance
Protection, S&H
Biermanns Distance Relay - Pl. 109223, AEG 1924
PAC.WINTER.2008
by Walter Schossig
Protection
PAC history
71
This article discussed only the industry’s initial approach to protection and selectivity
History
Biography
Distance
Protection
The Early Developments
The Zoned Voltage Drop Protection
At the beginning of the 20th century, effective protection
coordination using overcurrent or directional overcurrent
relays was no longer sufficient due to high clearing times
and operation with spur lines and rings circuits. Distance
protection became the most important protection technology.
Krämer, Chr., F&G proposed a protection device with the
basic structure of a distance relay in 1904. The patent claim
definition in DRP 174 218 by Felten & Guilleaume-Lahmeyer-Werke AG (F&G) was: “A relay for automatically switching
off an alternating current if the current is higher than a
nominal value. A series connected coil and a coil connected in
parallel exert a force on a rotatable disk. The intention is that
the closing time of the auxiliary contact is determined by the
current exceeding the nominal value and the associated voltage
drop.." See Figure 1.
AEG (Allgemeine Elektrizitäts-Gesellschaft) and the
company Dr. Paul Meyer AG made great contributions to
distance protection. Both were the first German companies to
put distance protection into operation around the same time
in 1923/1924 and contributed several patents prior to that. A
patent (by inventor Kuhlmann,K.) was granted to AEG on the
23th April 1908. The inventor proposed a Ferraris disk, driven
by current. A special voltage magnet worked as a brake and the
operating time was dependent on distance.
Another Kuhlmann patent was for a distance protection
device that worked as a balance-beam relay dependent on
undervoltage and overcurrent with a Ferraris anchor and
rotating armature (Patent: DRP 214 164). The balance-beam
is a mechanical device so the phase angle between the current
and voltage had no impact. Thus the impedance circle, typical
for electromechanical relays, was born.
The next invention was by Wecken,W.(Patent: DRP 248
466) and was the basic for selective voltage drop protection.
The relays that existed at that time were used for spur lines
with single infeeds. Wecken,W. proposed the ring operation
in 1912 and suggested using voltage drop relays to protect
the ring. A directional element to determine the direction of
the power during short circuits was not available. Meyer,G.,J.
developed a current and voltage dependent relay for ring
PAC.WINTER.2008
Walter Schossig
(VDE) was born
in Arnsdorf (now
Czech Republic) in
1941. He studied
electrical engineering in Zittau
(Germany), and
joined a utility in
the former Eastern
Germany. After the
German reunion
the utility was
renamed as TEAG,
now E.ON Thueringer Energie AG in
Erfurt. There he received his Masters
degree and worked
as a protection
engineer until his
retirement. He was
a member of many
study groups and
associations. He is
an active member
of the working
group “Medium
Voltage Relaying”
at the German
VDE. He is the
author of several
papers, guidelines
and the book
“Netzschutztechnik (Power System
Protection)”He
works on a
chronicle about
the history of
electricity supply,
with emphasis on
protection and
control.
PAC history
72
operation one year later. Although this relay worked without
a directional element just as other similar devices at that time,
Meyer’s patent (DRP 269 759) discussed the fact that the
direction of power should be the value being controlled.
The directional elements were not taken into consideration
for ring operation or with parallel lines because only one oil
circuit breaker was used in the substations at the time and
therefore it was not necessary to use a directional element.
Today, of course, we use circuit breakers in both directions to
maintain supply. (Fig. 2, 3, 6)
The operating principle of such a voltage drop device is
described as follows. Four driving cores beat against a drum
exerting a force. The coils of the cores are connected with a
resistance to the voltage. If the voltage is the nominal value, the
arbor is lifted by a silk cord. Under fault conditions, the voltage
decreases, the arbor will be "coiled up" with an associated
speed creating a distance dependent operating time.
A metal-filament lamp connected in series and adjustable
resistances allow a change of the characteristics (straight or
warped). (Fig. 7)
Biermans-Relays
In February 1916, Westinghouse El. & Mfg. Co. (inventor
Crichton,L.N., Patent: DRP 334 760) developed a relay
whose operating time was dependent on the ratio R/X = Z.
The device was equipped with a directional element. The
corresponding American patent 1 292 584 was issued on
January 28th in 1919 having been submitted for consideration
December 1912
In 1918 Meyer,G.J. developed an "N-Relay" (N=Netzschutz,
the German word for protection systems).
The 4kV network in Karlsruhe (Germany) was equipped
with distance relays in March/April 1913. The first
"Biermanns_Relays" (Fig. 4) were installed on ThELG’s (Gotha,
Thuringia, Germany) 30kV network in 1924 and it was there
that the first in-service tests for this relay took place (Fig. 5).
See Figures 8, 13. The red dot on the Biermanns-relay is the
color of phase-3. Three relays were necessary per feeder (Fig.
4). The operating times (Fig. 8) appear very high from today's
perspective but we should note that they correlate with the
practical characteristics of the oil circuit breakers that existed
at that time.
Due to the limitations of the breakers (decay of maximum
asymmetric short circuit current), the basic operating times
were in a range of 0.5 to 1s depending on the selected time
delay setting. However steady-state short-circuit current was
not dangerous in the substations in this time ("soft" machines
and current controllers). The setting characteristic was in a
fixed range calculated as 110 V/5 A = 22 Ω. If necessary, the
operating time could be decreased such that the two parts of
the current input windings were connected in series instead of
in parallel (See Figure 8).
In 1915 Meyer,G.J. introduced a method of switching
the voltage from phase-phase to phase-earth. This
switching became useful to improve the detection of
double-line-to-ground faults. Biermanns (AEG) used it with
either phase or zero sequence current in 1925.
Canadian Ackermann,P. proposed a combined voltage
and current relay using the resistance principle in 1920 (Fig.
11). Cansfield Electrical Works, Toronto began to use if from
1921. This was the first time that a step characteristic was used
and it continues to be used today. See Figures 12. The same
technique was used with the reactance protection developed
by Siemens, the Oerlikon Minimal Impedance Protection and
the new distance relays produced by Westinghouse Co. and
General Electric Co.
The Westinghouse Distance Relay was released in April
1923 and it is probable that the first substation in the US was
equipped with Westinghouse distance relays that same year.
Nevertheless, the use of the Westinghouse relay was not as
widespread as the German distance relays. One possible reason
might be, that in the US double-circuit lines were generally
used and these were protected with differential protection or
difference protection (balance relays). Meshed networks were
avoided with radial network as the preferred choice in the US.
1 Basic Scheme of a Distance Protection
2 Potential Grading during a Short-Circuit
(acc. to Chr. Krämer, F&G, 1904)
Figure 1:
a - ferraris disk
b - lever,
c - dead stop,
d - magnet,
influenced by
current,
e - magnet,
influenced by
voltage,
f,g - wiper,
h - tripping
magnet,
m - permanent,
magnet (works
as a brake)
PAC.WINTER.2008
A
G
B
U
a
b
at big machine power
A
D
U
a
b
a
G
C
B
b
at smaller machine power
C
D
The operating time is
determined by the current,
exceeding the nominal value
and the voltage drop.
The first substation in Europe that used Westinghouse
relays was the double-circuit line from power station
“Hedwigschacht” (Seestadl) to Prague in 1925. The utilities
“Thueringenwerk” and “Kraftwerk Thueringen AG” decided
to use Siemens-Westinghouse Relays for their 50kV network
in 1927 (Fig. 9). Note that Phase “R” (phase “a”) is not
covered. The first proposal for an AEG distance relay (type
1923) was made by Biermann,J. Several papers and patents
clarified the main distance protection topics. They explained
the impedance startup; reactive step logic element and the
logic used to detect double earth faults.
The name “impedance protection” (or “resistance
dependent relay”) arose from the fact that the operating
time changed with the voltage/current (=impedance) ratio.
Nevertheless Biermanns used the name “distance protection”
since the operating time was dependent on the length of
the line (German: “Distanzschutz”, French: “Protection des
Distance”).
In 1928 Brown, Boveri & Cie (BBC) and Siemens &
Halske (S& H) produced their distance relays according to the
European practice with consistent time characteristics. High
voltage lines used reactance relays since they had the advantage
that the arc resistance (ohmic) had no impact. Medium voltage
impedance relays with adapted phase shift were developed by
BBC. (Fig 10) An interesting “Bergmann-Elektrizitätswerke”
patent (DRP 403 934 and DRP 404 867 1923) was developed
by Schade,P. The distance relay proposed in the patent was
a device where the operation of one side was dependent on
3 Scheme of a
Voltage Drop Relay
4 First Impedance
Relays, both 1924
the apparent power, reactive power and resistance values.
The other side was operated by a clockwork device moving at
constant speed. The operating time decreased depending on
the line resistance between the fault location and the relay, i.e.
with the distance to the fault (on the spread).
Startup
Overcurrent startup is sufficient in normal situations on
medium voltage (4 up to 60kV) network because the short
circuit currents are larger than the nominal currents of the
assets being protected.
In meshed 110kV networks that have low power
consumption at night and on the weekends, the short circuit
current might be as little as the nominal values so under
impedance startup is necessary.
In solidly grounded networks, under impedance startup
is required to achieve phase selective startup. This avoids
incorrect startups on healthy phases caused by equalizing
(circulating) current (paradox of Bauch). Reactance relays were
the preferred choice in the 110kV transmission line grid to
eliminate the impact of arcs. Values up to 100Ω occurred in
off-peak periods prior to the electric arc being cut.
The first distance relay like the aforementioned N-relays,
Dr.-Paul-Meyer-AG; Biermanns, AEG and BBC relays were
5 Short-Circuit Test-Thuringia, Germany
6 Voltage Drop Relay (V & H)
PAC.WINTER.2008
PAC history
73
PAC history
74
7 Characteristics Voltage Drop Relay (V&H)
14
sek
12
10
a
08
b
06
04
02
00
0.0
times appear
very high
from today's
perspective
but we
should note
20
40
60
80
100 Volt
Parallel
Adjustable Characteristic
a
The operating
Distance protection was met
with criticism
in magazines and at
conferences at that time.
Serial
b
single pole devices with one startup, one time and one
directional element. Typically, 3 relays were installed on each
feeder.
Double earth faults were not normally expected in cable
circuits and it was expected that every fault would end in a
three-phase fault due the long control time in belted cables.
Distance relays provided by BBC and impedance relays of
Siemens in 1928 had similar designs. The first distance
relays that used the reactance principle were developed by
BBC and S&H in 1928. Unlike impedance relays, they were
used for supergrid applications due to the possibility of high
arc resistances in such applications. The first AEG distance
relays (with impedance startup element) were named "double
distance relays" in 1925/26. Biermanns made substantial
earnings from their successful distance protection relay.
However, distance relay manufacturing difficulties might
explain the reason why S&H preferred other protection
systems at that time.
In addition, distance protection was met with criticism in
magazines and at conferences at that time. The idea was new
for utilities although the distrust and skepticism decreased
with increasing numbers of successful short-circuit and double
earth-fault operational trials.
First Improvements
Many patents were granted in the first years of distance
protection technology development. Examples of patents
from 1908 up to the 1920's include those of Kuhlmann,K.;
Wecken,W.; Chrichton,L.N.; Meyer,G.J., Ackermann,P.
and Biermanns,J. Kesselring,Fr. combined the protection
and directional relays in one box, the "N-relay". Cohn,,A.
proposed to use bimetal strips, saturation transformers and
other elements. Kesselring,Fr. further developed the N-relay,
the voltage and directional elements from 1924 up to 1927.
The Norwegian Wideröe,R. was granted 41 German and 2
American patents in the years 1928-1932 when he worked
with AEG; during this time N. Jacobsens Elektriske Verksted
(NJEV) was granted 10 patents in Norway. See Figures14,16.
Short-Circuit Tests for Relay Usage in Grids
Ackermann,P conducted short circuit tests on Shawinig
Water and Power Co’s 50kV transmission network in 1920.
He observed that time relays with overcurrent tripping
devices did not trip due to the low short circuit currents in
small machine applications. The impact of arc resistance was
not considered at this time. He observed the reduction of the
current levels during the short circuit but explained it as a
that they
correlate with
8 Characteristic Biermanns-Relays, AEG,
1924 (parallel / serial)
characteristics
of the oil
circuit
s
the practical
35
30
25
20
15
10
breakers that
existed at
05
00
AEG
TWL 8192
0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10
Parallel
that time
PAC.WINTER.2008
11
Serial
9 S iemens-Westighouse 10 D istance Relays,
Impedance Protection
BBC, 1928
75
11
decrease of the initial short- circuit current up to the level of
Balance-Relays by Ackermann, 1920
sustained short-circuit current.
The Preuß. Kraftwerke Oberweser A.G. Cassel 60kV
network was fully equipped with V&H voltage drop
relays after short circuit tests were carried out. See Figure 5.
Other utilities also performed short circuit tests to collect
information about the performance of relays and the network
under fault conditions. One observation was that short circuit
currents could be smaller than the nominal currents. In 1924
Dr. M. Schleicher described the impact of arc resistance on
J
U
impedance relays. Arc resistance in their 110kV network was
investigated by the German utility "Bayernwerke" in 1926/27.
The proposal to use the reactance to estimate the distance to
Parallel
Serial
the fault was subsequently discarded.
Following significant investigations and network tests
with 30 relays, a Norwegian interconnection company
"Samkjöringen" (translation in English is ‘Cooperation’)
Induction or Immersion Anchor,
decided in 1936 to use distance relays to protect their main Westinghouse-Relays
lines in Eastern Norway. They used Dr. Wideröe, NJEV
protection scheme. The Viennese ELIN AG relays subsequently
acquired the commercial rights to this protection scheme. The
application of an AEG distance relay in a network model was
shown at a fair in 1924.
The advantages of distance protection relays were
demonstrated by statistics from Elektrowerke AG. They had
43 disturbances on their 100kV network in 1924. Most of
them originated in the medium voltage network. The relays
in the medium voltage (overcurrent and directional relays)
did not work properly 32 times and the number of trips was
3 times higher that they should have been. Replacement of
the relays with distance protection resulted in only 2 relay
misoperations during the 27 disturbances in 1927.
Six-, Three-, Two- and One-Relay-Schemes
Circuit Biermanns-Relays, AEG, 1923 /4
When distance protection was introduced it became
obvious that in a case of a double earth fault (base point of fault
in different phases of different systems) different measuring
values had to be used. Biermanns proposed a scheme in 1924.
The voltage coils were on the phase to phase voltage for
short circuit faults and were on the phase to earth voltage
for earth faults. He introduced the changeover of measuring
circuits with zero-sequence current in the summation current
circuit as is used today. The name "zero sequence startup" is
used incorrectly - in this application it refers to a changeover
of measuring values. O. Mayr proposed a similar scheme in
1924. The commonly used schemes for resistance-dependent
protection are described briefly. The following assumptions
were made:
there is no changeover in the current circuit
in isolated or compensated circuits there are
opportunities to reduce the number of CTs required, thereby
reducing the number of relays required
it uses startup overcurrent
The six relay circuit detects each and every phase-phase
fault and phase-earth fault with separate measurement
elements. In the case of a double earth fault (where a zero
sequence voltage or current occurs) the three relay circuit
11. The combined
voltage and current relay using
the resistance
principle, was
proposed by
Canadian
Ackermann,P.
in 1920
12
13
PAC.WINTER.2008
12. Medium
voltage
impedance
relays with
adapted phase
shift were
developed
by BBC
PAC history
76
14 Tripping Characteristic Wideröe-Relays, NJEV
8.0
7.0
t=f(z)
J=kost
6.0
5.0
10 Amp
20 A
4.0
30 A
3.0
50 A
2.0
75 A
1.0
0.0
0
10 A
1
2
20 A
3
4
5
30 A
6
7 skala for 10 Amp. curve
50 A
75 A
(Fig. 15) uses the voltage change between phases rather
than the phase-earth voltage. The two relay circuit uses two
measurement elements only with two current transformers.
A changeover is possible with the zero-sequence voltage
only. A further simplification is possible with one relay
circuit, also known as one relay impedance protection. Only
one measuring element is necessary and the changeover
is dependent on the zero-sequence voltage. The one relay
circuit (using 3 current transformers with measuring value
changeover in the case of a zero sequence current) is the default
solution in the medium and high voltage applications. Subject
to phase or zero sequence current startup, the measuring
element is connected via interposing relays to the currents and
voltages (in accordance with directional elements).
To avoid a changeover of the currents, current proportional
values are obtained from interposing transformers or shunts.
Due to the reduced control time and redundancy, six relays
circuits are only used in the EHV grid applications.
Practical experience has shown that easy changeout of
the scheme is appreciated since it would allow a change of
transformer or line lengths settings on site. The Biermanns
15 Three Relay Circuit
PAC.WINTER.2008
relays allowed on site changes of rate of rise with a ratio 1:2
of winding groups connected in series or in parallel. To change
the characteristic of an N-relay; the cam disc, the bi-metal
strip or the saturation transformer had to be changed. Every
new characteristic curve had to be calibrated with a number of
measuring points.
Due to the aforementioned results of the short circuit tests,
new characteristics were developed, e.g. characteristics that
during nominal voltages required double the nominal current
value to initiate a trip but in the case of very low voltage
(short-circuit!) a current level of 30% of the nominal value was
sufficient to trip the relay.
Between 1925-1927 the German utility Bayernwerk in
collaboration with vendors S&H, AEG and BBC carried out
70 short circuit tests to study the behavior of the distance
protection schemes.
Requirement for Fast Impedance Protection
At the end of the 1920s calls for shorter tripping times
(less than 2s) grew. This was necessary to prevent the
network getting out of step with generators, dynamotors
and motors. The breaking power of the oil circuit breakers
increased allowing shorter tripping times. The operating time
of resistance relays grew proportionally with the distance
from the fault location to the relay. The rate of rise of the
characteristic had to be considered carefully to avoid protection
overlaps along the length of line. The fault locator was born
out of the fact that consideration of the operating time of the
definite characteristic of the protection relay allowed the fault
location to be identified.
The goal for the 60 and 110kV networks was to achieve
the shortest tripping time over the entire length of line. For
this reason, the more commonly used continuous time
characteristics were abandoned in favour of the new step or
mixed characteristics.
Further steps in the development of distance protection will be
covered in the next magazine issue.
walter.schossig@pacw.org
www.walter-schossig.de
16 Scheme of a Wideröe-Relay, NJEV
Marco C. Janssen
Our
industry
is dying..
In the coming ten years a
generation of engineers will retireand
there will be no one to take our place!
I am calling out for us to start a global
campaign to market our profession...
As we all should know the electric utility industry is the basis
for the digital economy of today
and it will be for every economy
tomorrow.
Without electric power, economies would not be able to exist
and our society as we know it would come to a complete stop. Then
why do we put our own future and
the future of our children at risk?
During my recent travels around
the world I learned that our profession is dying!! Young people no
longer want to study Power System Engineering or Electrical Engineering. But do you realize what
that means?
In the coming ten years a generation of engineers will retire and
there will be no one to take our
place!
Why? Is our profession that boring? Is our industry that bad?
The answer is simple…
No it is not. Fact is that our profession is no longer perceived as
“sexy”. It is more interesting to be
a lawyer, a doctor, a politician. But
do these other professions provide the basis for development, for
the future? It is the Electrical and
Power System Engineer that does!
That is why action is needed!
As an industry we have to safeguard our future and the future of
our children. An example is that
if we believe that CO2 reduction
is important, then the question
is, without electric power who
will develop the solution to the
problem?
The answer is no one!!
Therefore we must provoke a
change and my plea to you is to
be proud to be an engineer and
let everybody know that you are,
tell your friends your neighbor
about your important role in
society
educate the children around
you about the importance of electric power and make them consi-
I think
75
Biography
der to become an engineer. It is the
generation of children between
the age of 7 and 15 that still have
to make a choice what it is they
want to do with their life and we
can show them that there are more
choices than the typical ones
To the companies in this industry,
vendors, consultants, utilities and
educational institutes I say… Look at the budget you are spending
every year on research and development. Why is it so hard to take
10% out of that budget to secure
our and our children’s future!! It
is a small price to pay and a great
investment in your own and our
future.
I am calling out for us to start a
global campaign to market our
profession and educate the young generation, but we can only
succeed if people contribute. Go
to your local school, volunteer to
speak at conferences, discuss how
your company can contribute. It
does not have to be big, every little
bit helps.
Let’s make a change and do something good for the future. Lets
start an open discussion and send
me your feedback, your ideas,
your commitment and your comments and I promise we will do
something good for this planet!
PAC.WINTER.2008
Marco C. Janssen is
an utility industry
professional with
more than 16
years’ experience.
He graduated from
the Polytechnic
in Arnhem, The
Netherlands and
developed further
his professional
skills through
programs and
training courses.
He is President
and Chief
Commercial
Officer of
UTInnovation
LLC – a company
that provides
consulting and
training services
in the areas
of protection,
control, substation
automation and
data acquisition,
and support
on the new
international
standard IEC
61850, advanced
metering and
power quality.
He is a member
of WG 10, 17,
18, and 19 of IEC
TC57, the IEEE-PES
and the UCA
International Users
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Automation
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reports
industry
Impact of IEC
61850 on
Protection and
Automation
B5 is one of 16 Study
committees of CIGRE.
Its scope is to facilitate
and promote the progress of protection and
automation.
79
IEC 61850, the standard for communication in substations was published three
years ago and is already widely used in Substation Automation projects. The goal of the
standard is interoperability between devices from different manufacturers. It supports the
interconnection of all applications in the substation automation (SA) system from the station
level with its HMI and remote control gateway to the protection and control IEDs in the bays
(station bus), and from these IEDs down to the switchgear (process bus). It supports also the
use of unconventional current and voltage sensors. It may replace all signal wires by serial
communication links. The standard goes beyond the definition of communication since it
provides additional important features like the domain specific Data Model and the Substation
Configuration description Language (SCL). Therefore questions came from the users : What
is the impact of IEC 61850 on protection and automation? How introduce IEC 61850 based
substation automations system to exploit all benefits but to minimize the risk of this step?
The CIGRE Study Committee B5 had formed the WG 5.11 which created a brochure covering
all these topics and, as common, a summary in Electra - both published in fall 2007. This
CIGRE brochure cannot replace the more than 1000 pages of the standard but is intended as a
practical guideline for utilities. This article cannot replace the 110 pages of the CIGRE brochure
PAC.WINTER.2008
by Klaus-Peter Brand
Suplier A
Suplier B
have before
and when
Suplier A
Suplier B
Substation Department (SD)
utilities
Communication
Departrment
Control/SCADA
Departrment
Communication
Departrment
Control/SCADA
Departrment
Protection
Departrment
Switchgear
Departrment
Protection
Departrment
Switchgear
Departrment
Offer/Order
IED
IED
IED
System Integrator (SI)
System Integrator (SI)
IEC61850 Knowledge everywhere
Suplier C
PAC.WINTER.2008
Suplier D
Suplier C
Suplier D
Simulation
(Tool)
Simulation
(Tool)
Maintenance
(Tool)
System
SCD
Integration/
Engineering File
(Tool)
Switchyard
Single Line
introducing
IEC 61850
3
SCD - Thread trough the life cycle
sponsibility for substations of SA and substation
Functions
allocated
M
ai
nt
en
an
ce
departments in utilities
and facilitates the integration of
a third party main 2 protection
as needed for transmission lines.
At the beginning of chapter 6 it is
recommended to reconsider the
system concepts to exploit the
benefits of IEC 61850 as much
as possible. This is especially
important for migration strategies
(chapter 4). There are no general
strategies because any migration
depends on the actual state and the
intended goal for the SA system.
Specification of IEC 61850
based Systems
The most sensitive phase for
SA systems is the specification
phase because corrections later in
the implementation phase may
either be not possible or very costly.
Guidelines for specification are
given in chapter 6 by description
and as checklist. The description
of the site and the already existing
or newly ordered switchgear is
essential. The starting point is the
single line diagram of the substation
and the allocated SA functions
as usual.The communication
design based on Ethernet is more
flexible and scaleable than the
previous proprietary ones. Active
elements like switches support
s
File
ICD
of questions
1 Current Responsibility of 2 IEC 61850-Holistic re-
The switchgear and
SA system should be
considered as a whole.
SA
T
discusses a lot
current and voltages, as well as
using the common conventional
t ransfor mer-t ype ones . The
SCL of IEC 61850 provides a
comprehensive description of
the complete SA system. It was
defined to be used by all tools also from different manufacturers
- for configuration, engineering,
testing, and maintenance i.e. in
any phase of the life-cycle starting
from any single compliant product
and ending with the maintenance
phase of the customer specific
SA project (Figure 3). In chapter
3 it is shown how these benefits
correlate to operative and cost
benefits for the utility justifying
the introduction and use of IEC
61850. Examples are the use of SCL
and mainstream communication
technology, but also the options
to replace copper wires by serial
fiber optic links transporting
GOOSE messages or to use any
kind of today’s and tomorrow's
current and voltage sensors. Last
not least, interoperability is not
only provided between devices of
different suppliers but also between
different generations of products.
Concepts and migration
SA systems realized according to
IEC 61850 up to now are more or
less one-to-one copies of existing
ones replacing only the proprietary
communication by IEC 61850.
This step is already beneficial
since it excludes communication
from competitor comparison
FA
T
The brochure
but explain shortly some findings and
highlight its helpful role for utilities.
The chapters in the brochure
were written by different authors
from utilities and providers.
The brochure was compiled by
the members of working group
5.11 and crosschecked by the
representatives of CIGRE SC B5
36 member countries worldwide. The idea is that each chapter
is readable by itself depending
on the background and the aim
of the reader. Therefore, there is
some overlap between the chapter
content.
Benefits and justification
Chapter 2 summarizes the
features of IEC 61850 and points
to the benefits. The combination
of all it s disc ussed feat ures
makes the standard unique. The
homogeneous and comprehensive
abstract data model including all
services for the communication in
substations is formulated very near
to the user's (substation engineer)
terminology and independent
from any implementation which
is left as task for the manufacturers.
The mapping of this model to main
stream communication means
i.e. MMS, TCP/IP and Ethernet
makes the standard future proof.
The inclusion of the sampled
values service allows exploiting the
benefits of new non-conventional
instrument transformers like
Rogowski coils, capacitive dividers,
and electro-optical sensors for
Upgrade
(Tool)
SSD
File
CIGRE B5
industry reports
80
Specification
Test
(Tool)
Test
(Tool)
System
Refurbishment
Tool
this flexibility. To get an optimized
SA architecture, requirements for
both availability and performance
have to be stated. If there are no
restrictions in the specification,
GOOSE messages may replace
all wiring bet ween IEDs. At
least for new substation the use
of unconventional instrument
transformers providing samples via
the process bus may be considered.
However, these advanced features
are not a must for using IEC 61850
but an option for the future. The
responsibility that the system
composed of interoperable devices
from different suppliers is running
as specified has to be taken by the
System Integrator and fixed in
the specification. This role needs
appropriate tools, test equipment
and trained staff. Besides the SA
system itself the most important
item to be delivered is a single SCLbased Substation Configuration
Description (SCD) file - a very cost
effective basis for all testing and
maintenance tools and, therefore,
for any future upgrades also.
Responsibility in utilities
The project execution (chapter
7) is normal besides the fact that
in the engineering process the
SCD for the complete system
has to be created and reused for
system tools. In addition to the
specification, the procurement
process (chapter 5) and the lifecycle management (chapter 8)
are within the responsibility of
the utility. The utilities should
invest in the knowledge about the
standard to understand what they
may request and what they will
get. The integration of the different
functions in the substation to one
system may strongly impact the
structure of utility organization
(see Figures 1 &2).
References
The introduction of IEC 61850 and its
impact on protection and automation
within substations
Cigre Brochure 326 (produced by SC B5 WG
B5.11), 2007, price 75/150 €, www.cigre.org
Summary in Electra N°233, August 2007,
21-29
Cyber Security
Issues for
Protective Relays
The Power System
Relaying Comettee is in
the Power Engineering
Society of IEEE.
by Solveig Ward, RFL, USA
In a m ajor move toward
ensuring the reliability of the
electric grid, the Federal Energy
Regulatory Commission (FERC)
approved eight cyber security and
critical infrastructure protection
(CIP) standards proposed by NERC,
CIP 002-1 to 009-1. The standards
will require bulk power system
users, owners, and operators in
the U.S. to identify and document
cyber risks and vulnerabilities,
establish controls to secure critical
cyber assets from physical and cyber
sabotage, report security incidents,
and establish plans for recovery in
the event of an emergency.
Substantial compliance is required
by 06/2008 and full compliance
by 12/2008. Utilities that do not
meet audit requirements will face
stiff penalties for non-compliance
when audits begin in 2009.
Because of the importance of this
subject the IEEE Power Systems
Relaying Committee Working
Group CI studied the issues of cyber
security related to different aspects
of power system protection and
produced a report “Cyber Security
Issues for Protective Relays” that is
available to the community.
Cyber sec ur it y is the ter m
commonly used with respect to
the area of computers. Computers,
or microprocessor-based devices
with computing capability, are now
commonly used for control and
automation functions in addition
to traditional data archival and
processing.
Technological misuse and abuse
has become a serious concern in all
areas where computers are used and
networked. The electric industry
has embarked on the process
to secure control systems. This
requires risk assessment and review
to determine what is vulnerable to
cyber attacks. All assets should be
analyzed in regards to the need for
security.
Protec t ion and sec ur ing of
net worked communications,
intelligent equipment, and the
data and information vital to the
operation of the future energy
system is one of the key drivers
behind developing an industry
level architecture. Cyber security
faces substantial challenges, both
institutional and technical, from
the following major trends:
Need for greater levels of
integration with a variety of
business entities
Biography
Solveig M. Ward
received M.S.E.E.
from the Royal
Institute of Technology, Sweden
in 1977. She
joined ABB Relays.
where she has held
many positions in
Marketing, Application, and Product
Management.
After transferring
to ABB in the US
1992, she was involved in numerical
distance protection
application design,
and was Product
Manager for
current differential
and phase comparison relays. She is
a member of IEEE,
holds one patent
and has authored
several technical
papers In June
2002, Solveig joined
RFL Electronics Inc.
as Director of Product Marketing.
by Solveig Ward, RFL, USA
IEEE PES PSRC
industry reports
82
Increased use of open systemsbased infrastructures
The need for integration of
existing or “legacy” systems with
future systems
Growing sophistication and
complexit y of integrated
distributed computing systems
Growing sophistication and
threats from hostile communities
The repor t analyzes relay
communicat ions and the
requirements covered in the
different NERC standards. Two
main groups of protection related
communications applications are
identified:
between protection IEDs and
different substation and remote
client applications
between protection IEDs
with a substation or in different
substations.
The requirements for the different
cases are discussed in the report,
followed by analysis of the impact
of the communications media used
on the security of the system.
In evaluating the security threat to
substation equipment the report
concludes that numerous people
have physical contact with various
devices within the substation.
These indiv iduals include
employees, contractors, vendors,
manufacturers, etc. Of particular
concern is the fact that the typical
subst at ion environment can
1 Electronic Security
Perimeter
SCADA Master
Engineering
Station
Substation
HMI
Substation
Applications
Router
Switch
Telecom
Device
IED
IED
IED
Substation
PAC.WINTER.2008
Telecom
Device
IED
IED
Substation
provide a means to compromise
the power system with a low
probability of being detected or
apprehended.
Threats may be caused by actions
of authorized persons as well as
malicious actions of authorized and
unauthorized persons. Some of the
threat sources to consider include:
Employees with criminal intent
to profit or to damage others by the
misappropr iat ion of ut ilit y
resources
Disgruntled employees or exemployees who cause damage to
satisfy a grudge
Hobbyist intruders who gain
pleasure from unauthorized access
to utility information systems
Criminal act ivit y by both
individuals and organizations
directed against the utility, its
employees, customers, suppliers,
or others
Terrorists
C ompet in g or g ani z at ions
searching for propr iet ar y
information of the utility, its
suppliers, or customers
Unscrupulous participants in the
markets for electric power or
derivatives
Software providers who, in
at tempt ing to protec t their
intellectual property rights, create
vulnerabilities or threaten to disable
the soft ware in cont r ac t ual
disputes
Communication protocols are
one of the most critical parts of
power system operations.
The International
Electrotechnical Commission
(IEC) Technical Council (TC) 57
Power Systems Management and
Associated Information Exchange
is responsible for developing
international standards for power
system data communications
protocols. The international
standards account for much of the
data communications protocols in
newly implemented and upgraded
power industry SCADA systems,
subst at ion automat ion, and
protection equipment.
The report analyzes
relay communications
and security issues
By 1997, IEC TC57 recognized
that security would be necessary
for these protocols. It therefore
established a working group to
study the issues relating to security.
The work by IEC TD57, WG 15
is to be published by the IEC as
IEC 62351, Parts 1-7. The IEEE
PSRC report concludes with the
following Recommendations :
Security must be planned and
designed into systems from the
start. Planning for security, in
advance of deployment, will
provide a more complete and cost
effect ive solut ion. Advance
planning will ensure that security
services are supportable.
Establish a security policy
tailored to the needs of protective
relay systems and the access needs
of protective relay engineers
Assess existing communications
channels for vulnerabilities to
intrusion
Implement and enforce policies
re computer usage, remote access
control, with frequent auditing of
systems and policies. Emphasize
that security is not a part time ad
hoc function.
Where appropriate, add policies,
procedures and hardware to
v ulnerable communicat ions
channels and access ports.
Where appropriate, implement
authentication and/or encryption
techniques based on individual risk
assessments
Monitor logs and traffic.
Maintain and monitor a list of
authorized personnel who have
password or authenticated access.
Comply with industry and
government regulations.
Maintain a backup of vital
information.
Prepare a recovery procedure in
the event of an attack
reports
conference
Relay Protection
& Substation
Automation
Conference 2007
Cheboksary,
Russia
page 84
CIGRE B5 2007
Madrid,
Spain
page 86
Western
Protective Relay
Conference 2007
Spokane,
Washington, USA
page 84
PAC conferences
around the world
Protection, Automation
and Control conferences
around the world provide
forums for discussions and
exchanges of ideas that
help the participants in
resolving the challenges
that our industry faces
today.
SEAPAC
2007
Sidney,
SIMPASE
2007
Australia
page 83
Salvador,
Brasil
page 82
Protection &
Automation
Conference 2007
New Delhi,
India
page 87
PAC.WINTER.2008
83
by Jorge Miguel Ordacgi Filho, ONS, Brazil
from around the world
conference reports
84
Pestana hotel
- the conference venue in
Salvador
SIMPASE 2007
held in Salvador, Brazil
The Symposium of Electric
Power Systems Automation
is among the most
important conferences of
the Brazilian Power System.
The VII SIMPASE – Symposium of
Electric Power Systems Automation
was held in Salvador, Brazil from
August 5 to 10, 2007. Having
existed for more than 15 years,
SIMPASE is now considered as one
of the most important Brazilian
conferences in its area. SIMPASE
is a biennial meeting promoted
by CIGRÉ-Brazil, conducted by
Committees C2 (Operation and
Control of Power Systems) and B5
(Protection and Automation).
SIMPASE's seventh edition was
organized by Coelba (Bahia State
Power Company) and gathered
PAC.WINTER.2008
500 actively engaged professionals
who exchanged information and
technical/managerial experiences.
It is fair to highlight the active
participation of professionals
from utilities, vendors, consulting
companies, system integrators,
universities and research centers
during the technical sessions, panels,
conferences, mini-courses and in
the exhibition hall, visiting the
stands of national and international
companies. Six preferential subjects
were discussed in the symposium:
Automation and digitalization
of plants, substations, distribution
Salvador
was the first
capital of
Brazil
networks, and large consumer
facilities;
Automation of control centers
and service centers;
Integration of local control and
supervision systems, facilities
and control centers to corporate
systems;
E duc at ion, re se arc h and
development in the field of
automation for power systems;
Automation-related economic,
financial and performance aspects;
Metering automation.
Out of the 195 abstracts submitted
by 64 organizations, the Technical
Committee selected 42 technical
papers to be presented in the
technic al sessions , The V II
SIMPASE granted awards to the
three best ranked papers based on
evaluation by the participants of the
abstracts, technical reports and their
presentation in the plenary sessions.
The author of the best ranked paper
will be granted a special award that
consists of his/her participation
at CIGRÉ – Paris 2008 Biennial
Conference. The paper that was
granted this award was presented by
COPEL in partnership with UTFPR,
and this shows the evolution of the
academic centers as far as electric
power systems automation-related
themes are concerned. Noteworthy
also is mentioning that the scoring
85
Many Protection
and Automation
systems will be
integrated
and use IEC 61850
system took into account the
scores assigned by the Technical
Committee to the abstracts and
technical reports, in addition to the
voting process that involved the
participants of the conference.
Three technical panels were also
conducted, bringing together
renowned experts of the Brazilian
Power System, and two minicourses that discussed issues
related to IEC 61850 Based
Substation Automation, delivered
by Dr. Alexander Apostolov from
OMICRON (US), and SCADA and
Applications for Control Centers
of Power Systems, delivered by
Dr. Roland Eichler from SIEMENS
(Germany). Special presentations
on relevant and up-to-date subjects
were done by invited speakers, such
as the CIGRÉ SC B5 Chairman,
Mr. Ivan de Mesmaker from
ABB (Switzerland), Dr. Edmund
Schweitzer III from SEL (US), Mr.
Renato Céspedes from KEMA (US)
and Dr. Walter Johnson from CaISO
(US).
In addition, VII SIMPASE promoted
an exhibit in which 22 companies/
institutions participated with
27 booths, taking great care in
presenting the state-of-the-art
in terms of available systems and
equipment. The participants of
the conference actively visited the
exhibit. .
The VII SIMPASE also promoted an
atmosphere of comradeship to the
automation professionals, especially
during the opening ceremony and
the get-together dinner offered by
the conference.
SEAPAC 2007
held in Sidney, Australia
The conference was a great
success by all reports from the
115 attendees. Many reported
that this was a unique event in
the Australian calendar
The Australian National
Committee of CIGRE and the
B5 Protection & Automation
Panel organized the South East
Asia Protection & Automation
Conference. Its goal was to help
participants to respond to the
increasing pressure on utilities to
provide ever more reliable and robust
electricity supply to the consumer
under tight regulatory requirements.
With new developments in
protection and automation, it is
time to review what the industry is
achieving in its current operations
and take the lessons forward as the
industry is about to embark on the
next evolution of technology. It
focused on best practice protection
and automation issues in the
Australia, New Zealand, South-East
Asia and the Pacific region.
It gave participants the opportunity
to gain an understanding of current
protection and automation practices
in the industry and a unique
opportunity for networking amongst
other professionals in the region and
internationally.
The scope of the conference provided
wide opportunity to discuss
project strategies for development,
justification, implementation and
project management as well as
design objectives and solutions for
green field projects, brown field
developments through to full life
cycle management of the asset.
Projects encompassing direct
equipment replacements through to
complete technology shifts were also
of interest. The program was highly
interactive enabling an exchange of
information on the papers presented
with opportunities for all attendees
to discuss specific issues particular to
individual organizations.
Two keynote speakers - Brian
Pokarier, PowerLink Manager
Engineering & Projects and Chris
Fitzgerald, Transgrid General
Manager Engineering - discussed
development s w ithin the
industry and the issues facing their
organizations.
A special feature of the conference
was a tour of Transgrid’s new
330/132 kV indoor GIS substation.
The conference included an
exhibition area where a number of
suppliers presented their products
and were available to discuss user’s
needs.
PAC.WINTER.2008
from around the world
conference reports
86
Western Protective
Relay Conference, USA
Relay Protection
& Substation
Automation
Conference,
Russia
Participation in the Conference
was open for all the experts
The 34th Western Protective
Relay Conference was held in
Spokane, Washington, USA from 16
to 18 October, 2007. It is an annual
event hosted by Washington State
University and offers the attendees
from many countries the opportunity
to discuss new developments in
power systems protection, as well
as the application of such devices or
systems in the field. The wide range
of protection and protection related
papers presented at the conference
make it attractive to researchers and
educators, technicians and managers,
consultants and manufacturers’
representatives.
As usual, the conference venue
was the Spokane Convention
Center. Approximately 600
protection professionals attended
the conference, which makes it the
largest specialized conference in the
field. The attendees were from many
countries, predominantly from
the Western US. Papers about the
application of protection technology
in generation, transmission,
distribution and industrial systems,
and how it is used were presented.
The program committee selected
50 of the submitted abstracts to
be presented over 3 days in 10
sessions. The opening and closing
sessions were general and attended
by all participants in the conference.
The remaining eight sessions were
grouped in four pairs, thus giving the
opportunity to the attendees to select
the papers of interest. The advantage
of this approach is that more papers
can be presented at the conference.
The drawback is that some times
both papers presented in the same
time slot might be of interest to some
of the attendees.
Following the paper sessions, the
participants had the opportunity
to visit the hospitality suites of
many leading vendors in the field
and discuss the latest demonstrated
technology.
interested in the preferential
subjects chosen for discussion.
T he Rus si an National
Commit tee of CIGRE (RNC
CIGRE) and the All-Russian Relay
Research, Design & Technology
Institute (VNIIR) along with the
System Operator for UES of Russia
and the Federal Grid Company
org anized the Inter nat ional
Conference on Relay Protection and
Substation Automation of Modern
Power Systems. The conference was
held from 9 to 13 September 2007
in Cheboksary - the administrative,
industrial, historical and cultural
center of Chuvashia, located in
the center of the European part of
Russia, in the heart of the VolgaVyatka region. The republic is not
large, but is one of the most densely
populated regions in the Russian
The Red Lion
hosted the
The main purpose of the
hospitality
suites.
Conference & Exhibition is
to put forward all the latest
achievements and lines of
development in the field, and to
encourage a dialogue.
PAC.WINTER.2008
The conference was
held in
Chebocksary,
Chuvashia, Russia
Cheboksary
is the capital
from around the world
of Chuvashia
conference reports
87
Federation, with a total population
of 1.35 million people. It is one
of the main ancient ports of the
Volga River and its foundation
goes back to the 14th century. Old
monasteries and other cultural
monuments reveal its rich history,
while woodland sceneries show
some of the real treasures of the
Russian nature. Another important
reason that Cheboksary was chosen
to host the Conference is that it
is in fact the Russian and former
Soviet center of the relay protection
scientific research.
The goal of the conference was
to summarize and analyze the
world experience in development,
manufacturing, operation and
maintenance of facilities, tools and
systems for relay protection and
automation of EHV power systems
and encourage a dialogue between
experts, manufacturers and users in
that area.
Several CIGR E study
committees were invited to take
part in the Conference. This clearly
shows the focus of the conference
on a wide range of issues related
to the protection and control
of large electric power systems
under different normal, as well as
abnormal system conditions. Papers
presented over the three working
days of the conference covered new
and re-discovered theories and
practices serving the modern power
system protection and control, the
impact of IEC 61850 on the design
of secondary systems, electric
power system simulation methods
and their influence on development
of power system protection and
control. FAC T S systems and
synchrophasors applications were
also discussed, together with
protection reliability.
A significant number of papers
were also available to the attendees
in poster sessions. The exhibition
allowed the participants to see new
devices and tools and discuss the
future trends in the field.
The evening event s were
an excellent opportunity for
networking and establishing
contacts with protection and
control professionals attending the
conference.
Cheboksary is
an ancient port
on the Volga
river and was
founded in the
14th century
PAC.WINTER.2008
88
from around the world
conference reports
CIGRE B5 Colloquium
Madrid, Spain
The CIGRE B5 Colloquium is biannual event held in different
countries around the world
The capital of Spain, Madrid,
hosted the Annual Meeting and
Colloquium of CIGRÉ Study
Committee B5 from 15th to 20th
of October 2007. This event is held
every two years in different venues
all over the world with a worldwide perspective and participation.
The 2007 event venue was the
Palacio de Congresos de Madrid
(Madrid Congress Hall), located in
the heart of Madrid. The city is very
well known for its rich history and
intense cultural and artistic life.
More than 250 professionals
attended - half from utilities, one
third from manufacturers and the
remaining – consultants, educators
and researchers. The program also
allocated time for working and
activity groups meetings, as well as
a half-day Tutorial.
The Colloquium was held on
17 – 18 October 2007. All accepted
papers were related to one of the
three preferential subjects (PS).
In CIGRE Technical Discussion
sessions, the paper authors do
not actually present their papers.
Each discussion session is based
on questions raised by the Special
Reporter in his report, published
before the colloquium and available
to the registrants along with the
papers. Authors of accepted papers
presented them in a poster session.
PS 1: “New Trends on Bus Bar
protection” Special Reporter: Zoran
Gajic (Sweden)
PS 2: “Acceptable Functional
Integration in Substation P&C for
transmission Systems”- Special
Reporter: Iñaki Ojanguren (Spain)
Madrid is a city
with very rich
history
Gala Dinner,
hosted by the
Spanish National Committee
of CIGRE in
Castillo de
Viñuelas
PAC.WINTER.2008
PS 3: “Protection of
Tr ansmis sion L ines & C oordination of Transmission System
Protection”- Special Reporter: João
Emanuel Afonso (Portugal)
At the opening of each
discussion session, the Special
Reporter presented a summary of
his report and the questions he had
posed. Registrants who attended
the discussion sessions made short
prepared contributions in response
to the special report questions.
Spontaneos contributions were
made at the end of each session,
followed by the summary of
all discussions by the Special
Reporter.
I n a s s o c i at i o n w i t h t h e
Colloquium, a technical exhibition
on the subject of Protection
and Automat ion Systems
complemented the colloquium.
Fifteen companies presented their
protection and control products in
stands organized in a special area
adjacent to the meetings place.
This was a good opportunity for
the participants to learn directly
from the manufacturers about the
latest and most advanced devices
and tools in the field of substation
protection and control.
After the colloquium, interested
attendees participated in a technical
visit to the Renewable Energies
Operation Center in Toledo
89
The conference
provided
an environment for
sharing ideas
and experience
Th e C e n t r a l B o a r d o f
Irrigation & Power organized
the 4th international conference
on “Power System Protection and
Automation” that was held at
Hotel Le-Meridien in New Delhi,
21-22 November 2007.
New Delhi is currently the
capital of India. Most of the city
was planned by Sir Edwin Lutyens,
considered by some as the greatest
British architect.
The aim of the conference
was to provide the participants
excellent opportunities to share
knowledge, experience and new
ideas in the areas of power system
protection and automation and to
discuss their implementation and
applications to the existing and
future power systems.
Approximately three hundred
protection and control professionals
from different countries attended
the conference. They had varying
interests on the discussed subjects
- senior officers of power utilities,
planning specialist and consultants,
manufacturers and researchers.
The conference inaugural
address “Trends in Protection and
Substation Automation Systems:
Integration, Standardization,
Information Technology” was
delivered by Ivan De Mesmaeker
(Sw it zerland), Chair man of
CIGRE-SC-B5 “Protection and
Automation”.
Internationally recognized
experts from around the world
presented the 36 papers selected
by the technic al commit tee
during 7 sessions. Two sessions
Protection Conference
2007,
New Delhi, India
International experts presented
and discussed papers at the
conference
were dedicated to protection and
monitoring of main plants and
transmission circuits. Another two
covered monitoring, metering,
recording and overall power system
protection. The remaining three
covered:
Substation automation, remote
control and novel sensors
Case studies
Maintenance, training, asset and
information management
Several manufact urers
used a small exhibition area to
demonstrate their latest devices
and engineer ing tools . The
interesting discussions between
authors and attendees during the
sessions and the breaks showed
the importance of information
and experience exchange that such
forums offer.
It was clear that IEC 61850
- the new international standard
for substation communications, is
gaining momentum and is going to
shape the future of the protection
and control industry not only in
India, but in many other countries
around the world
Hotel
Le-Meridien,
the conference
venue
Most of New
Delhi was
planned by Sir
Edwin Lutyens
PAC.WINTER.2008
17 – 20 March 2008
The Crowne Plaza Hotel,
Glasgow, UK
Protection Engineers
The Institution of Engineering and Technology
Be part of National Grid’s exciting new engineering center
of excellence near Boston, Massachusetts.
9th International Conference on
Developments in Power System
Protection: DPSP 2008
Our Engineering and Asset Management department is
currently looking for protection engineers with several years
experience in the protection engineering and asset strategy
field. If you have a proven track record of delivering
protection designs or developing protection asset
management strategies we would like to hear from you.
DPSP 2008 will provide an up-to-date
understanding of recent developments and future
trends in the design, application and management
of power system protection and control systems.
Main Features of DPSP 2008:
• Key Tutorial on IEC 61850
• Exhibition featuring many of the big names in
Power System Protection
• 10 Oral Sessions and 2 Poster Sessions
over the 3 days
• Excellent networking opportunities including
a Conference Dinner at the fantastic
Kelvingrove Art Gallery and Museum
• Complimentary drinks reception on the
Monday evening
www.theiet.org/dpsp
Headline Sponsors
CD & Lanyard Sponsor
Supported by
What you need NettedAutomation
to know about
UTINNOVATION
IEC 61850
IEC Standards for Power Systems
Generation, Transmission, Distribution, … Design, Specification, Engineering,
Configuration, Automation, Monitoring, Information Management, Maintenance,…
Training opportunities:
14-15 April 2008 Frankfurt (Germany) 03-04 July 2008 Atlanta, GA
07-08 July 2008 Chicago, IL
10-11 July 2008 Los Angeles, CA
21-22 Aug 2008 Paris (France) prior to CIGRE conference
www.iec61850.com/seminars
Mr. Karlheinz Schwarz (NettedAutomation)
Mr. Christoph Brunner (UTInnovation)
Prospective candidates should have:
•A Bachelor’s degree in Electrical Power Engineering;
Master’s degree preferred.
•Five years or more experience in Electric Transmission or
Distribution protection
•Real world experience in setting and coordinating complex,
multi-functional relays
•Knowledge and direct use of power system analysis tools
•Strong analytical and communication skills
•PE license or international equivalent is preferred
National Grid is an international energy delivery company.
In the U.S., National Grid delivers electricity to approximately
3.3 million customers in Massachusetts, New Hampshire,
New York and Rhode Island, and manages the electricity
network on Long Island under an agreement with the Long
Island Power Authority. National Grid is the largest power
producer in New York State, owning 6,650 megawatts of
electricity generation that provides power to over one
million LIPA customers and supplies roughly a quarter of
New York City’s electricity needs. It is also the largest
distributor of natural gas in the northeastern U.S., serving
approximately 3.4 million customers in New York,
Massachusetts, New Hampshire and Rhode Island.
As a large international company, National Grid is striving
to develop and support a more inclusive and diverse
workplace. We believe a positive approach to Inclusion and
Diversity is not a "nice to have" but is fundamentally the
right thing to do for us as a business.
Benefits
We offer a comprehensive benefits package, letting you
select the plans and coverage that best meet your needs and
those of your family, including your spouse, domestic
partner and eligible dependents. Listed below is a partial
list of the benefits offered to our employees.
•Health and Family: Medical, dental, health care spending
account, life insurance, disability, long-term care, same-sex
domestic partner and same-sex marriage benefits,
dependent care assistance and adoption assistance.
•Financial: Pension, 401(k), opportunity for annual cash
bonus and credit union benefits.
•Educational Aid: Tuition reimbursement and scholarships
for employees' children.
•Vacation/Holiday: Paid vacation and holidays and purchase
extra vacation days.
tss
xppeerrt iess
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Contact us: Visit our website at www.nationalgridus.com
and click careers. Search on all listings, all locations and
apply for NE-2027. EOE
National Grid is committed to inclusion and diversity and
encourages women and minorities to apply.
IEC
61850
www.nationalgridus.com
photos of the issue
91
Druskininkai, Lithuania Photo: Evaldas Oleskevicius/ Lithuania / Panasonic, Lumix
Photo Competition 2008
These photos were selected for
the Winter 2008 issue. They will be
considered for the final Photo of the
Year Competition. Please, submit your
favorire pictures for the Spring 2008
The beauty of winf power Photo: Jefferson Foley / USA / Casio Exlim 5MP
Maple - Acer perspective
Photo: Andrei Podshivalin/ Russia/ Canon PowerShot G3
Book review
93
Protective Relaying
Principles and
Applications
Third Edition
The Third Edition of Protective
Relaying, Principles and Applications
comes twenty years after the first
edition of the book that has been
one of the key reference books
for protection engineers in North
America, as well as many others
around the world. The popularity of
the original was mainly due to the
style of the book – straightforward
and application oriented.
The core of this book, is on the
fundamentals of electric power
systems analysis, especially fault
calculations, and the requirements
and principles of protection of the
different system components.
The need for this third edition
is driven by the significant changes
in protection technology that
started around the time of the
publishing of the first edition and
has become widely accepted in the
last ten years. At the same time, we
have seen a change in the utility
environment characterized by loss
of expertise, operation of the electric
power system close to its stability
limit, distributed generation and
increase in the number of industrial
customers sensitive to voltage
variations. All of these require a
new approach to the protection
of the power system based on
good understanding of the power
system events and the behavior of
protection relays and systems under
these conditions. The new chapters
in this
new edition,
are focused on
microprocessor based protection
relays, and their integration in
substation automation systems.
More than 600 pages of
the book are divided in fifteen
c hapter s :The fir st c hapter
discusses general requirements for
protection, operating principles
and applic at ions .The next
three chapters introduce some
fundamental concepts, such as per
unit calculations, phasors, polarity
and symmetrical components.
The instrument transformers,
their performance, and criteria for
selection are discussed in Chapter
5. Optical sensors are described at
the end of the chapter.
Protection fundamentals and
basic design principles are later
introduced, followed by detailed
discussions of the different types
of protection typically used:
Generator (including intertie
protec t ion for dist r ibuted
generation) and motor protection
Transformer, reactor and shunt
capacitor protection
Bus protection
Line and Feeder protection
Different issues related to the
security and stability of the electric
power system, such as reclosing
and load shedding are discussed in
Chapter 14. The last chapter focuses
on the new technology in power
system protection - microprocessor
based relays and their applications,
non-protection functions in these
devices and their integration in
substation automation systems.
Many chapters of the book
include bibliography with papers
for further reading, while some have
appendixes or examples that help
the user understand the practical
application of the theory discussed.
The book also includes a section
with problems that can be used by
the reader to practice what they have
learned.
The main additions in the
Third Edition include the material
related to new technology and
system stability. This, combined
with the fundamental concepts
and applications of electric power
systems protection make this book
a good reference for anyone with
interest in protection, automation
and control.
J. Lewis Blackburn & Thomas J. Domn
Published by CRC Press
Taylor & Francis Group
ISBN 1-57444-716-5
PAC.WINTER.2008
by Andrea Bonetti, ABB AB, Sweden
Entertainment
hobby
94
The Magic
Curtain
It is an interesting
feeling when
you meet
someone at a
conference or
standardization working
Andrea
Bonetti, The Bonnie Kids,
preparing for the ABB arena performance
group, and you know that
there is something special
about that person. This
is where Google helps,
when you do a search on
“Andrea Bonnetti” some
unexpected information
pops-up...
PAC.WINTER.2008
Engineering and Magic
My interest in magic started
around 1982-1983. My first magic
shows in front of real audiences
took place with my younger brother in 1983.
It is not easy to be a magician: in
order to be allowed to join a magic
circle, you must prove your real interest in the art and show that you
are able to perform some magic
tricks. However if you do not join
a magic circle, it is difficult to learn
to perform magic tricks!The city
of Rome gave me the possibility
to manage this Catch-22 situation.
Firstly, a magic shop in one of the
old city centers (near the Pantheon) provided me with the superb
opportunity to buy some simple
tricks and books. Subsequently,
I managed to join the local magic
organization affiliated to the largest
magician organization in the world,
the International Brotherhood of
Magicians (IBM). What triggered
such an interest in magic? Probably
Silvan - the most famous Italian
magician in the 1980's although TV
certainly played a role. The ‘magical’ part of the art was certainly
the major attraction and the belief
that I really could make things appear and disappear. However, this
was subsequently accompanied by
the frustration that it wasn’t really
like that. Even after all these years, I
still experience the frustration and
disappointment of ‘destroying the
magical effect’ when learning how
to perform a new trick, because
knowledge of the intricacies of the
trick destroys the magical illusion
to the performer.
A magician is like a juggler insofar as both need to dedicate hours
of training to master the art. The
difference is that the juggler entertains you by explicitly showing
how good he is whereas a magician
must hide his skill to entertain you
in a different way.
My family and friends fondly
remember "Andrea the Magician"
who doggedly tried to master the
different branches of magic: ma-
university years, providing me
with economic independence at a
young age and financing my summer vacations, my car, etc.
While the original idea was to
be a magician for adult audience
(mainly manipulation like cards,
billiard balls and cigarettes or general magic like silks, flowers etc. ...
typical theater stuff!), one day my
mother's friend asked me if I could
entertain at a children’s birthday
party.
"Entertaining kids?!? ?!?
I am a magician, not a baby sitter!" was my initial reaction. I really
did not like the idea at all! Nevertheless, I did the birthday party
show and discovered two things
that I had never considered before,
namely, that it was much more difficult with children but I had lots of
fun. Why more difficult? Because,
no matter how young you think
you are, you are not a child. Their
body language is different to ours,
their expectations are different.
They do not look where you want
to or as predicted when performing
for adults. If you say to a child, "Pick
up a card from the deck, ANY card,
look at it, show it to your friends,
2 Andrea's first magician card:
Brotherhood of Magicians
IBM - International
A magician
is like a juggler both need
to dedicate hours
of training
to master
the art!
DO NOT tell it to me.., put it back
in the deck, shuffle the deck….
Now I'll say the magic word… Sim
Sala Bim... here is your card!”, the
child’s reaction is "of course you
found my card, you are a magician. Can you show me something
funny now?". This task is not easy
to achieve.
So where did the name for the
magical act come from? Our surname is Bonetti, Bonnie  Bunny
 Magic Rabbit, then Kids (myself
and my brother Marco were young
and we were also performing for
kids) hence the name:
The Bonnie Kids
It sounded logical to us and in
November 1989, two weeks after
the Berlin Wall fell, the name Bonnie Kids was born, together with
the associated logo, the magic rabbit, the business cards etc.
A magician must not simply
learn some magic tricks but must
also learn how to present the
tricks in an entertaining manner.
You cannot proceed to this step if
you do not have years of practice
behind you. Investing in those
years of practice requires love for
the art. Those who have money as
their motivation do not enter the
profession on the right track. As
a magician, you have to promote
the art, so you have to share the
secrets with other possible future
magicians (amateur, professionals
or semi-pro). You must be able to
identify and encourage new potential magicians among the huge
PAC.WINTER.2008
Entertainment
nipulation (ask my poor teachers
about coins falling every 10 minutes on the classroom floor), pick
pocketing (wallets, pens, glasses
etc. stolen from my friends’ bodies
resulting in positive and negative
reactions) and going to school on
the unicycle (every magician can
juggle a little and vice-versa).
My parents were tired and bored
of seeing the same tricks each day
and this caused me to question my
capability at performing the tricks
until I got a sign. This happened
when, after a small private Christmas show, my father confessed that
he had sneaked into my secret room
while I was sleeping to find out as
he described in his own words,
"how the hell you pulled out all that
stuff from the box!" At that moment I realized that I had attained a
certain level of skill in magic.
My motive for being a magician
was never about making money – I
simply wanted to be a magician and
never dreamed that I would earn
money from it. However word
spread quickly about me and my
magical act, Bonnie Kids (the name
came about in 1989), and magic
ended up paying my way through
hobby
95
Entertainment
hobby
96
number of people that just want
to know "how to". This is not an
easy task. In any case, I think I have
done my part as two Italian magicians took up the art because of my
influence. Their parents were not
so happy at the time, fearing that
they would prefer to practice their
magic instead of preparing for university exams. However, not only
have they continued until this day
to be in the magic society, they also
graduated from university.
As a magician you must adhere to strong ethics which are
mainly based on the following two
principles:
keep the secret
give credits
The first principle is obvious but
the second is more subtle since the
"how to" and the presentation of a
trick are the most important things
in producing a magical effect, and
most of them are not patentable.
The magic community demonstrates respect for the inventor of a
magic trick/effect by:
always buying original tricks
(no rip-offs);
always mentioning the source
of the magical inspiration or giving
3 December 2005:
PAC.WINTER.2008
credit in a few words.
As a magician, you have to promote yourself, you are your own
boss (although customer satisfaction is your ultimate boss) and you
are 100% responsible for your own
actions. This is something I like
about being a magician
The magician, a.k.a. me, graduated in electrical engineering in
1993 from La Sapienza University
in Rome, Italy (so I was first a magician and then an engineer!). I subsequently joined ABB in Rome and
moved to Sweden in 1998 to work
for ABB Relays in Västerås.
I was invited to write something
about my magic activity and I think
I have done this in the previous sections. However, I was also asked to
write something on how the "magician" interacts with the "engineer"
and vice-versa. I have done it but in
a more subtle way which you may
have missed.
I have concerns about the lack of
ethics in today's working life. Failure to meet or even attempting to
meet promised deadlines or failure
to give credit to work that has been
inspired by others are examples of
actions that concern me. Ethics was
My motive for being
a magician was
never about
making money...
As a magician you
have to promote
yourself,
you are your
own boss!
the main topic in the university
rector’s speech at my graduation.
As a magician, I know from experience that it is possible to perform
well while adhering to strong ethics. Surely, this is also possible in
everyday life?
Consider the example of pirate
software and counterfeit products
in engineering and considered what
would happen if the same principle
was adopted by magicians. There
would not be any more magicians if
Magic Show at Vasteras Theather, Sweden
97
secrets were not kept and due credit
given to inventors of new magical
effects/tricks. Today's magic literature is rich in examples of credit
being given to the original inventor
of magic effects/tricks. Acknowledgements such as "I got the idea
after having seen Slydini’s show in
Paris in 2000. I have slightly modified the ‘Slydini move’ and changed
the presentation etc" are very common in the magic community’s
books and magazines. Shouldn’t
we try to adopt the same principle
in everyday life?
The conjugation of magician/
engineer has worked fine for me so
far. Clearly, I have to give priority
to my work as an engineer and this
has influenced the direction my life
(e.g. my move to Sweden etc.). The
magician comes ‘after’ the engineer
so I have to plan carefully my magic
shows to avoid conflicts with my
day job. I keep the magic shows to
the minimum - one or two shows
a month.
Do I do it for money? No. When
you reach a certain level as a magician, you cannot train in front of
the mirror anymore. You practice while performing so without
performances you are no longer a
magician. Money come anyway,
and the economical aspect must be
considered, in respect to magicians
that do live out of their art!
Who gives more to whom - the
magician to the engineer or the
engineer to the magician? Probably the magician gives more to
the engineer. Audience control,
understanding the body language,
preparing a speech where people
do not fall asleep, using fantasy, inventing something instead of doing
‘copy/paste’, all of these are used
by the engineer but it comes from
the magician within. Nonetheless,
the engineer provides the magician
with economic independence and
the luxury of choosing the shows
that he prefers in terms of prestige
and money.
It is funny when an engineer exits the ABB door in the evening and
enters the same door in the morning as a magician. This can occur at
‘open house’ days in my company
or perhaps at the launch of new
products when I sometimes perform a magic show.
ABB is a big company. I once
ended up participating in the of-
4 The Bonnie Kids Logo
ficial opening of the Ice Hockey
Arena in Västerås, sponsored by
ABB (it is called ABB Arena). I was
the magician and a lot of ABB employees who were present at the
opening thought perhaps they had
already seen me somewhere else…
maybe dressed differently… who
knows? In any case, I was there as a
magician!
Since the relay engineering community is very small, smaller than
the magic community for sure, it is
probable that one day we will meet
somewhere. Then if you think that
I am crazy, you will at least now understand why!
The purpose of this article was to entertain you. If you have managed to
read this far, I have hopefully achieved
this so I am happy.
www.magician.org/member/thebonniekids
Andrea Bonetti
is a relay engineer
working for after
sales customer
support and training
at ABB AB – Substation Automation Products in
Västerås, Sweden.
He graduated
as an electrical
engineer at Universitá La Sapienza in
Rome, Italy in 1993
and is member
of IEC TC 95 / MT
4 working group:
Measuring Relays
and Protection
Equipment Functional
Standards.
Andrea is a parttime professional
magician, a member
of IBM (International Brotherhood
of Magicians) and
VMK (Västerås
Magiska Klubb), the
local magic circle in
Västerås.
5 Kids don't hide their emotions
PAC.WINTER.2008
last word
98
98
Make your choice
With two issues of PAC World already
on your desk and the rich content you
can find on the web site I guess you realize that we are trying to provide you
with a wide range of information that
will keep you up to date on what is going on in our industry.
For several months, we had on
the PAC World web site a simple
question:
Do you, or your company plan on
purchasing IEC 61850 equipment?
Do you, or your company plan on purchasing IEC 61850 equipment?
The results from this non-scientific
poll are shown in the chart to the
right. Looking at the results made me
think and ask myself this question:
Why from the thousands of people
that visited the web site during that
time less than two hundred decided
to click on one of the choices?
I do not know the answer to this
question.But I think that it is
important to all of us to know the
state of our industry, to know what
our colleagues think. This will make
each of us think as well, and maybe
look for a better solution.
Now we have changed the question
on the web site. It is a simple, but
very interesting question related
to the main subject of this issue-
transmission line protection:
What type redundant relays do you
use for transmission line protection?
The answers that you can choose
from are:
Same type from different
manufacturers,
Same t ype from same
manufacturer,
Different type from same
manufacturer,
Different type from different
manufacturer.
Please take a minute, go to the web
site page, and click on your choice.
— Alex Apostolov
calendar
We offered you to answer by selecting
one of the four available options:
In next 6 months: 50.4 %
In 1 to 2 years: 17.8 %
Unsure: 19.2 %
No idea what IEC 61850 is: 12.6 %
Poll Results:
Power System
Conference
11-14 March, 2008
Clemson,
South Carolina, USA
http://www.ces.clemson.
edu/powsys2008/
Texas A&M Conference
for Protective Relay
Engineers
March 31-April 3, 2008
College Station,
Texas, USA
http://engineer.tamu.
edu/prorelay/
Africa Power &
Electricity Conference and
Exhibition
14 - 18 April, 2008
Johannesburg,
South Africa
http://www.terrapinn.
com/2008/powerza/
IEEE-PES Transmission &
Distribution Conference
and Exposition
21-24 April, 2008
Chicago,
Illinois, USA
http://www.ieeet-d.org/
Developments in Power
System Protection
Conference
17 - 20 March, 2008
Glasgow, UK
http://conferences.theiet.
org/dpsp/
Western Power Delivery
Automation Conference
6 - 10 April, 2008
Spokane, WA, USA
http://capps.wsu.
edu/conferences/wpdac/
Hannover Messe
21 – 25 April, 2008
Hannover, Germany
http://www.
hannovermesse.
de/homepage_e
Georgia Tech Fault &
Disturbance Analysis
Conference
May 19-20, 2008
Atlanta, Georgia, USA
PAC.WINTER.2008
Georgia Tech
Protective Relay
Conference
May 21-23, 2008
Atlanta, Georgia, USA
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www.selinc.com/pw1 to view
live synchrophasor measurement.
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unmatched...
D90Plus - Line Distance Protection System
The most advanced line distance protection
system in the market, GE Multilin’s D90Plus
delivers maximum performance, flexibility and
functionality. Designed as a true multifunction
device, the D90Plus eliminates the need for
external devices reducing system complexity,
commissioning time and capital costs.
Featuring advanced automation and control,
dedicated digital fault recording, comprehensive
communications including IEC61850, and an
extensive local HMI, the D90Plus represents the next
benchmark in protective relaying.
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Multilin
GE Multilin
www.GEMultilin.com/D90Plus
gemultilin@ge.com
Worldwide
Tel: 905-294-6222
North America
Tel: 1-800-547-8629
Europe/MiddleEast/Africa
Tel: +34 94 485 88 00