©2009 S&C Electric Company 766-A0901
Conventional reclosers stress the circuit with fault
current every time they reclose into a fault. The results:
Avoidable damage to the windings of upstream transformers,
conductor splices, terminators, and connectors . . . shortening
their lives. Plus voltage sags on adjacent, unfaulted feeders.
But S&C’s IntelliRupter won’t damage your system. Its
PulseClosing Technology™ performs a fast close-open operation
at just the right point on the voltage wave, putting a short, 5-ms
pulse of current on the line to test for the presence of faults.
IntelliRupter offers you:
� A completely integrated package including controls, communications, power supply, and three-phase voltage and current sensing. Eliminates cost, clutter, and complexity. Controls are line-powered, no VTs needed.
� Easy up, easy on. All system components are contained in the IntelliRupter base for easy, single- point-lift installation.
� 6LPSOH�FRQ¿JXUDWLRQ�DQG�RSHUDWLRQ from the comfort of your vehicle, using secure WiFi-based wireless communication.
� NEW! Available with IntelliTEAM SG™ Automatic Restoration System. This self-healing feeder UHFRQ¿JXUDWLRQ�V\VWHP�UHVSRQGV�WR�V\VWHP disturbances and restores power to all the loads the system can handle. With new features like Rapid Self- Healing and IntelliTEAM SG Designer, IntelliTEAM SG is faster and easier to use than ever before.
� NEW! Now with single-phase tripping capability, plus RSWLRQDO�H[WHUQDO�SRZHU�VXSSO\�DQG�¿EHU�RSWLF�FRP-munication.
S&C’s
IntelliRupter ®
PulseCloser
eliminates the
need to close into
a fault to test the line.
Current versus Time—Conventional Recloser—Fault from Phase Wire to Grounded Neutral
Current versus Time—IntelliRupter PulseCloser—Fault from Phase Wire to Grounded Neutral
PulseClosing Technology tests for faults with
non-disruptive 5-millisecond current pulses.
With each reclosing, circuit is stressed by fault current.
Still not
convinced?See an actual demo
of IntelliRupter
pulseclosing versus
a typical recloser at
www.sandc.com/ir-demo
25-kV Non-Disconnect Style
IntelliRupter PulseCloser
Screen shot
of typical
recloser
closing
into a fault
2009
AWARD WINNER
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power available wherever and whenever it is required.
May 2012 | www.tdworld.com2
Vol. 64 No. 5
CONTENTS
CO
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TO
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MA
Y2
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™
34
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Powerlink Leads With Process BusAustralia’s aggressive implementation of IEC 61850 process bus solutions
increases station capabilities.
By Pascal Schaub and Anthony Kenwrick, Powerlink Queensland,
and David Ingram, Queensland University of Technology
Targeting the Customer Smart meters and demand response are adding intelligence
to the smart grid.
By Gene Wolf, Technical Writer
Super Grid Increases System StabilityThe 400-kV super grid interconnection of six Arabian countries
is now fully operational.
By Ahmed Ali Ebrahim, Gulf Cooperation Council Interconnection Authority
When the Lights Go Out Seattle City Light improves customer service with outage management.
By Joyce Miceli and Tracye Cantrell, Seattle City Light
Cable Condition Revealed Field cable assessments at RWE Rhein-Ruhr Netzservice prove
to be technically viable and economically valuable.
By Andreas Borlinghaus, RWE Rhein-Ruhr Netzservice GmbH
Dashboards Turn Data Into InformationUnion Power turns a surfeit of data into valuable information displayed
to satisfy stakeholder needs.
By Todd Harrington and David Gross, Union Power Cooperative46
34
40
Never Compromise
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SMART ENOUGH TO KNOW WHEN TO INTERRUPT
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Today, maintaining an aging distribution
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Backed by our promise of enduring products
and the people you depend on, we continue
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May 20122 | www.tdworld.com4
DepartmentsGlobalVIEWPOINTDoug Alert: The Sky Is Falling. Is the “threat” to the grid posed by solar storms really such a big deal? By Vito Longo, Technology Editor
BUSINESSDevelopments ComEd and Municipal Leaders Establish Initiative to Improve
Storm Response ABB to Develop 1,200-kV UHV Circuit Breaker
SMARTGrid Iowa Utility to Benefit from Joint Offering with Itron for AMI Deployment First Norwegian Power Distributor Chooses Smart Metering Solution
TECHNOLOGYUpdates EPRI Tests Confirm Drone Technology Could Accelerate Outage Restoration Look-Ahead Tool to Reduce Costs, Improve Efficiencies
QuarterlyREPORTSmart Grid Evolution, Not Revolution. The emergence of smart grid technologies challenges electric utilities to manage their systems more effectively, demand teamwork and focus on distributed intelligence.By Dave Scott, Utilimetrics
CHARACTEAA RSwithCharacterBrewing Up Trouble. Mike Mueller, a senior project engineer with POWER Engineers, is always up to something, be it pushing technology to the limits or bottling his latest home-brew. By James Dukart, Contributing Editor
PRODUCTS&Services Process Efficiency Software PTZ Dome Camera
StraightTALKTTValue of In-House Engineers. BPA recognizes there is no substitute for the knowledge and system experience of in-house engineering talent.By David Hesse, Bonneville Power Administration
In Every IssueClassifiedADVERTISING
ADVERTISINGIndex
8
10
14
16
20
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66
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6871
pCONTENTS
y Powerlink’s implementa-tion of IEC 61850 process bus solutions will increase station capabilities for the utility located in Queensland, Australia.
22
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May 2012 | www.tdworld.com4
Departments
GlobalViewpointDoug Alert: The Sky Is Falling. Is the “threat” to the grid posed by solar
storms really such a big deal?
By Vito Longo, Editorial Director
BusinessDevelopmentsl ComEd and Municipal Leaders Establish Initiative to Improve
Storm Response
l ABB to Develop 1,200-kV UHV Circuit Breaker
sMARtGridl Iowa Utility to Benefit from Joint Offering with Itron for AMI Deployment
l First Norwegian Power Distributor Chooses Smart Metering Solution
technoLogyUpdatesl EPRI Tests Confirm Drone Technology Could Accelerate Outage Restoration
l Look-Ahead Tool to Reduce Costs, Improve Efficiencies
QuarterlyRepoRtSmart Grid Evolution, Not Revolution. The emergence of smart grid
technologies challenges electric utilities to manage their systems more
effectively, demand teamwork and focus on distributed intelligence.
By Dave scott, Utilimetrics
chARActeRswithCharacterBrewing Up Trouble. Mike Mueller, a senior project engineer with
POWER Engineers, is always up to something, be it pushing technology
to the limits or bottling his latest home-brew.
By James Dukart, Contributing Editor
pRoDucts&Servicesl Process Efficiency Software
l PTZ Dome Camera
StraighttALKValue of In-House Engineers. BPA recognizes there is no substitute
for the knowledge and system experience of in-house engineering talent.
By David hesse, Bonneville Power Administration
In Every IssueClassifiedADVeRtising
ADVeRtisingIndex
8
10
14
16
20
22
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contents
Powerlink’s implementa-
tion of IEC 61850 process
bus solutions will increase
station capabilities for the
utility located in Queensland,
Australia.
22
16
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Quanta Services’ roots in the power industry run deep. For generations, Quanta has been the force behind the development of the power grid. As consumption of electricity rises, so does the demand for transmission and distribution contractors. Reliability is at stake.
Quanta designs, installs, maintains and repairs electric power infrastructure. The branches of our network are far reaching and ready to mobilize. With approximately17,000 employees working in all 50 states and Canada, Quanta’s growth has made the company the foremost utility contractor with the largest non-utility workforce in the country.
The nation’s premier utilities rely on Quanta’s expertise to deliver the manpower, resources and technology necessary to meet growing demand, integrate new generation sources and deliver the power and reliability consumers deserve.
www.quantaservices.com 713.629.7600 NYSE-PWR
Reliable
May 2012 | www.tdworld.com6
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GlobalVIEWPOINT
Doug Alert: The Sky Is Falling
My associate Rick Bush long ago introduced us to
Dougs: Dumb Old Utility Guys. We are all around
the electric power industry, albeit in decreasing
numbers. It seems that Chicken Little is also alive and well,
especially in newspapers, but sometimes in industry publica-
tions and sometimes in the form of “industry experts” who
seem intent on scaring Doug into some form of action. It is
probably only a coincidence that the action sought is to spend
decent amounts of money for said industry experts to study
the situation.
While at DistribuTECH, toward the end of January, I
noticed that there were several stories in the popular media
about the “massive solar fl are headed toward Earth.” Wow!
This is pretty cool stuff. Actually, the neatest part of these
stories were the creatively powerful lines: “A powerful fl are
erupted from the sun unleashing a plasma wave that may su-
percharge the Northern Lights for sky watchers in high lati-
tudes this weekend.”
What could be cooler than a plasma wave being unleashed
on the earth? And, sure enough, there were a lot of very nifty
pictures of Northern Lights. There was usually some reference
to the sun being in the middle of an 11-year solar “weather”
cycle and that the peak of activity is expected in 2013.
This all starts to get tricky and involve the power grid when
press releases like one from EPRI end with a suggestion (or
worse) of possible doom: “Last week, the sun hurled billions
of tons of plasma at up to 5 million mph toward Earth, which
produced a dazzling light display in northern regions of the
world. Radiation from the explosion made the 93-million-mile
trip to Earth within 34 hours after the solar explosion. The
event put the nation’s utilities on alert for possible [my empha-
sis] disruption of the power grid.”
Yes, anything is possible.
For several years, industry experts have made a big deal
about geomagnetically induced currents (GIC) disrupting
this nation’s power grid and actually destroying large power
transformers. With the lead time to replace transformers, the
projection is that this could [my emphasis] cripple the power
delivery system for most of a year with ripple effects into the
economy and the health and safety of the country. (Note: Any-
thing could happen.)
Now, there’s no doubt about it, GIC is real, and there have
been serious failures attributed to this effect of solar fl ares. Ac-
tually, Dougs were rudely awakened in 1989 when GIC caused
a generator step-up transformer at a nuclear plant in the
Northeast to fail. About the same time, a similar storm caused
a widespread blackout in Québec. And, more recently, there
have been transformer failures in South Africa attributed to
GIC. So, all of this does not “signify nothing.” But, let’s get a
grip here: The sky isn’t falling, no matter how nifty a headline
that might make.
It is at least a little bit extreme for a leading power industry
publication, IEEE Spectrum, to share on its cover “How a Solar
Superstorm Could Take Down Power Grids EVERYWHERE.”
On the inside, the story was titled: “A Perfect Storm of Plan-
etary Proportions.” I know that the publishing adage is “If it
bleeds, it leads,” but planetary? Really?
Enthusiasts of the impending doom scenarios from the
solar “weather” activity have seized on “The Carrington Event”
of 1859. Notwithstanding that there are no scientifi c records,
there are reports of this event that state with certainty that
NASA scientists have said the fl are was the largest document-
ed solar storm in the last 500 years.
There is usually some reference to a telegraph operator be-
ing shocked and fi res being started. Oh, my! And now, making
an enthusiastic leap forward by about 150 years — without be-
ing encumbered by any real documented facts — some wiz-
ards of smart have postulated that a Carrington-magnitude
solar fl are could cause the power grid on earth to have a pro-
verbial meltdown.
Dougs responded to that 1989 event. When I was at EPRI
in the 1990s, my buddy Ben Damsky managed the research
project that activated the SUNBURST system. This system
alerts utilities when there is solar activity that might represent
a challenge to the grid. The challenge is the induction of a DC
ground current on transmission lines. These currents, if large
enough, can pose a danger to the large power transformers
connected to the lines. The R&D also suggested protection
schemes for these events.
A February 2012 NERC report on the effects of GIC on the
bulk power system concludes that the most likely result from
a severe geomagnetic disturbance event is voltage instability.
Among the 33 recommendations for mitigation is an assess-
ment of vulnerability. I think Dougs can take care of this.
One little-mentioned fact is that not all lines are susceptible
to GIC. It is specifi cally a risk at extreme northern and southern
latitudes. Thus, Québec, the Northeast United States and South
Africa are unsurprising locations for damage. It is hardly a plan-
etary event, and this hardly constitutes “everywhere.”
Technology Editor
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May 2012 | www.tdworld.com10
BusinessDevelopmentsABB to Develop 1,200-kV UHV Circuit Breaker
ABB will develop, design and manu-
facture a 1,200-kV circuit breaker. The
innovative circuit breaker will be de-
ployed at a national test station being
constructed by Power Grid Corporation
of India (PGCIL), India’s central trans-
mission utility, at Bina in the central
Indian state of Madhya Pradesh. The
circuit breaker will being jointly devel-
oped by ABB engineers in Switzerland
and India, with the support of PGCIL,
and will be manufactured at ABB’s pro-
duction facility in Vadodara, India.
ABB’s 1,200-kV circuit breaker is safe-
ly housed along with the disconnector
in a tank filled with insulating gas. This
unique design can result in a space saving
of up to 60% compared with convention-
al designs. The configuration protects
critical components from environmental
exposure and brings down the center of
gravity, thereby increasing its ability to
withstand seismic events. Other design
features include modular ring-type cur-
rent transformers, partial-discharge sen-
sors and composite bushings.
India is adding significant power-
generation capacity to meet growing de-
mand, which requires an efficient and
reliable T&D infrastructure to deliver
the electricity to consumers. Transmit-
ting at higher voltages enables more
power to flow through lines with mini-
mal space impact and significantly lower
transmission line losses. These factors
have prompted India to develop a 1,200-
kV transmission system, which will be the
highest AC voltage level in the world.
Visit www.abb.com.
ComEd and Municipal Leaders Establish Initiative to Improve Storm Response
ComEd and municipal leaders from across ComEd’s service territory have an-
nounced a new collaboration to coordinate response and improve customer service
during significant outage-related events by establishing Joint Operations Centers
(JOCs) in communities throughout the utility’s service territory.
Working with regional councils of government and approximately 400 munici-
palities in its service territory, ComEd will establish up to 17 region-specific JOCs,
temporary office locations that will be set up within hours of a significant service
disruption. Preselected staff will collaborate with ComEd and municipal emergen-
cy-response personnel to restore power to critical municipal facilities during major
system events so that municipalities can get their communities up and running dur-
ing these critical events. The JOCs will allow for close coordination during times
when there are significant outages and also will help coordinate priority restoration
efforts to a pre-established list of public health, life and safety facilities.
Public health and safety facilities have always been, and will remain, a priori-
ty for service restoration. However, priorities for individual municipalities can be
amended as local conditions evolve, ensuring that a municipality’s unique profile is
taken into consideration. Annual joint trainings with municipal representatives and
ComEd will ensure a strong and familiar working relationship between both the
utility and local communities.
Triggered once a set number of customers are without service for more than
three hours, JOCs will streamline communication and coordination among munici-
palities and between municipalities and ComEd during severe weather or natural
disasters. JOCs will be the hub of communications during an Area Outage Emer-
gency and will be staffed continuously by a ComEd representative and a municipal
representative who will be in constant communication with each other and ComEd’s
emergency operations organization.
Within 60 days of completing an outage-restoration mission, ComEd and the
municipality will conduct a complete evaluation and review. In addition, ComEd has
planned several technology improvements to allow for quicker response times and
improved customer service:l A smart phone app to report service interruptions and pay bills onlinel A newly acquired, US$1 million regional mobile command center that can be
deployed to the worst-hit areas in a storml A text-messaging system to report outages and receive service updates. l A revamp of the annual report summaries provided to municipalities.
For more information, visit www.comed.com.
NOVEC Customers Are Paying Less for ElectricityNorthern Virginia Electric Cooperative (NOVEC) cus-
tomer-owners are paying less for electricity than they were in
recent years because of a 2011 rate reduction, coupled with
a power cost adjustment credit they are receiving in 2012.
U.S. residential consumers who receive power from investor-
owned utilities paid on average US$125 for 1,000 kWh of elec-
tricity in January 2012 while NOVEC customers paid $119.24.
NOVEC uses short- and long-term contracts to purchase
power from several sources. In 2013, the co-op will add anoth-
er 50 MW of green electricity to its power mix when a biomass
plant it is building comes on-line. The plant will meet all envi-
ronmental standards yet keep power costs competitive.
“We ended our long-time power supply contract at the end
of 2008 in an effort to stabilize wholesale power costs,” ex-
plained Stan Feuerberg, NOVEC president and CEO. “Costs
had spiraled upward by 60% in six years, and we wanted to
drive them downward for our customer-owners.”
With lower power costs, NOVEC sought a rate decrease and a
fee modification in 2010. The Virginia State Corporation Com-
mission approved the request in 2011, and the co-op reduced
residential rates by 4.5% and commercial rates by 8.5%.
For more information, visit www.novec.com.
R ight the first time, every time is standard operating procedure for a NECA/IBEW outside line
contractor. NECA/IBEW contractors know the safety requirements like the back of their hands,
for tasks ranging from high voltage work to low-energy applications. They know the specifics, too:
How to coordinate drawings, how to work with engineers, and how to coordinate with utilities.
Working to a higher standard of professionalism and productivity is part of their package.
NECA/IBEW line contractors employ the best trained electrical line workers in the country.
Whether the job involves transmission or distribution systems, construction, power quality, line
clearance or maintenance, NECA/IBEW line contractors can save you money on every job by
delivering excellence.
Contact your local NECA line chapter or IBEW local union for more information.
Doing it right the first time is what we do best.
www.thequalityconnection.orgNational Electrical Contractors Association
International Brotherhood of Electrical Workers
N E C A / I B E W C O N T R A C T O R S • T H E Q U A L I T Y C O N N E C T I O N
May 2012 | www.tdworld.com
BusinessDevelopments
12
The U.S. National Park Service (NPS) selection of the route
preferred by Public Service Electric and Gas Co. (PSE&G)
and PPL Electric Utilities Corp. is a major step forward for the
Susquehanna-Roseland project, a regional power line that will
prevent overloads on other power lines.
The park service selection of the utilities’ route as the NPS
Preferred Alternative, part of the ongoing Environmental Im-
pact Statement process, is a milestone for the project. Utility
executives pledged to continue to work closely with the park
service to finalize details of a major land purchase that will
benefit the public and the environment.
Mitigation is a routine part of the environmental impact
review process when there are impacts on federal lands from
power lines or other infrastructure improvements needed by
society. Mitigation typically is required by federal agencies for
impacts that cannot be avoided. Under the mitigation pack-
age proposed by PPL Electric Utilities and PSE&G, thousands
of acres of land would be purchased or preserved. The value
of the package will depend on the final
assessment of impacts by the NPS, but
the utilities’ estimate the cost would be
US$30 million to $40 million.
The Susquehanna-Roseland power
line is being built to maintain the reli-
ability of the electric grid for millions
of people in the Northeast. In addition,
it is estimated that the project will save
consumers more than $200 million
per year by relieving congestion on the
power grid, which will reduce electric
bills for some customers.
The Susquehanna-Roseland power
line will run from Berwick, Pennsylva-
nia, to Roseland, New Jersey. The inde-
pendent regional power grid operator,
PJM Interconnection, ordered the new
line to prevent violations of national
standards for the operation of the na-
tion’s electric power grid.
About 95% of this 145-mile (233-km)
route would follow the path of an exist-
ing 85-year-old power line that must be
replaced because it is nearing the end
of its useful life and is undersized for
today’s electricity demands.
The Obama administration selected
the Susquehanna-Roseland line as one
of seven transmission lines nationwide
for fast-track treatment by the admin-
istration’s Rapid Response Team for
Transmission. The team is expected to
streamline the review and permitting
of transmission line projects to increase
reliability and save consumers money
by modernizing the grid. The project
will create about 2,000 jobs during its
three-year construction period.
The NPS expects to issue a Record
of Decision on the Susquehanna-Rose-
land project by Oct. 1. The utilities are
planning to have the power line in ser-
vice in time to meet peak summer elec-
tricity demand in 2015.
Visit www.pplreliablepower.com.
Susquehanna-Roseland Power Line Wins Approval
Day Ahead Dynamic Line Forecast
Day Ahead Dynamic Line Forecast
Lindsey TLM with LIDAR Conductor Height Measurement
Lindsey TLM with LIDAR Conductor Height Measurement
Model line load history, weather, and
conductor height for day ahead forecast
Model line load history, weather, and
conductor height for day ahead forecast
• Conductor Height
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• Corona Free @ 500 kV
• AC Line Powered
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Lindsey TLM Measures:
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Watch a live line installation of the TLM on our web site
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May 2012 | www.tdworld.com14
SMARTGrid
Iowa Utility to Benefit from Joint Offering with Itron for AMI Deployment
Atlantic Municipal Utilities (AMU) has contracted Tantalus for its advanced
metering infrastructure deployment. The Iowa Association of Municipal Utilities
contributed to the project with funds from a U.S. Department of Energy grant to
develop a more intelligent and more efficient energy grid.
AMU selected Tantalus based on the technical advantages of TUNet (Tantalus
Utility Network), which provides consumption reporting, power-quality monitoring,
outage notification and voltage alarms for AMU and its customers. TUNet also will
enable AMU to control select air conditioning and water heater loads.
The Atlantic, Iowa, utility becomes the first in the area to benefit from the Tan-
talus/Itron strategic partnership, which delivers a wide range of smart metering
and smart grid benefits to multiservice public utilities. The partnership ensures
that public utilities across North and Central America and the Caribbean will
be able to provide increased levels of customer service, greater service reliability,
improved efficiency and access to usage information that smart metering delivers.
For more information, visit www.tantalus.com.
Michaels Rolls Out Siemens EMS Platform Extensions
Michaels Stores Inc. is rolling out a
series of Siemens advanced extensions
to the Site Controls Energy Manage-
ment System (EMS) across the arts and
crafts retailer’s chain of stores.
Since deploying the Siemens system
in 2006, Michaels has seen substan-
tial reductions in energy consumption
across its building fleet of more than
1,000 stores. The additional savings
created by the new advanced-capability
deployments are expected to bring total
EMS-related savings to more than 30%.
“Energy is our second-highest store-
level line item expense behind labor,” said
Robin Moore, vice president for store de-
velopment and construction at Michaels.
“Through regular KPI reviews and pro-
cess improvements provided by Siemens’
Client Services team, we have been able
to sustain and increase our energy sav-
ings over time, and these new extensions
will take those savings even further. We
have been very pleased with both the ad-
vanced technology and the consultative
approach provided by our long-standing
partnership with Siemens.”
The fleet-wide expansion was preced-
ed by a thorough system analysis after a
30-site pilot and subsequent 200-site ex-
pansion. A comprehensive measurement
and verification study following these
deployments validated the savings.
The extensions include three main
items:l Intelligent Demand Control Venti-
lation (i2DCV), which enables global en-
thalpy with existing HVAC units without
expensive hardware retrofits l Psychrometric controls, which dy-
namically adjust temperature setpoints
to factor in temperature and humidity
while maintaining customer comfortl Lighting automation upgrades,
which enable more precise control of
lighting circuits such as employee areas
and stocking zones.
The extensions will provide Michaels
a cash-on-cash payback of 20 months,
and an ROI exceeding 90%. In addition,
the investment will drive further reduc-
tions in Michaels’ carbon footprint.
Visit www.siemens.com.
First Norwegian Power Distributor Chooses Smart Metering Solution
In a close race of leading system providers, Ringeriks-Kraft has selected the wire-
less smart metering system from Kamstrup for 22,000 metering points.
Ringeriks-Kraft will be the first distribution company in Norway to implement a
smart metering system since the Norwegian Water Resources and Energy Director-
ate (NVE) issued the directive about countrywide implementation of smart meters
before Jan. 1, 2017. The meter installation will take place in 2012-2013.
The power company will be able to benefit from more accurate billing and
smoother communication with their customers with the automatic and on-demand
collection of hourly values from the meters and a two-way communicating system.
The precise load profile of single meters and of whole areas will strongly improve the
energy efficiency for the benefit of the environment and the economy.
For more information, visit www.ringeriks-kraftnett.no.
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May 2012 | www.tdworld.com16
TechnologyUpdates
EPRI Tests Confirm Drone Technology Could Accelerate Outage Restoration
The Electric Power Research Insti-
tute (EPRI) has completed tests deter-
mining that unmanned aircraft systems,
or drones, can be used effectively to as-
sess storm damage on utility distribu-
tion systems.
Conducted at the New Mexico State
University Flight Test Center, the tests
involved navigating several aircraft tech-
nologies and using high-resolution vid-
eo cameras to transmit images of power
lines from a height of 5,000 ft to 7,000 ft
(1,524 m to 2,134 m). The tests deter-
mined that such images can be used by
electric utilities to assess damage and
pinpoint its location following a storm.
In the wake of a storm, damage as-
sessment is frequently a choke point in power restoration due largely to obstacles,
such as downed trees blocking roads or icy conditions that make it extremely diffi-
cult for utility crews to get to and report on distribution line damage.
“Our research clearly shows that drones may provide utilities a tool that could
reduce outage-restoration time,” said Matthew Olearczyk, senior program manager
for distribution research at EPRI. “Using live steaming video information, utility
system operators would be able to dramatically improve damage assessment.”
With more accurate and timely information, system operators can better dispatch
crews, establish repair priorities, and communicate timely and accurate information
to customers. Researchers assessed several drone technologies, looking at aircraft
performance, control systems and payloads. The tests indicated that unmanned air-
borne technologies equipped with sensors, cameras and GPS could be deployed
faster, allowing utilities to evaluate large areas more quickly than ground-based
crews, then develop a repair strategy and mobilize crews quickly and effectively.
EPRI also will be evaluating drones and remote-sensing technologies for inspec-
tion and assessment of overhead transmission lines. As part of this research, func-
tional requirements will be identified for unmanned aerial vehicle (UAV) inspec-
tion and market surveys will identify available UAV inspection technologies, services
and their costs.
For more information, visit www.epri.com.
Look-Ahead Tool to Reduce Costs, Improve Efficiencies
With approval from the Federal En-
ergy Regulatory Commission, MISO
implemented a new Look-Ahead Com-
mitment (LAC) Tool for its power grid
operators, which will improve opera-
tional efficiencies and reduce the cost of
wholesale power.
The LAC Tool more efficiently plans
near-term resource commitments in
the real-time market. By conservative
estimates, the tool is expected to save
upwards of US$2 million per year to the
region, which covers 11 states and Mani-
toba, Canada.
MISO developed the tool after ex-
tensive analysis of the current process
used in real time for the commitment of
resources to produce energy. The tool
provides displays to the control room
operator, giving access to new operation-
al information. The “smart-thinking”
application will help decision making
and enable fast actions that will keep
power flowing efficiently. MISO’s Inde-
pendent Market Monitor has consistent-
ly identified a look-ahead capability as a
means of improving the commitment of
fast-start resources.
“The current Intra-Day Reliability
Assessment Commitment process is less
efficient for near-real-time resource
commitments and often must be done
manually,” said Richard Doying, vice
president of operations. “The LAC Tool
is a new online process. We will be able
to better identify upcoming changes
and more efficiently commit resources
to meet those needs.”
Visit www.midwestiso.org.
Drone technology being used for distribu-tion system assessment.
Sensus Gains Exclusive U.S. License for Consumer Energy Management Technology from Navetas
U.K.-based Navetas Energy Management has contracted
Sensus to deliver its energy management software, which al-
lows consumers to accurately and intelligently monitor the
electricity consumption of discrete devices on their premises.
Utilities deploying the licensed wireless Sensus FlexNet
advanced metering infrastructure (AMI) system will be able
to leverage the Navetas software as an optional service that
provides residential and commercial customers with an online
portal or mobile app showing precise electricity consumption
data from various appliances. The system gives consumers ac-
cess to detailed information about daily usage patterns and
the cost associated with each device.
Utilities can offer the nonintrusive load-monitoring tech-
nology as an added service to facilitate broader customer
engagement, producing an online dashboard with compre-
hensive energy-profile data so that the consumer can make
informed decisions on their monthly utility usage.
Visit www.sensus.com and www.navetas.com
Supported by a global network of application experts, the Multilin 3 Series
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options including IEC 61850.
The Multilin 3 Series protection relays feature detailed asset diagnostic
capabilities, and a robust draw-out design to maximize uptime. Customers
rely on GE’s Multilin 3 Series to protect their essential electrical infrastructure
and critical assets.
From oil and gas and mining, to utility substations and light
rail, GE’s Multilin™ 3 Series provides advanced protection for
feeders, motors and transformers in demanding environments.
)DVW��DFFXUDWH��ÀH[LEOH�SURWHFWLRQ
g Energy
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North AmericaTel: 1-800-547-8629
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May 2012 | www.tdworld.com18
technologyUpdates
TLM Device Assists with Dynamic Rating and Forecasting of HV Line Capacity
Lindsey Manufacturing Co. intro-
duces the Transmission Line Monitor
(TLM) to assist with real-time rating and
forecasting of high-voltage line capacity.
Developed in conjunction with the
Idaho National Laboratory (INL), the
TLM enables electric utilities to maxi-
mize their transmission resources by cal-
culating each line’s dynamic capacity. By
knowing the conductor’s height clear-
ance history for a load under specific
weather conditions, operators can fore-
cast the line capacity for similar future
weather conditions with a high degree
of confidence.
Company President Keith E. Lindsey
says the TLM will change the way elec-
tric T&D infrastructure is maintained
and managed worldwide. “This is the
first ‘smart’ device of its kind deliver-
TLM helps utility operators forecast how much additional line capacity is available without violating clearance regulations.
ing valuable operational information
on high-voltage transmission lines,”
said Lindsey. “Based on the initial INL
design, our company developed ways to
measure line sag, conductor tempera-
ture, and tilt and roll of the conductors,
as well as the distance to any object be-
neath the line. We also tasked the sen-
sors to detect Aeolian vibration, which is
an indication of wind blowing across the
conductor, and ‘galloping.’”
Lindsey continued, “By gathering
weather history from locations around
an installed TLM, line current history
and exact conductor height history, util-
ity operators can forecast 24 hours in ad-
vance how much additional line capacity
is available without violating clearance
regulations.”
The TLM uses Light Detection and
Ranging (LiDAR) technology to accu-
rately measure the height of the trans-
mission line relative to crossing con-
ductors or vegetation below the line. Its
onboard sensor package incorporates
two temperature sensors: one measures
conductor temperature up to 250°C in
real time and the other measures am-
bient temperature. A pair of dual-axis
MEMS (micro electro-mechanical sys-
tem) accelerometers measures the vibra-
tion characteristics of the transmission
line and determines its tilt and roll.
Each TLM is remotely programma-
ble, has a GPS address and communi-
cates in a self-healing wireless mesh net-
work over the 915-MHz band. Data from
the device are encrypted compliant with
the National Institute of Standards and
Technology AES 256-bit standard, and
are available at the endpoint ground lo-
cation in DNP3 format, which integrates
to most installed smart grid communica-
tion systems.
Visit www.lindsey-usa.com.
Thank You.
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Emergence of Data AnalyticsThe example above speaks to another trend just starting to
evolve in the smart grid market: distributed intelligence. Re-
mote analytics and the appropriate automation provided via
the short-term storage of device data and local data processing
requires device integration and embedded intelligence into
the distribution system.
This and real-time processing of data in the field, rather
than in a utility’s back office, requires vendor relationships,
open frameworks and cross-utility vision of how the distribu-
tion system is managed and reported on. The distribution in-
telligence example is rapidly growing along with intelligence
downstream from the meter into the customer’s home, sup-
porting customer information, energy management and dis-
tributed resources.
Partnership Between Utilimetrics and UtilitiesThe task of building a smart grid road map is no small
feat. It requires visionary leadership as well as utility expertise
around the purchasing decisions, device configurations, and
data mining and analytics activities. Plus, there is so much to
be gained from learning about each other’s experiences.
Utilimetrics is a trade association of utilities, consultants,
vendors and other professionals engaged in or considering
utility automation. For decades, Utilimetrics has supported
the industry as it has progressed from manual meter reading,
to automatic meter reading, then advanced metering technol-
ogies, and now advanced distribution and home technologies.
As Utilimetrics continues to evolve its role in supporting the
smart grid market, data management and analytics will drive
the future.
Dave Scott ([email protected]) is the treasurer of
Utilimetrics, the world’s premier utility automation association.
For the last 25 years, Utilimetrics has provided information and
educational programs for utility professionals about innovative
technologies that lead to improved operations, customer
service and resource utilization. He is a senior project manager
at SAIC and helps utilities develop business cases, procure and
deploy AMI and smart grid systems.
Editor’s note: Learn more about the smart grid future as well
as lessons learned from your utility peers about advanced
metering infrastructure and smart grid deployments by
attending Autovation 2012, Sept. 30-Oct. 3, 2012, in Long
Beach, California, U.S.
QuarterlyRepoRt
Smart Grid Evolution, Not Revolution
By Dave Scott, Utilimetrics
The progress to date of smart grid projects funded by the
American Recovery and Reinvestment Act and the U.S.
Department of Energy, as well as various other smart
grid implementations across the United States, has taught the
utility industry one clear thing: smart grid is all about evolu-
tion, not revolution. Sector growth and product options have
exploded with the onset of big data, faster communications,
and management and reporting capable devices that Utilimet-
rics has long envisioned.
In 2012, utilities have a myriad of options to define, develop
and ultimately roll out a smart grid program. However, with
these purchasing decisions comes a magnitude of challenges.
Utilities must address how to integrate and manage the meter-
ing infrastructure, outage management software, meter data
management applications, in-home automation, distribution
automation as well as the associated management applications
that spotlight network and device health. Ultimately, these de-
cisions could drive the data mining and analysis activities that
determine the distribution system operational efficiency and
long-term feeder reliability.
For example, many utilities across the United States have
transitioned from one monthly register read to technologies
that support time-of-use rates from usage data obtained at a
minimum of five-minute intervals. This brings with it complex
communications and marketing campaigns. The goal of these
campaigns is to educate and encourage customer participa-
tion in demand-response programs, as well as share an inter-
nal vision of the value and underlying drivers to obtain and
efficiently manage data down to such specific intervals. The
configuration decisions associated with these meters dictates
and drives value for other upstream systems looking for indica-
tors of power quality, feeder health and revenue assurance.
Demand for TeamworkThis vision of a “connected grid” is now driven by the idea
of a “connected utility.” Engineers concerned with power qual-
ity indicators, IT professionals concerned with network perfor-
mance, business analysts concerned with reliability indicators
and financial analysts looking at financial drivers must now
work together to develop their smart grid footprint. This level
of inter-utility teamwork is required to determine device capa-
bilities, configurations and calculations that can be developed
to expose the inter-device relationships and ultimately pro-
vide the full value of a smart grid. A simple example is voltage
sensing at the transformer and meter to generate exception
reports indicating voltage-regulation needs.
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CHARACTERSwithCharacter
Brewing Up Trouble
Mike Mueller, POWER Engineers
By James Dukart, Contributing Writer
As you’re reading this, Mike Mueller may be thinking
underground thoughts, crafting a new IPA beer or
“tickling the ivories” for the pleasure of his two young
daughters. In fact, there’s a good chance he’s done two out of
three within the past 24 hours.
Mueller — pronounced “Miller” like the famous Milwaukee
beer (more on that later) — is a senior project engineer with
POWER Engineers in St. Louis, Missouri, U.S. During his day-
time workday hours, he specializes in underground transmis-
sion, or more specifically in what he calls “pushing the technol-
ogy to the limits of its capabilities” by going longer distances
underground or stringing subterranean cable beneath and
through lakes, ship harbors and bedrock.
In his off-work hours, you’re more likely to find Mueller fill-
ing a “growler” with a new home-brew or banging out a tune
on the piano.
Mueller’s been in underground transmission for about 10
years, starting with an internship with an electrical construc-
tion contractor in his hometown of Milwaukee, Wisconsin,
U.S., following engineering school.
“I went out and got down and dirty in the field with some
linemen and splicers,” said Mueller, calling that “a whole new
education in itself.” With that sample of field work, Mueller was
drawn to “UG” [his terminology] with all its “crazy constraints
and requirements.”
“We have to think outside the outside the box in order to
build a line from point A to point B underground,” he stated.
“You might have wetlands to protect, have to get approvals to
go underground in certain areas and the subsurface can be
very hard bedrock.”
Among the more memorable projects Mueller recalls was
channel dredging in the Biscayne Bay just south of Miami,
where the U.S. Army Corps of Engineers needed to dig the bay
deeper for larger ships. He was part of the team that helped
bury transmission lines deeper in the bay. He also calls a
Virginia water-crossing project “wild and crazy” in the sense
that drilling concepts perfected in the oilfields were used to
install cable for a span of some 7,000 ft (2,134 m) under the
water, landing exactly where it needed to be on the other side.
“We get heavily involved in cable sizing and the ampacity
of the lines,” Mueller noted. “Submarine cables are hot now
and that will probably increase with offshore wind projects.”
He claims that drilling for underground transmission may
offer significant advantages over either trenching or stringing
transmission overhead. “Aesthetically, the public wants every-
thing underground, and that is good for me if those projects
happen,” he said.
Mueller himself may not be as “wild and crazy” as in his
youth. Married and with one-year-old and three-year-old
daughters, he has forsaken playing piano in rock bands — “We
played all over the Milwaukee area, the music of The Doors
and Yes” — to playing for a much younger, captive crowd now.
“I’ve got a career and a family now,” Mueller commented. “I
also travel a lot, so when I’m home, it’s always nice to sit down
and play some music for my girls.”
Mueller has always seen music as essentially mathematical
and sees parallels between music and engineering. Deciding
to pursue one or the other as a career wasn’t something he
took lightly.
“I almost went to music school, but my dad said, ‘You might
want to consider a different career path,’” he noted. “He said,
‘Why don’t you go to engineering school first? Then you would
have something to fall back on if the music didn’t work out.’”
Another family member helped turn Mueller on to his oth-
er passion: home-brewing.
“A year or so ago, my wife Maggie said I should pick a new
hobby,” Mueller explained, “so I kind of all of a sudden jumped
into the world of home-brewing.”
For Mueller, that meant reading all the beer-brewing fo-
rums he could find online, buying all the equipment he’d
need and focusing on all-grain brewing, meaning he mashes
his own grains to turn into home-brew. He admits to spending
up to four or five hours at a time on Saturdays and Sundays
brewing, bottling or studying the subject.
“You can mix and match with different hops and grains
and get what sort of flavor you want,” he commented. “I bought
three kegs that are old 5-gallon soda kegs and got my own little
CO2 tank. I fill up my growlers [home-brew talk for half-gallon
beer bottles] and take them to parties and events. It’s sort of a
way to use my nerdiness to come up with some cool ideas.”
Mueller home-brews in another famous beer town — St.
Louis — so one might surmise that this whole beer thing may
have always been in his blood. That said, he makes a clear dis-
tinction between his hometown while growing up and the city
where he fills his growlers today.
“I went as long as I could without a Bud or Bud Light when
we moved here,” he stated. “I’ll go to the Cardinals games
sometimes, but I’ll always be a Brewers fan at heart!”
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Australia Leads With Process Bus
Powerlink Queensland has undertaken an aggressive
program of research, development and implementa-
tion of IEC 61850-based system solutions. The intent
is to move towards an IEC 61850 process bus using a
two-step approach.
Powerlink is a government-owned corporation that owns,
develops, operates and maintains the state of Queensland’s
high-voltage electricity transmission system for approximate-
ly half of Australia’s eastern seaboard. The utility’s internal
engineering group develops in-house standard designs for
substation automation systems (SAS) based on commercially
available products from global suppliers. Project-specifi c de-
signs based on the standard designs are implemented by the
in-house engineering group as well as external contractors.
The Two-Step ApproachPowerlink’s fi rst step in moving towards an IEC 61850
process bus is the development and implementation of a new
multi-vendor SAS standard design based on IEC 61850 station
bus by 2012. The second step includes the implementation of
technology facilitated by an IEC 61850-9-2 multi-vendor pro-
cess bus, such as nonconventional instrument transformers
(NCITs) and smart switchgear with electronic interfaces. The
optimum time for the second step depends on the ongoing
development of international standards and the availability of
products compliant with those standards.
Powerlink is undertaking several projects trialing the im-
plementation of IEC 61850-9-2 process bus to investigate this
technology and the current maturity of the market. Projects
include the refurbishment of the Loganlea SAS and the trial
of a fi ber-optic current transformer (FOCT) on a 275-kV line
reactor bay at Powerlink’s 330/275-kV Braemar Substation.
These two projects, coupled with Powerlink’s participation
in university research projects and the international working
group developing the IEC 61850 standard, will allow Power-
link to establish a valuable understanding of the technology
Powerlink’s implementation of IEC 61850 process bus solutions increases station capabilities.
By Pascal Schaub and Anthony Kenwrick, Powerlink Queensland,
and David Ingram, Queensland University of Technology
26 May 2012 | www.tdworld.com
protection&Control
developments and further refine the technology road map for
implementation of IEC 61850 process bus.
The first substation will be the 275/110-kV Loganlea Sub-
station project, which employs NCITs communicating with
the protection system through a switched Ethernet network
using an IEC 61850-9-2 sampled value (SV) process bus. This
is the world’s first commercial installation of a substation
protection system outside of China
based entirely on IEC 61850-9-2 SV
process bus communication.
In 1999, Powerlink introduced
ABB’s iPASS (intelligent plug and
switch system) hybrid outdoor gas-
insulated switchgear (GIS) with a
series of turnkey projects. Four of
the turnkey projects were part of
the 275/330-kV Queensland–New
South Wales Interconnector (QNI)
and two further substation up-
grades that used iPASS.
The QNI substations are the
backbone of the essential inter-
regional interconnection. With a
design life of 15 years for SAS, Pow-
erlink is planning to refurbish six
substations.
The existing iPASS switchgear is based on a single-phase
unit, with each unit containing a circuit breaker, isolator and
earth switch, and a NCIT at each bushing. Separate electronic
modules, built into the primary switchgear, are used for the
control and supervision of the switchgear (circuit breakers
and disconnector/earth switches) and for the acquisition of
current and voltage samples derived from the NCITs. The
www.PowerPD.net
A substation automation system diagram using the intelligent plug and switch system.
HMI
Networkoperations
center
Baycontroller
ProtectionX
ProtectionY
iPASSswitchgear
MUPX
MUPY
Commsgateway
Commsgateway
GPS clock X
GPS clock Y
Baycontroller
iPASSswitchgear
MUPX
MUPY
ProtectionX
ProtectionY
27www.tdworld.com | May 2012
protection&Control
electronic modules are an integral part of the
SAS. The interface of the iPASS switchgear with
the bay-level equipment uses a proprietary fiber-
optic point-to-point process connection.
Refit KitWith the approaching end of design life for
the SAS, Powerlink and ABB jointly developed a
generic retrofit product that can be progressively
applied to all six iPASS substations.
With the kit, the circuit breaker and disconnec-
tor/earth switch control are replaced with a con-
ventional hard-wired solution. A new electronic
module for the existing NCITs is included as part
of the iPASS refit kit, providing a SV process bus
interface based on the UCAlug implementation
guideline for IEC 61850-9-2, also termed the 9-2
light edition (9-2LE).
The refit kit has been tested and proven in a
field trial conducted on a 275-kV line reactor bay
at Powerlink’s Braemar Substation. The 275/110-
kV Loganlea Substation was the first site for the refurbishment
solution.
One of the main components of ABB’s NCIT solution for
iPASS includes a CP (current/potential) transformer combi-
nation, electronic current and voltage sensor (single-phase
unit), which is designed for use in GIS products. The CP is a
modular design and has two fully redundant measuring sys-
tems. The existing primary sensor, which is built into the GIS
enclosure, is retained. This unit contains two Rogowski coils
for current measurement and a gas capacitive divider for volt-
age measurement.
A redundant set of secondary converters (CP-SC) samples
the current and voltage transducer outputs and then sends
these to the IEC 61850-9-2 merging unit for protection (CP-
MUP). Transmission of the signal is through one of two fiber-
optic data outputs. Both outputs can be used for protection ap-
plications or, alternatively, one output can be used for revenue
metering. The point-to-point data link between CP-SC and
CP-MUP is a proprietary ABB solution. The CP-SC is mounted
on the primary equipment, and the CP-MUP is installed in the
substation control room.
The CP-MUP synchronizes the current and voltage sam-
ples received from the various secondary converters. The port
mapping of the built-in Ethernet switch is configurable, allow-
ing the user to direct the SV data streams produced by the
internal MU logical devices to specific Ethernet ports on the
switch.
The CP-MUP port-mapping feature also allows the user to
receive a SV data stream from another MU device on one Eth-
ernet port and direct that data to any of the intelligent elec-
tronic devices (IEDs) connected to the other CP-MUP Ether-
net ports. This functionality overcomes limitations associated
with an IED with only one physical Ethernet port for a SV
process bus where it requires SV data streams from multiple
physical MU devices.
Substation Automation System ArchitectureThe application of SV according to 9-2LE results in two
mission-critical networks: a process bus Ethernet-based local
area network (LAN) and a 1-pulse per second (1PPS) time syn-
chronization network.
The protection and control IEDs support 9-2LE on one
physical Ethernet port, leaving a second Ethernet port for the
station-level communication according to IEC 61850-8-1 (ge-
neric object-oriented substation event [GOOSE] and manu-
facturing message specification). The IEDs also feature one
1PPS input to synchronize sampling of conventional current
transformer inputs and SV data streams for the purposes of
differential protection.
The majority of Powerlink’s iPASS installations have the
switchgear laid out as a breaker-and-a-half diameter. The
configuration of the switchgear (including the number of
NCITs — six per diameter) will not change as a result of the
refurbishment and installation of a new SAS. The original de-
sign philosophy for fully overlapping protection zones using
all NCITs in each diameter will continue with the new SAS.
The number and location of NCITs were already determined
by the location of the switchgear; the issue to be addressed
was the number of MUs per diameter and their connection to
both the NCITs and the protection and control IEDs.
To address the requirements of Australia’s national elec-
tricity rules, the protection system is duplicated. All MUs are
configured as time masters, supplying the connected IEDs
with the 1PPS signal. There is no constraint or dependence
between the MU clocks as these operate as time islands. The
MU connections for this layout use the second output signal
(PPL2) from both CP-SCs on the Q30 coupler breaker.
The protection IED for feeder 1 in the Loganlea Substa-
tion requires the summation of two separate current NCITs
to determine the total current flowing on the feeder. The sub-
station configuration allows the summation to take place in
Simplified breaker-and-a-half diameter layout at Loganlea Substation with three CP-MUPs.
1 Bus Feeder 1protection
PPL1
CB Q10
PPL1
PPL2
Feeder 1
PPL1
CB Q30PPL1
Feeder 2
PPL2
PPL1
Bay controllerQ20
CB Q20
2 BusPPL1
Power-to-power link (PPL1)9-2LE1PPS
CP-MUP
CP-MUP
CP-MUP
NCIT
NCIT
NCIT
NCIT
NCIT
NCIT
Bay controllerQ20
Bay controllerQ30
Feeder 2protection
28 May 2012 | www.tdworld.com
protection&Control
the protection IED by receiving the two currents from a single
CP-MUP, removing the requirement to synchronize with any
other CP-MUP. The same also is true for the protection IED
for feeder 2.
The bay control functions for the Q10, Q20 and Q30 bay
control IEDs are each derived from a single CP-MUP and,
therefore, are independent of the time-synchronization sys-
tem used by the other CP-MUPs. CP fail
and bus zone protection are performed
in ABB’s REB500 system, with each bay
unit connected to a different CP-MUP.
The station bus architecture for Pow-
erlink’s iPASS SAS refurbishment is a
single-ring LAN topology. GOOSE has
been used for the auto-reclosing function
that resides in the bay controller. Both the
main 1 and main 2 protection can initi-
ate auto-reclosing through the station bus
LAN with GOOSE messages.
The main 1 and main 2 duplicate pro-
tection systems installed are to remain
physically and electrically separated at all
times to satisfy the redundancy require-
ments of the national electricity rules.
The process and station-level networks
are physically separate 100-Mb/sec LANs.
The process-level network is only being used for the transmis-
sion and distribution of SV data, and each bay has its own
process bus LAN. Communications gateways and human-
machine interface have a dual attachment to the two station
Ethernet switches for improved availability. The GPS clock
provides time synchronization for the time-stamp accuracy of
events through the station-level network.
This breaker is ready for installation of the intelligent plug and switch system refit kit.
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absorb power generation from small local power producers and handle new
power consumption patterns.
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transforming their ageing power grids into state of the art smart grids. The
digitalization of the existing power equipment allows the power companies
to prepare for a new power distribution future with more alternative energy
sources as well as different load patterns from electrical vehicles.
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The system is based on optical sensor technology with a 2-way communication technology. Using the DISCOS®�6\VWHP��\RX�ZLOO�EH�
able to get control over your grid and make it smart!
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Reusable Power Distribution Ageing assets and a greater array of renewable energy sources are pushing power distribution companies to digitalize their infrastructure through smart grid technology.
sensethepower.com
30 May 2012 | www.tdworld.com
protection&Control
Handling the TransitionPowerlink has developed considerable knowledge on the
existing iPASS substations since their introduction in 1999.
The knowledge continues to grow now that the technology is
being used with the implementation of the new SAS solution.
The new IEC 61850-based solution offers a more integrated
system. The sending and receiving of protection, control com-
mands and indications, and monitoring information over the
same equipment or network will need to drive changes to ex-
isting work practices and procedures. The identification of a
protection or control IED’s boundaries will not be possible in
the same manner that it has been to date.
The personnel working with the SAS will need a combined
knowledge and understanding of protection and control equip-
ment, systems and philosophies, as well as data networking
skills. There is a change in skills, knowledge and requirements
for designers and field staff alike. Powerlink was intimately in-
volved in the design process for the Loganlea solution. From
this experience, it is apparent a centralized approach to the
IEC 61850 system design and configuration (including net-
work addressing and data flows), where all SAS design infor-
mation is drawn together at a systems level, will be required for
the successful delivery of IEC 61850-based systems.
From a utility perspective, this requires the review and re-
development of roles, reallocation of responsibilities within
the design groups and associated skills development. Change
management to existing roles within the automation and
protection areas is where the most effort and benefit will be
gained to ensure the process is a success.
It also is likely some of the maintenance activities that cur-
rently require attendance on-site for existing systems may be
undertaken remotely in the future. In addition to the higher
skill and aptitude requirements of the field staff responsible for
the operation and maintenance of substations, there will be a
need to maintain and develop a support group consisting of
highly skilled subject matter experts because of the complexity
and level of integration of the IEC 61850-based systems.
Some of Powerlink’s key design and field test staff were in-
volved in the delivery of the Loganlea project to ensure the
utility had a detailed understanding of the technology and
the solution satisfied all of Powerlink’s requirements. The Lo-
ganlea system successfully passed its factory acceptance test in
Switzerland and was commissioned in 2011. The experience
Powerlink gained from this project will greatly assist it in the
future development of a standard design for an IEC 61850 pro-
cess bus solution.
Looking ForwardSAS products have a typical operating life of 15 to 20 years,
but the primary plant is expected to operate for 40 to 60 years.
This presents an opportunity to implement SV process buses in
existing substations with conventional instrument transform-
ers, a manner similar to Powerlink’s refurbishment of Logan-
lea. An Ethernet-based process bus provides well-documented
safety and engineering benefits, but, to realize these benefits,
the merging units generally need to be mounted at the pri-
mary plant. With the ABB iPASS refit kit, the CP-MUP merg-
ing units can be installed in the control room because of the
legacy fiber-optic process connection. Installation of merging
units in the field with a switched process bus further reduces
A line reactor bay with the intelligent plug and switch system.
© BURNDY LLC, 2012
1-800-346-4175 USA | 1-603-647-5299 International | 1-800-387-6487 Canada | www.burndy.com/implo
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protection&Control
field cabling, as Ethernet switches can aggregate the SV data
from several merging units.
Merging units for conventional instrument transform-
ers take industry-standard current (1-A/5-A) and voltage
(100-V/110-V) inputs. NCIT merging units are a little different
in that digital connections from NCIT secondary converters
(CP-SC in this project) to merging units are proprietary. It is
the role of the merging unit to convert measurement data into
the format specified by IEC 61850-9-2.
Point-to-point (un-switched Ethernet) IEC 61850-9-2 sys-
tems, available from several vendors, may be a way of gradu-
ally moving to a station-wide process bus, as this topology is
similar to existing analog systems. Different network architec-
tures also offer design diversity, so a point-point system could
be used in parallel with a whole-of-substation switched Ether-
net process bus.
Future ChallengesMany manufacturers have implemented 9-2LE, but only
two merging units, including the CP-MUP from ABB, have
received certificates from UCAIug for Part 9-2 of IEC 61850 at
this time. Powerlink’s investigations have shown that many SV
implementations comply with 9-2LE; however, there have also
been products that do not implement the standard correctly.
This prevents interoperability, suggesting that products need
to mature further. Vendors need to be testing their SV publish-
ers and subscribers with products from their competitors.
Vendor diversity is widely practiced in Australia, with the
only exception being for certain turnkey substation contracts.
The diversity of the make and model of IEDs and merging
units is intended to mitigate the risk of common mode fail-
ures, but the complexity of IEC 61850 systems works against
this for two reasons:
l Many IEC 61850 vendors use commercially available
stacks to implement their products, so there is a chance X and
Y protection IEDs are based on the same software.
l In-house implementations will take considerable effort to
perfect. Errors in 9-2LE encoding of data from both large and
small vendors confirm this is the case.
Powerlink is looking to implement a SV process bus but is
constrained by the lack of commercially available products,
particularly for merging units. Western protection manufac-
turers have yet to bring a merging unit for the connection of
conventional instrument transformers and switched Ethernet
to market, while Asian manufacturers have sufficient home
market demand so there is little promotion of their products
in Australia.
Single-vendor IEC 61850-9-2 process bus products are avail-
able that use a proprietary, yet documented, dataset. These
systems may have application in parallel with conventional
process connections, but multi-vendor support is needed for a
whole-of-substation implementation.
A major impediment to the widespread introduction of
9-2LE process buses is the very limited availability of SV sub-
scribing revenue meters, phasor measurement units (PMUs)
and transducers. Powerlink is building many new substations
to satisfy customer growth or new power station connec-
tions. Both of these require revenue metering and cannot
be achieved with a digital process bus at this time. Wide-
area measurement systems using PMUs located throughout
the country may miss out on critical data unless PMUs that
can use SV data are developed. A major benefit of a switched
Ethernet process bus is that a single device can perform the
PMU function for all feeders, and a single Ethernet connec-
tion is all that is required.
Pascal Schaub ([email protected]) holds a bachelor’s
degree in computer science from the Technical University in
Brugg-Windisch, Switzerland, and is the principal consultant of
power system automation for Powerlink Queensland. Prior to
joining Powerlink, he worked for ABB in Switzerland. Schaub is
a member of the Standards Australia Working Group EL-050
‘Power System Control and Communications’ and the Inter-
national Working Group IEC/TC57 WG10 ‘Power System IED
Communication and Associated Data Models.’
Anthony Kenwrick ([email protected]) holds a
bachelor’s degree in computer and electrical engineering from
the Queensland University of Technology and is a secondary
systems support engineer at Powerlink Queensland. He has
worked in several different positions on secondary system
design, construction, commissioning and testing. Kenwrick is a
registered professional engineer of Queensland.
David M.E. Ingram ([email protected]) holds a bachelor’s
and master’s degree in electrical and electronic engineering
from the University of Canterbury and is a Ph.D. candidate at
the Queensland University of Technology. He has worked for
several utilities including Powerlink before commencing his cur-
rent study. Ingram is a senior member of the IEEE, a chartered
professional engineer and a registered professional engineer of
Queensland.
Company mentioned:ABB | www.abb.com
Powerlink staff undertaking the commissioning of the supervisory con-trol and data acquisition system.
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demandResponse
Targeting the Customer Smart meters and demand response are adding intelligence to the smart grid.By Gene Wolf, Technical Writer
One of the most controversial issues within the
electric power industry today is how does a util-
ity keep up with the customer’s growing power
demand? It is a timely discussion — even though
energy usage has dropped the last few years — because of the
recession. The recession is a short-term condition that will be
forgotten as the economy recovers. In the long term, a study
by the Battelle Memorial Institute projects world demand for
electricity will increase nearly 44% between now and 2030.
The study anticipates electrical demand in North America will
increase by about 26% during the same time period.
Utilities are keenly aware there is a problem. A large por-
tion of existing infrastructure has aged well beyond its expect-
ed lifetime. Depending on the expert quoted, hundreds of bil-
lions of dollars and euros are needed for new facilities to meet
the demand worldwide. Utilities cannot build their way out of
this problem. There is not enough time, money or motivation,
but there is a solution.
Utilities are turning to technology
— not some mythical silver bullet — to
come to the rescue. This is real-world
technological innovation using existing
tools available from demand-response
(DR) providers today. GlobalData’s “De-
mand Response – Global Market Sizing,
Analysis and Forecasts to 2020” report
estimates global DR capacity under man-
agement was in the range of 37,000 MW
for 2009. Illustrating that, the Brattle
Group reported DR technology offset
the 2010 peak load at PJM by 6.3%, ISO
New England by 5.6%, New York ISO
by 6.8% and Midwest ISO by 8.2%.
1,600,000
1,400,000
1,200,000
1,000,000
800,000
600,000
400,000
200,000
0
Num
ber
of cu
sto
mers
TRE FRCC MRO NPCC RFC SERC SPP WECC Other
Investor-owned utilitiesMunicipal entitiesCooperative entities
NERC region
Reported number of customers enrolled in direct load control programs by region and type of entity. Courtesy of FERC.
35www.tdworld.com | May 2012
demandResponse
DR technology is delivering significant
reductions to utilities and operators daily.
Tangible Technology, Not Vaporware
By combining advanced meters with DR
technology, utilities have been able to en-
gage directly with their customers — com-
mercial and residential — through two-way
communication. For the first time, it is pos-
sible to provide customers tools and real-
time information to reduce energy con-
sumption and improve energy efficiency.
Several factors have aligned to make
this possible, such as the cost of smart meters dropping like
a rock in the past 10 years. Remember when they ran about
US$3,000 per customer installation? Today, the cost is run-
ning about $100 per installation, and utilities are installing
advanced meters in the millions.
Enhancements The industry also has seen huge improvements in DR tech-
nology. It has evolved from direct load control (for example,
cycling air conditioners and pool pumps) to constant load
management.
According to the Demand Response and Advanced Me-
tering Coalition (DRAM), residential customers account for
nearly 40% of the electricity consumption and would provide
about 53% of the potential DR savings. DRAM went on to
say that several years ago Puget Sound Energy initiated a DR
program by deploying digital meters and placing more than
300,000 volunteer customers on time-of-use rates.
According to the DRAM report, the merger of smart me-
ters and DR programs reduced Puget Sound Energy’s peak
demand by roughly 6%. The total power usage was reduced by
about 5%. In the parlance of Las Vegas blackjack players, it is
a double down when DR and energy efficiency are combined
with advanced metering.
1,600,000
1,400,000
1,200,000
1,000,000
800,000
600,000
400,000
200,000
0
Num
ber
of cu
sto
mers
TRE FRCC MRO NPCC RFC SERC SPP WECC Other
Potential peak reductionActual peak reduction
NERC region
Reported potential and actual 2010 peak load reductions. Courtesy of FERC.
• AMI Backhaul
• Substation Automation
• Demand Response
• Capacitor Bank Control Monitoring
• Fault Detection and Isolation
• Volt/VAR Optimization
• Distribution Automation
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demandResponse
The Gamble The big gamble is customer acceptance. Last year, the
industry witnessed pushback from residential customers in
California, Texas and Maryland on the replacement of old
mechanical meters with smart digital meters. Almost immedi-
ately, customers began reporting electric bills jumping double
digits, and many rumors surfaced about the utilities gathering
personal information on customers.
Nothing was wrong with the digital meters or the deploy-
ment, and there certainly was not a nefarious plan for the utili-
ties to be Big Brother. The problem was a failure to communi-
cate. Now utilities have begun outreach in the community to
educate customers about new technologies.
Game On for Developers The point has not been lost on savvy utilities. As a result,
many utilities are partnering with third-party DR providers.
These aggregators offer residential and small commercial
customers the same energy audits and smart building tech-
nologies that have long been available to large commercial
and industrial (C&I) customers. Smart building technologies
include such things as building management systems, lighting
control systems and direct load control (for example, thermo-
stats, pumps and HVAC).
They also provide DR/energy-efficiency software that
shows where customers can make easy cuts in usage and con-
trol smart building hardware automatically. The customers
make their choices concerning the levels of response they are
willing to live with and leave the rest up to their energy man-
agement partner.
The effect of this new approach has
blurred the lines separating all customer
segments. Where once only large custom-
ers buying megawatts realized energy sav-
ings and improved energy-efficiency strate-
gies, now all segments are taking advantage
of dynamic pricing.
Not Without the CustomerThe Federal Energy Regulatory Com-
mission (FERC) confirms this is the cor-
rect direction DR needs to go to realize its
full potential. FERC has published a series
of DR reports, such as “National Demand
Response Potential Model Guide,” “Nation-
al Assessment of Demand Response Poten-
tial” and, most recently, “Demand Response and Advanced
Metering.”
FERC estimates that DR programs, with full participation
across all segments of the customer base, have the potential
to reduce peak load by roughly 20% (188,000 MW) by 2019.
FERC points out that, for this degree of reduction to happen,
it requires the residential and small commercial customers to
take part. If utilities keep doing business as usual (large C&I
only), they will not be successful. The residential customer is
key to the success of realizing the full potential of DR.
The Electric Power Research Institute (EPRI) also con-
ducted a study titled “Assessment of Achievable Potential from
Energy Efficiency and Demand Response Programs in the
U.S.: 2010–2030,” which supports the FERC findings. The
EPRI report estimates the non-coincident regional peaks will
increase by about 39% by 2030.
Reported potential peak load reduction by region and customer class. Courtesy of FERC.
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
Rep
ort
ed
peak
load
red
uct
ion (M
W)
TRE FRCC MRO NPCC RFC SERC SPP WECC Other
Commercial and industrialResidentialWholesaleOther
NERC region
Customer-Oriented UtilitiesAustin Energy has long been a leader in innovative cus-
tomer-friendly programs. The utility has even developed con-
tests for its customers in its education effort. One of the most
successful has been its citywide Kill-A-Watt Challenge, where
FERC estimates that DR programs, with full participation across all segments of the customer base, have the potential to reduce peak load by roughly 20%
(188,000 MW) by 2019.
demandResponse
customers compete to see who can come
up with the biggest energy savings over
the peak summer months. Austin Energy
estimates its various programs saved more
than 700 MW between 1982 and 2007, and
it expects load reductions in 2011 to exceed
58 MW.
Working with Comverge, Austin Energy
offers residential customers a free Com-
verge programmable thermostat. This
Power Partner program includes both in-
stallation and warranty for the thermostat.
It is estimated customers save between 15%
and 20% on their electric bills, and Austin
Energy reduces its summer peak by roughly
45 MW.
Kansas City Power and Light (KCP&L)
has developed an Energy Optimizer pro-
gram, managed by Honeywell, that reduc-
es energy demand from air conditioning.
The customer is provided the Honeywell
UtilityPRO programmable thermostat.
More than 30,000 of the thermostats
were installed initially. Honeywell expects to have more than
50,000 installed in homes, apartments and small businesses
by the end of 2011. KCP&L estimates this will result in the
reduction of approximately 80 MW at peak energy use.
KCP&L also has given the customer more control over per-
sonal energy consumption by selecting Siemens for a smart
grid demonstration project. The project will include two-way
metering infrastructure to demonstrate time-of-use pricing
and state-of-the-art customer end-use tools. It also will in-
clude electric vehicle charging and management of rooftop
solar technology. KCP&L expects the Siemens technology to
reduce energy delivery costs, provide more efficient energy
consumption, improve its carbon footprint and enhance in-
formation flow.
Indianapolis Power and Light Co. (IPL) and Silver Spring
Networks have an agreement in place to develop IPL’s smart
energy project. Part of the Department of Energy (DOE)
smart grid investment grant, this project is designed to devel-
op energy efficiency, improve reliability and deploy advanced
meters to IPL’s customers.
A Social Networking UtilityBaltimore Gas and Electric (BGE) website visitors will see
links to Facebook, Twitter, Flickr and YouTube. BGE is using
the technology its customers are familiar with to educate and
keep them informed. BGE is customer friendly, so it not sur-
prising to see the utility team up with Tendril. Tendril is sup-
plying BGE with a platform for its smart energy pricing pilot
program. In return, BGE has provided Tendril a group of ad-
vanced metering infrastructure-enabled customers to inform
of pending DR events. The customers will be given direct feed-
back on how an event affects them, and they will receive re-
bates for voluntarily reducing their energy consumption.
Tampa Electric started developing DR programs in 2006.
The programs were successful and continue today. Early this
year, Tampa Electric extended its partnership with EnerNOC
for an additional five years. This will give the utility 40 MW of
firm dispatchable DR capacity.
PJM recently announced it will take part in a demonstra-
tion price-response demand project with Tendril and Utility
Integration Solutions. PJM says this project will test the end-
to-end integration of the near-real-time price of an automated
residential DR program in the home.
Through this program, PJM hopes to work with residen-
tial customers more closely. By controlling customers’ ther-
mostats one or two degrees throughout the day, PJM seeks to
Reported potential peak load reduction by type of program and by customer class. Courtesy
of FERC.
14,000
12,000
10,000
8,000
6,000
4,000
0,000
0
Rep
ort
ed
peak
load
red
uct
ion (M
W)
Inte
rruptib
le lo
ad
Commercial and industrialResidentialWholesaleOther retail
Incentive-basedDR programs
Time-basedprograms
Direct lo
ad co
ntro
l
Emer
gency
dem
and re
spon
se
Load
as a
capac
ity re
sour
ce
Deman
d bid
ding a
nd b
uy-b
ack
Non
-spinning
rese
rves
Spinning
rese
rves
Critica
l pea
k pric
ing
Real-
time
pricing
Syste
m p
eak r
espon
se tr
ansm
issio
n ta
riff
Critica
l pea
k pric
ing w
ith lo
ad co
ntro
l
Oth
er
Regul
atio
n
Tim
e of
use
Peak
tim
e re
bate
38 May 2012 | www.tdworld.com
demandResponse
lower overall demand and save customers money as a result.
Southern California Edison (SCE) has been a leader in DR
for years. Using an $11.4 million DOE grant, SCE and Hon-
eywell (Akuacom) are developing an OpenADR technology
system to automate the SCE critical peak program that will
include about 700 of SCE’s C&I customers.
In addition to that project, SCE has been working with En-
erNOC since 2008 on a 40-MW DR capacity project. SCE has
expanded this project to 110 MW of DR capacity, which will
take effect in 2012. By working directly with SCE’s customers,
EnerNOC offers customized DR technology to automate load
reductions and perform energy-efficiency audits of customer
facilities to reduce consumption.
Shifting Load Beats Dropping LoadSouthern California Public Power Authority (SCPPA)
points out that DR includes shifting load to non-peak hours
as well as load interruption. SCPPA signed an agreement with
Ice Energy, a provider of advanced energy-storage solutions,
for the first utility-scale distributed energy-storage project.
The 53-MW project will permanently reduce California’s peak
electric demand by shifting about 64 GWh of on-peak electri-
cal consumption to off-peak time using Ice Energy’s Ice Bear
technology.
Several years ago, Tennessee Valley Authority (TVA) award-
ed a contract to EnerNOC for a 160-MW DR program for C&I
and institutional customers to reduce their electric usage. It
has proven so successful that TVA awarded the second phase
of the contract to EnerNOC. Phase two will add 400 MW of DR
capacity for an additional 10-year period.
Pepco offered its Washington, D.C., customers a pilot pro-
gram with smart meter and enabling technology (program-
mable thermostats). The PowerCentsDC pilot was so successful
Pepco opened it up to all customers in the District of Columbia
in 2011. Customers who participated in the pilot were provid-
ed with information on electricity usage. They selected one of
three pricing plans: critical peak pricing, hourly pricing and
critical peak rebate. Pepco reports that more than 90% of all
participants saved money and peak loads were reduced.
Companies mentioned: Battelle Memorial Institute | www.battelle.org
Brattle Group | www.brattle.com
Comverge | www.comverge.com
Control4 | www.control4.com
DRAM | www.drsgcoalition.org
EnerNOC | www.enernoc.com
Electric Power Research Institute | www.epri.com
Federal Energy Regulatory Commission | www.ferc.gov
GlobalData | www.globaldata.com
Honeywell | www.honeywell.com
Ice Energy | www.ice-energy.com
SCPPA | www.scppa.org
Siemens | www.siemens.com
Silver Spring Networks | www.silverspringnet.com
Tendril | www.tendrilinc.com
UISOL | www.uisol.com
25,000
20,000
15,000
10,000
5,000
0
Po
tential
peak
load
red
uct
ion (M
W)
2006 survey2008 survey2010 survey
Customer class
Commercial and industrial
Residential OtherWholesale
Reported potential peak load reduction by customer class in 2006, 2008 and 2010. Courtesy
of FERC.
Targeting the Consumer
At this year’s DistribuTECH, companies
such as Comverge, Tendril, Silver Spring
Networks, Control4 and others displayed
DR products specifically for home energy-
management systems. These products were
designed to work as a customer portal or a
utility portal.
In fact, many included not only energy
monitoring but also analytics to compare
one homeowner’s energy consumption
with that of other homeowners in their
neighborhood. Through comparisons, the
system shows the homeowner what others
are doing and makes recommendations for
energy savings. This is made possible by
such technology as cloud-based computer
systems. They provide customers with a simple and inexpen-
sive interface including the customer’s smartphone. This is
possible because the computing power is in the cloud.
The Journey Has BegunThe technology of DR is real, it is being used and it is grow-
ing. In many jurisdictions, regulators are supporting dynamic
pricing and other innovative rates and tariffs needed for these
programs. Pioneering utilities in North America, Europe and
Asia are deploying load-controlling technologies and gaining
customer support as they go.
DR providers are energy managers for their clients inter-
facing with utilities, providing hundreds of megawatts of DR
capacity for system relief. The industry has a long way to go to
realize the 188,000 MW FERC identifies as the total DR poten-
tial, but all the surveys and studies show the industry is moving
in a positive direction.
Does this mean the winds of change are blowing? When it
comes to demand response, yes, they certainly are.
Utility Division, Valmont Industries, Inc.
Two Perimeter Park South, Suite 475 West
Birmingham, Alabama 35243
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GRIDPlanning
Super Grid Increases System StabilityThe 400-kV super grid interconnection of six Arabian countries is now fully operational.By Ahmed Ali Ebrahim, Gulf Cooperation Council Interconnection Authority
The Gulf Cooperation Council Interconnection Au-
thority has commissioned a 400-kV super grid that
connects the electrical power networks of the Arabian
Gulf Cooperation Council (GCC) countries of Bah-
rain, Kuwait, Qatar, Oman, United Arab Emirates (UAE) and
Saudi Arabia. This interconnection enables electrical energy
exchange and emergency support among these countries.
The 400-kV transmission system was constructed in three
phases:
● Phase I included the 400-kV interconnection connecting
the existing power systems of Bahrain, Saudi Arabia, Qatar
and Kuwait, including a high-voltage direct-current (HVDC)
back-to-back 1,200-MW installation between a 50-Hz, 400-kV
system and a 60-Hz, 380-kV system.
● Phase II included the internal interconnection among
the southern systems (UAE and Oman) to form the UAE na-
tional grid and the Oman northern grid.
● Phase III included two major projects, a double-circuit
400-kV transmission line from Salwa (Saudia Arabia) to a new
400-kV substation at Al-Silaa (UAE). The new substation con-
nects to UAE Transco’s Shwaihat Substation as well as existing
double- and single-circuit 220-kV transmission lines between
the Al Fuhah Substation (UAE) and Mhadha Substation
(Oman).
To control operations, the Gulf Cooperation Council In-
terconnection Authority (GCCIA) established a new intercon-
nector control center equipped with supervisory control and
data acquisition (SCADA) and energy management system
(EMS) facilities in Ghunan, Saudi Arabia.
Operational Studies In addition to conducting studies during the feasibility and
planning stages of phase I, the GCCIA commissioned opera-
tional studies during the fi nal construction stage of the GCC
interconnection, prior to commissioning the interconnecting
transmission lines. Undertaken by a consultant consortium
consisting of RTE, Tractebel Engineering and Elia, the plan-
ning and operational studies were GCCIA’s fi nal verifi cation
of safe energization, synchronization and stable operation re-
gimes for the interconnected power systems.
These studies provided recommendations for implementa-
tion on the interconnected systems. The study work entailed
various workshops, attended by GCCIA, the consultant con-
sortium and representatives from the operations team, as well
as visits to European control centers.
Operational Standards The implementation of such an interconnection high-
lights the need for new operational standards to ensure the
reliability of the interconnected systems is improved and
the frequency-control reserves are shared among the power
systems. This gives rise to a balancing reserve generation ca-
The geographical routes and layout of the GCC interconnection. The 650-MVA transformer at the 400-kV Al-Zour Substation.
41www.tdworld.com | May 2012
GRIDPlanning
pacity and the harmonization of policies
and practices.
The HVDC converter station ensures a
large power reserve is available in case of
a severe disturbance on either side of the
50-Hz and 60-Hz networks. Steady-state
analysis and dynamic studies were conduct-
ed to identify the limits of such joint inter-
connected operation, and to give guidance
to procedures and sequences that ensure
safe and stable operations.
Operating Reserves Operating reserves are crucial for reli-
able performance of the interconnection;
the sharing of spinning reserves was fore-
seen as the fi rst benefi t of the intercon-
nection. In addition, the support in case
of a severe generation failure is improved
by the mutual delivery of emergency reserves by the intercon-
nected power systems.
The control of the frequency usually mobilizes different
types of reserves, depending on availability and situation spe-
cifi cs. The size of the operational reserves is 664 MW, which
is what the loss of the biggest generating unit would be. The
acceptable transient frequency drop and the fi nal frequency
deviation agreed on for the interconnector were a maximum
deviation of 500 MHz and a fi nal deviation of 200 MHz.
Three different types of reserve responses were identi-
fi ed. The primary reserve aims to stabilize and halt any drop
in frequency. The secondary reserve aims to reconstitute the
volume of the primary reserve and restore the frequency to
its nominal value. The tertiary reserve is used for restoring
Ghunan Substation and the 400-kV transmission lines through the desert.
42 May 2012 | www.tdworld.com
gridPlanning
safe operating conditions, thus restoring enough secondary
reserve margins.
The time allowed for cost-efficient decisions must be de-
fined and agreed to by the interconnected power systems. The
composition of these reserves depends on their origin. Short-
term reserves, also called spinning reserves, include the power
margin between the present setpoint of the turbine and the
maximum output, or the limiter value. Secondary and tertiary
reserves may use contractual fast load shedding, power ex-
change agreements or additional unit commitment according
to availability and cost efficiency. Each interconnected power
system is responsible for complying with the common reserve
requirements while satisfying their technical and economical
objectives.
Converter Station The HVDC converter station was designed for two opera-
tional modes. The economic dispatch mode allows stable com-
mercial exchanges with no frequency control. The dynamic
reserve power sharing (DRPS) mode provides automatic fast
power transfer and mitigates generation deficiencies by mobi-
lizing DRPS between the 50-Hz and 60-Hz systems.
The activation of the DRPS mode is dependent primarily
on two criteria, namely, the rate at which the frequency chang-
es or the rate at which load is lost. These events are governed
by the load on the interconnector and the time or season at
which these events occur. Thus, the HVDC converter station
offers a significant capability of emergency reserve sharing be-
tween the 50-Hz and 60-Hz systems, thus contributing to the
stabilization of the systems after large disturbances.
Load Shedding
Harmonization of under-frequency load shedding (UFLS)
is concerned with the high imbalance in active power as a re-
sult of sudden loss of generation, leading to a drop in frequen-
cy. This frequency drop can be corrected by suitable automatic
load-shedding schemes. All member states had such schemes
A valve hall in one of three 600-MW GCCIA back-to-back HVDC converter stations.
Work on the 400-kV transmission line towers.
in place, but the interconnection of separate
power systems required a harmonization of the
existing UFLS schemes and the definition of
common rules to be followed by each member
state.
When different power systems are intercon-
nected, the solidarity principle automatically
becomes the rule: The load is shed not only in
the area where the imbalance occurs but also
in the interconnected systems. This harmoniza-
tion is required to minimize the shed load and
fairly share the contribution of each member
state.
Two rules were recommended for the UFLS
harmonization of the GCC system:
l The first UFLS threshold for the 50-Hz
side (Qatar, Bahrain and Kuwait) is 49.3 Hz.
l The first UFLS threshold of the 60-Hz
side (Saudi Arabia) is set to 59.2 Hz to keep a
similar frequency range for the primary frequency control on
both sides of the HVDC connections.
The distribution of the UFLS stages in the frequency range
and the load shedding amount per threshold should be har-
monized. A range similar to the Union for the Coordination
of Transmission of Electricity practices was recommended:
l No more than 200 MHz between two UFLS stages
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44 May 2012 | www.tdworld.com
gridPlanning
l Shedding a minimum of 5% of total load each 200-mHz
steps and a maximum of 10%
l Recommended global load shedding amount between
40% and 45% for each country. It is left to the discretion of
each country to exceed this global amount by activating ad-
ditional UFLS stages under 48.3 Hz (the frequency threshold
to disconnect the interconnections).
The shed load has to be evenly distributed geographically,
and the percentage of load per threshold should remain con-
stant as much as possible throughout the year (peak and light
load conditions).
Stability StudiesThe interconnected system of GCC is characterized by sev-
eral sections connected together by relatively long alternating-
current lines. This type of structure is likely to face problems
with inter-area oscillations. This is another class of power sys-
tem stability, namely, small-signal stability, which is concerned
with the ability of the system to remain stable following small
disturbances.
Extensive analysis was conducted to identify any such modes
of operation that would cause small-signal-stability problems.
Small-signal-stability analysis also allows the identification of
the different inter-area oscillation modes of the GCC inter-
connected system. In accordance with international practice,
a mode is judged to be critical if damping is lower than 5%.
Synchronization Among the three member states with 50-Hz synchronous
systems, Kuwait has the strongest network. Therefore, studies
showed the preferred scenario was to energize the intercon-
nector progressively from Al-Zour (Kuwait).
First, the systems of Kuwait and Qatar were interconnect-
ed and synchronized, and then Bahrain was interconnected
later. The studies highlighted that it is preferable to perform
the synchronization with conditions leading to limited volt-
age and frequency difference, and to the lowest impedance
between the two systems.
The voltage at the connection points is controlled by ad-
justing the transformer taps. For frequency difference, the
recommended setting of the synchro-coupling devices in
asynchronous mode was set at 200 MHz. This requires the
member states to maintain a frequency in a range of about
0.1 Hz around the nominal value. The GCCIA’s interconnec-
tor control center orchestrates synchronizing operations, as it
has a view of both system frequencies and, therefore, is able to
remotely trigger the synchro-coupling schemes.
The FutureDuring the first two years in operation, the GCC intercon-
nection contributed significantly to the continuity of power
flow to the power systems of the member states. Between July
2009 and the end of 2010, there were some 250 incidents of
sudden loss of generation units connected to the networks in
various member states, but because of the GCC interconnec-
tion, the systems managed to avoid supply interruptions. Also,
the need to program customer shutdowns has been avoided as
there have been no incidents of low frequency in the member
states since the GCC interconnection became operational.
The GCCIA aims to promote power trading to optimize the
use of fuel resources. To achieve even more power exchanges
and trade, the GCCIA is conducting interactive seminars and
workshops to establish common grounds among the GCC
power authorities.
Interconnection of the GCC grid to other grids such as
the Egypt, Jordan, Iraq, Lebanon, Syria and Turkey (EJILST)
grid or the Maghreb Arab grid will offer the opportunity to
export surplus power to other regions (for example, to export
surplus power from the GCC region during the winter period
when demand is low to Europe where winter power demand is
high). This market also would encourage energy interchange
during seasonal diversity with the peak demand during the
hot summer seasons in the GCC region being supplied by
regions where demand is low. Therefore, the development of
a regional market through the GCC grid can provide alter-
native solutions to exportation of power by energy wheeling
as an alternative to exporting energy through natural gas
or oil.
Ahmed Al-Ebrahim ([email protected]) has a BSEE
degree from the University of Texas, a MSEE degree from the
University of Strathclyde and a MBA from DePaul University.
Al-Ebrahim is director of systems operation and maintenance in
the Gulf Cooperation Council (GCC) Interconnection Authority,
and has more than 24 years experience in power systems and
infrastructure planning. He is a board member and technical
committee chairman for the GCC-CIGRÉ and has authored
some 20 papers in the field of electricity markets.
Companies mentioned:Elia | www.elia.be
GCCIA | www.gccia.com.sa
RTE | www.rte-france.com
Tractebel Engineering
www.tractebel-engineering-gdfsuez.com
Transco | www.transco.ae
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MOBILEDispatch
When the Lights Go Out Seattle City Light improves customer service with outage management.By Joyce Miceli and Tracye Cantrell, Seattle City Light
When asking line workers and dispatchers what
they do, they will say, with pride, “I keep the
lights on.” But outages are one of the biggest
challenges for any electric utility. However dif-
fi cult it may be to restore power, it is the critical part of busi-
ness utilities have attended to for years.
This is the work utilities generally do well. The task that can
be challenging is keeping customers informed about what is
going on during an outage, when they will have power again
and why their power was interrupted in the fi rst place. In the
information age, utilities are expected to have tools in place
to provide customers with this kind information in real time.
Seattle City Light, one of the largest municipal-owned utilities
in the United States, is doing just that.
The EventIn December 2006, Seattle City Light’s customers expe-
rienced one of the most devastating windstorms in decades.
The storm left approximately 180,000 customers without pow-
er, representing almost half of the utility’s service area, and
caused a tremendous amount of problems for the utility, in-
cluding 89 downed electric poles, 34 miles (55 km) of downed
wire, 65 downed feeders and 100 transformers that needed
to be replaced. The extensive damage challenged the utility’s
ability to restore power, and while most customers had their
lights back on within two days, some were without power for
more than a week.
With the help of 40 line crews and 10 tree crews, the util-
ity logged 58,000 hours over eight days for restoration opera-
tions. Internally, though, the utility struggled to keep up with
the copious volume of paper it had to sort through to make
informed decisions and provide better information to its cus-
tomers. The storm demonstrated Seattle City Light’s need to
modernize the tools and systems it used to respond to power
outages. Sometimes with disaster comes the opportunity for
improvement, and Seattle City Light saw an open window to
move into the future.
After the EventTo operate effi ciently and provide excellent customer ser-
vice, utilities must ensure customer service representatives,
dispatchers and technicians are in sync with one another at all
times. This was certainly one of the driving
factors in Seattle City Light’s decision to de-
ploy Oracle Utilities Network Management
System. The utility needed a highly scalable
and proven solution to connect its disparate
working parts.
In 2007, Seattle City Light reviewed its
internal response to the devastating wind-
storm it experienced several months earlier,
hired a consultant for an external review and
asked other utilities with extensive emer-
gency-response experience to provide peer
reviews. Through that process, Seattle City
Light received recommendations on how to
improve its storm-response planning and de-
velop procedures that, ultimately, would en-
able it to provide better customer service and
communication options to its customers.
Implementing the SystemIn June 2009, Seattle City Light began
working with a systems integrator (SI) on the
path forward for its outage management sys-Outage-restoration operations of which most customers are not aware.
Answers for infrastructure and cities.
Today, electricity customers demand the highest pos-
sible availability and a consistently high power quality
level. At the same time, voltage quality is influenced
by more and more factors. It is an advantage to iden-
tify weak spots and potential fault sources within a
distribution grid early in order to systematically elimi-
nate them.
Siemens has set a new standard with SICAM PQS: for
the first time ever, an integrated, intuitive software
solution makes possible the central evaluation and
archiving of all power quality data from the field
www.siemens.com/sicam
level – automated, complete, and vendor-indepen-
dent. This enables a quick and comprehensive over-
view of a distribution system‘s quality.
With SICAM PQS, you can keep an eye on all relevant
data, including fault records and all power quality
measurement data. It can also be easily expanded to
create a station control system for combined applica-
tions. Comprehensive fault record and power quality
analysis becomes easier than ever. Be sure to discover
the unique advantages of SICAM PQS.
A new dimension
Excellent fault record and power quality analysis with SICAM PQS
E5
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48 May 2012 | www.tdworld.com
mobileDispatch
tem (OMS) implementation, and through September the team
focused on requirement sessions involving dispatchers, crews,
and call center and communications staff to prepare them for
the changes coming down the pike with the new system. In
October of that same year, the utility moved forward with the
system design work, which also involved cross-functional user
teams. Concurrently, the utility’s IT group worked on design-
ing interfaces with its geographic information system (GIS)
and customer information system (CIS).
In February 2010, Seattle City Light and its SI began build-
ing out the system and completing development work; testing
followed in June and July. Then, just eight months later, in
October 2010, the utility began the initial stage of its operation-
al system by going live with the first phase of its project, which
included implementing core functionality of Oracle Utilities
Network Management System. This new functionality enabled
Seattle City Light to handle large storms and enhanced its
interactive voice-response system (IVR) so customers could
call and report outages as well as get an update on restoration
status.
Seattle City Light’s primary goal was to enhance its cus-
tomer service, specifically, restoration information during an
outage. In April 2011, the utility went fully live with its OMS
for approximately 100 call center users, 10 dispatchers and 80
Seattle City Light staff, expanding its capabilities to include
an automatic customer callback feature that alerts custom-
ers when their power has been restored. Now, if power is not
restored in a specific area, customers can alert the callback
system, which then produces an automatic trouble report
alerting Seattle City Light to respond. This callback feature
also has helped Seattle City Light improve detection of nested
outages — that is, a smaller outage within a larger outage —
thus reducing outage time and improving the efficiency of dis-
patching work crews.
Further, in the second phase of its project, Seattle City
Light launched a Web workspace that provides remote users
with access to operations maps and enables them to more ef-
fectively provide crew management support in specific service
territories. The Web client also includes functionality that pro-
vides remote users with access to outage data, and detailed
crew information and functions, allowing decentralized sup-
port during storms.
Through the system, Seattle City Light receives internal
automatic notifications in the event of an outage that include
information such as the number of customers affected by an
unplanned outage; number of major customers, such as indus-
Seattle City Light has improved the back-office and customer-facing aspects of outage restoration while the hard work out in the field continues.
The control center monitors a storm’s effect on the system and restoration progress while the information is integrated into the Network Management System.
© 2012 Thomas & Betts Corporation. All rights reserved. SEL is a trademark of Schweitzer Engineering Laboratories.
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50 May 2012 | www.tdworld.com
mobileDispatch
trial sites, affected by an unplanned
outage; specific customers affected
by an unplanned outage; outage-
restoration notifications for specific
customers; and frequency of outages
on a specific device.
Brighter Skies Ahead The Oracle-based software uses
customer calls and information
it gathers from monitors on large
feeder-line breakers to identify out-
ages. As dispatchers assign crews, and
repair crews identify the cause of an
outage and make repairs, they are
able to share that information with
everyone else using the system. Addi-
tionally, customers can check outage
information anytime using a map on
Seattle City Light’s website. The utility
updates the information on the map
every 15 minutes.
For storm management, Seattle
City Light can now calculate estimat-
ed times of restoration based on his-
torical restoration data (for example, A screen capture of information from the Network Management System.
52 May 2012 | www.tdworld.com
MOBILEDispatch
outage type and location) and available and planned crews.
The utility also can perform storm optimization what-if stud-
ies to improve crew staffi ng requirement estimates and opti-
mize mutual-aid strategies between utilities.
The system includes several additional
features:
● Integration with existing data from its
CIS, GIS, supervisory control and data ac-
quisition (SCADA) system, and IVR system
into a centralized, real-time database. This
guarantees the integrity of the data from
the disparate systems in use at Seattle City
Light and ensures the utility can see near-
real-time concurrent data across the organi-
zation. In the future, Seattle City Light also
hopes to integrate advanced metering infra-
structure data.
● The ability to access information — in-
cluding manually entered crew location data
— in real time, which enables Seattle City
Light to quickly direct workers to an outage
site in case of an emergency, increasing crew
safety and effi ciency. Seattle City Light also
can access automatically updated informa-
tion by graphical maps and tabular lists.
Seattle City Light is on the road to con-
tinued customer satisfaction improvements as it uses the new
system. The utility’s intent is to provide better outage infor-
mation, improve media relations by providing more accurate
data, enhance storm decision support (for example, what-if
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GIS integration of system information allows pinpointing likely outage locations for restora-tion action.
53www.tdworld.com | May 2012
mobileDispatch
studies), improve executive management awareness of storm-
restoration status and processes, and decrease costs associated
with storm restoration.
Lessons Learned Although Seattle City Light is still in the process of evaluat-
ing the product and its impact on the business, it is able to of-
fer some lessons learned about the implementation process:
l Ensure key dispatching personnel (system control center)
are part of the implementation team
l Secure guidance from others who are using this system
l Work with GIS data early; get data correction as complete
as possible before implementation
l Create a strong cross-functional team to participate in
the design sessions for the system
Seattle City Light has gained several tools through this
implementation:
l A real-time distribution network operations model from
the substations down to the customer with outage and restora-
tion information that can be shared throughout the utility
l The ability to share information with the public, so cus-
tomers can be better informed about outages
l A tool for the utility to plan for resources during a storm
l A platform for personnel throughout the utility to see res-
toration progress as well as the network operational state (for
example, distribution circuit state).
A Lasting InvestmentToday, with increasing pressure on utilities to improve their
outage-response capabilities, it has become clear improved
technologies can assist utilities in meeting customers’ needs
for information during outages. When working to reduce out-
age times, it pays to employ a solution that can help streamline
crew management, safeguard workers and the public, enhance
customer service and monitor system status. Seattle City Light
looks forward to experiencing the benefits of this new invest-
ment in technology in the years to come.
Joyce Miceli ([email protected]) works with the cus-
tomer care division at Seattle City Light. She has worked with
managing customer installations and projects, and is currently
working with business process redesign projects. Miceli served
as the business functional lead for the OMS project.
Tracye Cantrell ([email protected]) served as project
manager for the OMS project. She manages new application
development within the information technology division at
Seattle City Light.
Company mentioned:Oracle | www.oracle.com
Seattle City Light | www.seattle.gov/light
54 May 2012 | www.tdworld.com
UNDERGROUNDFacilities
Cable Condition Revealed Field cable assessments at RWE Rhein-Ruhr Netzservice prove to be technically viable and economically valuable.By Andreas Borlinghaus, RWE Rhein-Ruhr Netzservice GmbH
RWE Rhein-Ruhr Netzservice GmbH has a compe-
tence centre for cable testing and measurement tech-
nology at Bad Kreuznach with more than 20 years
of cable diagnostic testing experience on low- and
medium-voltage cables. The southern network region deploys
fi ve cable test vans that carry equipment for cable and sheath
testing, for tan delta (tan δ) diagnostics and partial-discharge
measurement. The equipment for fault location is also in-
stalled in the vehicles ready for use when required. Therefore,
the teams have the facilities to test new and old cable systems
for operational safety, reliability and condition assessment.
These cable test vans are primarily used for diagnostic testing
on plastic-insulated cables (XLPE) because of their wide-scale
use, but these procedures also can be used on paper-insulated
mass-impregnated cables.
There is a signifi cant difference between diagnostic pro-
cedures and test procedures. Cable and sheath testing yield
a pass or fail result for operational reliability and safety. Di-
agnostic procedures provide an insight into the condition of
cable and reveal weak points, which may lead to future fail-
ures. Therefore, there is a distinction between local and global
diagnostics.
One of the key objectives of cable diagnostics is the opti-
mization of maintenance costs. Medium-voltage cable systems
and other operating equipment can be expected to experi-
ence age-related failures. Hence, it is important to take coun-
termeasures. Driven by the German regulatory authorities,
RWE must ensure the actions implemented are cost-effective
and the network retains maximum availability.
Assessment Procedures
The assessment of cable systems helps to identify the most
appropriate maintenance practices for the network. However,
cable evaluation and steps for condition-based maintenance
are not based solely on current measurement values. Other
factors are a part of the assessment. The required supply se-
curity of the cable network is a key factor. Another factor is
basic data on the cable: manufacturer, type, installation date,
insulation material or joint type, number of defects and fault
history form. All this information is stored in a database for
archiving and analysis. This enables a systematic evaluation of
the cable condition based on various weighted factors, allow-
ing the best possible use of the maintenance budget.
The normal AC cable testing using several times the rated
voltage prior to commissioning (e.g., testing of XLPE cables
with three times rated voltage for over an hour), recommend-
ed by the German Association for Electrical, Electronic &
Information Technologies [VDE]), only confi rms that the
cable can withstand the test voltage. It is no indication of the
aging process, and on older cables, there is the risk of cable
damage caused by high test voltage stress. Therefore, for evalu-
ating older cables, alternative tests that do not stress the cable
are preferable. Depending on the objective, the main options
are sheath testing, tan δ measurement and partial-discharge
measurement.
DC sheath testing enables the
safety of the cables to be checked and
problems detected. These may include
damage during cable installation or
water penetration, which impairs the
insulation’s effectiveness and poses
a safety hazard for the public. In the
event of sheath damage, the position
can be pinpointed by sheath fault lo-
cation techniques to enable repair.
With older cables, it is common
practice to check for damage caused
by water trees. This requires tan δ
measurement, also known as dissipa-
Cable plug Uniformly aged cable line
Cable connection set Weak point fault
Cable sealing end
Test procedure Diagnostic procedure
Voltage test Local Global
● DC● AC 50 Hz● AC 0.1 Hz
● Partial discharge● Measurement● Partial-discharge location
● RVM● IRC● tan δ ( )
Cable system test and diagnostic procedures vary with location.
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56 May 2012 | www.tdworld.com
undergroundFacilities
tion factor measurement. The method determines the dielec-
tric dissipation factor: the ratio of real to reactive power of a
cable section. It is an integrated or “global” method, a deter-
mination of “average aging” for the complete cable circuit.
The tan δ of an undamaged XLPE cable is initially rela-
tively high, but the value decreases with time as the cable out-
gasses. Later, the value increases depending on the frequency
and size of water trees.
The measured value of tan δ depends on the measurement
voltage. New, intact XLPE cables have a low value, which is not
significantly higher at twice-rated voltage than at full- or half-
The true sinusoidal voltage sources of testing vans produce an error-free, load-independent voltage that can be used for tan δ and partial-discharge measurement. Courtesy of BAUR.
XLPe Cable Classification Based on rWe rhein-ruhr netzservice experience
Tan δ for measurements at 0.1 Hz Classification of XLPE cables
tan δ2Uo
< 1.2 x 10-3 andtan δ
2Uo – tan δ
1Uo < 0.6 x 10-3
Still safe for operation
tan δ2Uo
≥ 1.2 x 10-3 andtan δ
2Uo < 2.2 x 10-3 and
tan δ2Uo
– tan δ1Uo
≥ 0.6 x 10-3
Partially damaged
tan δ2Uo
≥ 2.2 x 10-3 andtan δ
2Uo – tan δ
1Uo > 1.0 x 10-3
No longer safe for operation
Note: Uo = rated voltage
The cable test service van has measurement technology as well as mobile equipment for fault location and other tasks. Courtesy of BAUR.
examples of diagnostic TestingDiagnostic measurement was necessary in a system following a transient ground fault. Cable testing of the circuit confirmed
the system would have been certified as “good.” However, partial-discharge measurement revealed the cause of the transient
ground fault: a defective joint that was replaced, eliminating the risk of future failures.
A further example of the value of diagnostic measurement is more apparent when, on a cable almost 2 km (1.24 miles) long
between two distribution substations, water trees were expected because of repeated disruptions. However, replacement of the
complete cable had to be avoided for cost reasons. Measurement of the tan δ revealed only one phase was severely damaged.
Partial discharge was found on sections of the cable when corresponding measurements were made, so cable replacement was
limited to two 300-m (984-ft) sections.
To check the success of these actions after the cable was replaced, dissipation factor measurements were performed in
addition to cable testing. This confirmed the condition of the cable system as being healthy. Identifying the location of the fault
reduced by one-third the cost of laying replacement cable, resulting in a cost saving of 130,000 euros (US$186,000).
The costs of diagnostic measurement are negligible as the time taken to complete a dissipation factor and partial-discharge
measurement is about an hour. Thus, the cost of diagnostic measurement is covered when the replacement of a few meters of
cable is avoided.
rated voltage. Aged cables already show a somewhat higher
value at half-rated voltage and signi�cantly higher values at
full- or twice-rated voltage. Thus, reliable classi�cation can
be performed based on the measured values at various test
voltages.
Recommendations and comments are added to the tan δ
measurement logs by �eld technicians according to the limit
values. These are available in the cable database for other
teams and for future measurements. These recommenda-
tions include, for example, repeating the diagnostic testing on
partially damaged cables at shorter intervals (after two years,
57www.tdworld.com | May 2012
undergroundFacilities
for example). Repeated measurements like this reveal aging
trends.
At a frequency of 0.1 Hz, tan δ is particularly informative
because the values are better differentiated than at the net-
work frequency of 50 Hz or 60 Hz. For very high reproduc-
ibility and comparability of the results, it is necessary that the
measuring voltage is symmetric and not be influenced by the
connected load and length of cable. RWE Rhein-Ruhr Netz-
service depends on the generator from BAUR that provides a
“true sinusoidal voltage,” which ensures the measured results
are reproducible.
A further advantage of very low fre-
quency (VLF) measurement (0.1 Hz) is
that the voltage sources are smaller than
comparable devices for operating fre-
quency. The VLF voltage generator also
allows conventional cable testing, tan
δ measurement and partial-discharge
measurement to be performed.
Partial-Discharge MeasurementPartial-discharge measurement in-
creases the reliability of assessment for
XLPE-insulated cables and is also used
for insulation diagnostics for paper-
insulated cables. XLPE cables and other
insulated cables are also subjected to
partial-discharge measurement follow-
ing indicative results of a problem dur-
ing tan δ measurement.
Partial-discharge measurement lo-
cates and identifies the places with a
greater occurrence of electrical trees
that can develop from water trees. It is
often revealed that only one phase or
only a part of the cable has weak points,
so targeted repair measures can be cost-
effectively undertaken.
For partial-discharge measurement
following tan δ measurement, the use of
a VLF true sinusoidal voltage source is
advantageous, because measurements at
0.1 Hz alternating current lead to faster,
directed growth of water trees compared
to other voltage waveforms or frequen-
cies. These then develop into electrical
trees at which partial discharge occurs,
which often sparks within a few minutes.
A high rate of detection is achieved with
short measurement times.
With “healthy” XLPE cables, partial-
discharge measurement typically yields
no results as partial discharges occur
primarily at joints and terminations.
These are then an indication of defects
or installation errors.
Diagnostic Procedure Effectiveness In addition to other applications, tan δ measurement can
be used to check the integrity of a reconstruction or repair. For
example, XLPE cables with water trees in the insulation where
electrical trees have not yet formed often can be repaired by
silicone treatment that displaces the water trees. It is not good
practice to determine the dissipation factor immediately after
a repair as the new silicone can give false (high) results for tan
δ. But after a few years, the silicone is fully cured and is chemi-
cally and electrically stable. A repeated measurement then
reveals whether the cable can be classified as noncritical.
58 May 2012 | www.tdworld.com
undergroundFacilities
Diagnostics Value
Diagnostic measurements have proved to
be technically and economically valuable for
the maintenance of existing and new under-
ground cable networks. Depending on the
application, tan δ measurement and/or par-
tial-discharge measurement are used. Over-
all cost savings are achieved, despite investments in the test
equipment and the time required for measurements and their
associated switching operations. Diagnostics provide informa-
tion on older cables that enable targeted, cost-effective mainte-
nance of the network based on the probability of cable failure.
Therefore, the resources available for network maintenance
can be used in a manner that maintains or even improves the
quality and reliability of the network within budgets.
For new XLPE-insulated cables, partial-discharge measure-
ment proves an effective instrument for detecting and correct-
ing installation errors before an in-commission circuit failure.
Diagnostic procedures have enabled the south region of RWE
Rhein-Ruhr Netzservice for the past 15 years to reduce the
number of cable faults attributable to water trees in XLPE-
insulated cables.
Moreover, recent random partial-discharge measurements
on newly installed cables have raised quality awareness on this
procedure and with the service providers, resulting in a reduc-
tion in the number of faulty installations.
Andreas Borlinghaus ([email protected]) has
been involved with maintaining the medium-voltage facilities
at RWE Rhein-Ruhr Netzservice GmbH since 1980. Since 1986,
he has managed the testing and measurement team for low
and medium voltage for electrical special service in the south
region. The facility in Bad Kreuznach also has assumed the
role of a competence centre for cable testing and measure-
ment technology within RWE Rhein-Ruhr Netzservice GmbH.
Borlinghaus is head of the competence centre for cable testing
and measurement technology, and he and his team have used
VLF cable diagnostics successfully for 10 years.
Installation Diagnostics
Diagnostic procedures prove useful for aging cables and
also for newly installed cables. RWE Rhein-Ruhr Netzservice
supplements AC cable testing and DC sheath testing with di-
agnostic procedures because installation errors can only be
detected by partial-discharge measurement. This enables war-
ranty claims to be made in a timely manner and defects that
could lead in-service failures to be corrected before operation-
al usage begins.
For example, in an urban area in 2010, two 2-km (1.24-
mile) sections of paper-insulated mass-impregnated cable laid
parallel in steel pipes were replaced by XLPE-insulated cables.
Both cables were subjected to cable and sheath testing fol-
lowed by partial-discharge measurements to check the quality
of the installed joints, which were spaced at intervals of about
300 m (984 ft).
The first XLPE-insulted cable tested was without prob-
lems, but the second cable laid by the same installation team
two weeks later showed conspicuous partial discharge at many
joints. Joint problems were suspected. But, as the cold-shrunk
joints have a higher contact pressure after a few days, the
measurement was repeated eight days later. Comparison of
the values indicated that the joints were indeed incorrectly
installed, a situation that would not have been found by cable
and sheath testing.
The cold-shrunk joints on the second cable were installed
without preheating when the outdoor temperature was -5°C
(23°F). Before installation, the joints should have been heated
for a long period or installed in a heated environment (such
as a tent). Therefore, the service provider had to remake the
joints by heating to about 60°C (140°F) for two hours. Subse-
quent partial-discharge measurement showed the cable to be
free of faults. In this example, the additional diagnostic mea-
surement avoided the consequential damages likely to occur
after the end of the warranty period. The costs of correcting
the problems were borne by the service provider.
Examples of joint defects found with local diagnostic procedures and fault location.
Companies mentioned:BAUR | www.baur.at
RWE | www.rwe.com
Water trees (made visible here in an XLPE cable with coloring) usually cannot be seen with the naked eye and are not detected by cable test-ing. The tan δ method enables aging of insulation due to water trees to be determined. Courtesy of
BAUR.
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60 May 2012 | www.tdworld.com
distributionManagement
Dashboards Turn Data Into InformationUnion Power turns a surfeit of data into valuable information displayed to satisfy stakeholder needs.By todd Harrington and david Gross, Union Power Cooperative
After conducting a full GPS inventory of its distribu-
tion system in 2008, Union Power Cooperative im-
plemented an advanced metering infrastructure
(AMI) system in 2010. However, the utility realized
it did not have a good way to sift through millions of records
and tie the information together to make sense of it all.
Early DifficultiesAs data started to be delivered from the AMI, the geograph-
ic information system (GIS) administrator and the engineer-
ing and operations (E&O) support manager had their own
separate problems. These problems converged. One problem
was data manipulation. When E&O queried the AMI system,
obtaining a �le that contained momentary interruptions for
the day, the �le had to be delivered to GIS for manipulation so
the data could be displayed on a map. This was the process ev-
ery time an engineer wanted to see momentary interruptions,
or high and low voltage, and how they related to the distribu-
tion system.
A second problem was trying to display many of the results
in a GIS map. Three different viewers, which required soft-
ware to be installed and the data to be kept up to date on each
machine, were being juggled. E&O was trying to display the
AMI data in SharePoint, but it was not working out well. The
goal was to have one easy-to-use application to con�gure and
tie all this information together.
First StepsIn 2011, GIS and E&O were reorganized into the same
group, and there was some experimenting with Esri’s ArcGIS
Viewer for Flex. The group was impressed by the speed of the
application and its ease of use. Brainstorming ensued about
the possible functionality that could be implemented.
However, the problem with the data manipulation still
Dispatch staff use the dashboard during an outage to view real-time data.
61www.tdworld.com | May 2012
distributionManagement
existed. But a tool from Geospatial Extensions allowed
automation of the process allowing insertion of the data
into the GIS database without having to do any program-
ming. Now when the engineers get to work, they have
access to the momentary interruptions that occurred in
the past 24 hours. This solution freed all involved sub-
stantially, thus saving time and money.
Six-Step ProcessThe process of converting momentary interruptions
from a tabular format to be represented in a geospatial
view involved several steps:
1. Brainstorm an idea
2. Identify what tables and fields were needed
3. Create SQL views
4. Configure the Geospatial Extensions tool
5. Publish the Esri map service
6. Configure the dashboard configuration file.
The idea was to have any meter that had a momentary in-
terruption on the system in the past 24 hours displayed on the
dashboard. Union Power discovered a job could be scheduled
to run every day and the data stored in a database table.
Once the data was in the SQL Server, queries were written
to calculate the delta of the momentary interruption count.
The meter number was then joined with the consumer layer
from GIS so the query contained the latitude and longitude.
The next step was to configure the Geospatial Extensions
tool to insert the data into an Esri database. The tool could be
configured to run on any schedule. When it is run, the tool
compares the records in the view to the records in the GIS
layer and either inserts or deletes records.
Once the data was in a GIS format, the file could then be
placed in a map document and configured. Once a document
is created, it can be published as an Esri map service. This
allows other Esri technology to
consume the map service. When a
map service is created, it produces
a representational state transfer
(REST) endpoint.
The last step was to config-
ure the Esri dashboard template,
which consists of copying and
pasting the REST endpoint that
was created from the map service.
This tells the dashboard to display
a particular map service when a
layer is turned on. Since the con-
figuration file is in HTML, Union
Power found it easy to set up and
maintain.
This same process was used for
every feature in the dashboard.
More AdditionsAfter adding the electric distri-
bution system to the dashboard,
the next item of work was adding failed reads, work orders,
and high and low voltage to the dashboard. The engineers
started checking the dashboard every morning and used this
information to make better-informed decisions about the sys-
tem. During the first week of having the high and low voltage
on the dashboard, the system engineer submitted work orders
to have several overhead transformers changed out as damage
was indicated. Union Power was able to address several power-
quality issues prior to any member complaints.
The dashboard spread companywide, with every depart-
ment using it. Requests started coming in from users for more
and more features. When the non-GIS people start submitting
ideas for expanded features making use of GIS information, it
was more than a hint the dashboard was something special.
OMS InformationOne of the next items added to the dashboard was live
On an iPad, a crew leader views a live outage on the same map service used in the dashboard.
The outage tab provides a summary of what and who is currently out of power.
62 May 2012 | www.tdworld.com
distributionManagement
outages and who was predicted out of power. The dashboard
pulls this information from the outage management system
and displays it along with other information about the outage.
Anyone in the utility can see the outage location and who is
affected, all in one easy application.
Since outages were already in the dashboard, SQL queries
were used to pull in the historical outages for the last 24 hours,
seven days, 30 days, month to date and year to date. Now when
someone inquires about historical outages, that information
can be easily and accurately provided.
Displaying possible meter tampering
on the dashboard has been a huge hit.
This feature existed in some vendor soft-
ware but had to be manually run each
day. A method to pull the information
from the AMI system each day was de-
vised, and it is compared to the customer
information system (CIS). Then someone
is notified by e-mail along with the dash-
board displaying data. In the first week of
release, approximately US$3,000 was re-
covered using the meter-tampering tool.
It is an understatement to say the meter-
tampering tool has been successful and
beneficial.
Some other features that have been
tied into the dashboard are right-of-way
maintenance, automatic vehicle location,
non-pay cutoffs, key accounts, and the
ability to add and delete notes.
Further Outage InformationUp to this point, Union Power has
spent little on the dashboard. The GIS tech-
nology was already in place, and the only
investment was on the Geospatial Exten-
sions tool, which was around the cost of a
new desktop. Staff who prepared the dash-
boards were not really programmers, so a
lot of time was spent getting familiar with
the configuration files of the dashboard
and SQL queries. It was just a couple of
co-op guys who, through a little hard work
and determination, produced something
unique that enables Union Power to make
dashboard changes at practically no cost.
Stepping back and evaluating the cur-
rent state of the dashboard has provided
some other ideas that would have required
programming expertise. Union Power
worked with Esri professional services to
add some customized features to the dash-
board.
One added feature was the ability to see
outage information at a higher level and
sorted in several different manners, includ-
ing number of members out of power, outages by county, out-
ages by district and number of key accounts out of power by
category.
Having this information available to all staff allows them
to access this information in real time instead of having to go
into the dispatch center where tensions are high during large
outages.
A second feature added was the ability for engineers to see
the current reliability index in real time. The engineers can
keep track of the current values of the system average inter-
A graph of momentary interruptions within the last 24 hours as well as the interruptions within the last 10 days.
The meter displays a high-voltage reading and the last 10-day voltage readings.
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64 May 2012 | www.tdworld.com
distributionManagement
each index. Each index is configured to
display by month, year to date, the past 30
days and the past seven days.
The third feature added was the ability
to graph the momentary interruption and
voltage data for the past 10 days. When a
user clicks a point, the pop-up window has
a button available to display the graph.
The momentary interruption data was
configured to show the data in a column
graph, and the voltage data was config-
ured to display the results in a line graph.
This provides a quick look at the historical
data for that particular meter without hav-
ing to access a different system.
Next StepsThe dashboard is not only used inside
the office, but it also can be accessed from
home with a user name and password.
Union Power has even taken the dash-
board and put it in a mobile environment.
Currently, seven users have the dashboard
in their vehicles through a wireless connection on a laptop.
The results have been positive.
Realizing the value of the dashboards has led to consid-
ering their use on mobile devices such
as iPads and Android tablets. Linemen
are currently testing these devices and a
decision will be made on which solution
will best suit the needs of Union Power
Cooperative.
Todd Harrington (todd.harrington@
union-power.com) is the GIS administra-
tor at Union Power Cooperative, which he
joined in 2007. He has more than 11 years
of experience in GIS and databases, rang-
ing from law enforcement to real estate.
He graduated from the University of North
Carolina at Charlotte with a bachelor’s
degree in geography.
David Gross (david.gross@union-power.
com) has worked with electric coopera-
tives either directly or through consulting
since 1994 and has been with Union Power
since 2008. He holds a BSEE degree from
North Carolina State University and is a
professional engineer in North Carolina.
ruption duration index (SAIDI), system average interruption
frequency index (SAIFI) and customer average interruption
duration index (CAIDI) compared to the annual goals for
The reliability index has the ability to show monthly, year to date, the past 30 days and the past seven days for each index.
Companies mentioned:Esri | www.esri.com
Geospatial Extensions
www.geoext.com
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3Transmission & Distribution World l May 2012
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Copyright 2012 Penton Media Inc. All rights reserved.
I Love It When a Plan Comes TogetherBy Paul Mauldin, Senior Editor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4
Smart Grid Communications: The Right Platform at the Right TimeBy John Egan, Egan Energy Communications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6
Adopting & Adapting: A Communications Strategy for the Smart GridBy Lee Harrison, Contributing Writer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Smart Utilities: Can the Smart Grid Market Explode Without Full Interoperability?By Lee Harrison, Contributing Writer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16
New Demands, New Technologies, New Partnership
By John R. Janowiak, International Engineering Consortium . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Table of Contents
Alcatel-Lucent . . . . . . . . . . . . . . . . . . . . 24
www.alcatel-lucent.com
Black & Veatch . . . . . . . . . . . . . . . . . . . 14
www.bv.com
CG Power Systems. . . . . . . . . . . . . . . . . 13
www.cgglobal.us
Cisco Systems Inc.. . . . . . . . . . . . . . . . . 21
www.cisco.com
Inmarsat. . . . . . . . . . . . . . . . . . . . . . . . . . 5
www.inmarsat.com
Itron . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
www.itron.com
S&C Electric Co.. . . . . . . . . . . . . . . . . . . . 2
www.sandc.com
Advertiser Index
Interoperable communications for a faster Smart Grid transition.
Interoperable. Scalable. Reliable.
Visit us at sandc.com/future-comm or
contact us at [email protected]
Transitioning to a Smart Grid can be daunting — not with S&C.
With an unbiased consultative approach, our communications
experts can help you assess which technologies will work best to
support your near-term needs while keeping the longer-view of a
holistic network architecture that can support future grid demands.
At S&C, we offer best-in-class solutions that have been engineered
to the highest standards of reliability, longevity, interoperability,
and performance. Regardless of your infrastructure or data-rate
requirements, S&C can integrate advanced, self-healing
communication technologies that can be quickly deployed at any
stage of your Smart Grid transition.
We are your consultative integrator of communication solutions.
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4 May 2012 l Transmission & Distribution World
I Love It When a Plan Comes Together
The editors of are proud to
bring you an in-depth view of how our
utility industry is building out enter-
prisewide telecommunications platforms to
support and enable smart grid. Smart grid
is being developed along the same S-curve
that most technology evolutions follow:
start slow, build interest, accelerate invest-
ment, increase number of participants, in-
crease speed of innovation and then begin
to fl atten out and mature. But we couldn’t
have foreseen all the twists and turns.
A Time for Straight TalkSome utilities had seen smart grid primarily as an oppor-
tunity to build up the rate base, while telling their customers
how much smart grid and smart meters would benefi t their
lives. But customers in several states dug into the issue and
found they wouldn’t benefi t much but would experience in-
creased rates. Some even feared health risks from the meter
electromagnetic radiation. Potential risk, higher costs and
foggy benefi ts — what’s the customer to like?
Fortunately, there is a rest of the story. Some utilities de-
cided to take a second approach and build out a business plan
to meet customers’ needs and, in the process, discovered
that an enhanced and well thought out smart grid would be
essential.
Take Oklahoma Gas and Electric (OG&E). Rick Bush,
’s editorial director, was so impressed with what
was going at this utility that he visited twice to make sure he
really grasped what it was achieving.
OG&E was denied a rate increase to build a coal-fi red
plant, but the state defi nitely needed more electric supply. So
OG&E worked with regulators to fi nd a way to fund load-
shifting solutions that would meet increased demand with the
same ability to control that would have existed on new gen-
eration. It is now building out the smart grid and communica-
tions platform to meet a legitimate need and at a legitimate
price.
So, let’s be honest up-front and build what the customers
need, want and are willing to pay for. In the long run, they
will appreciate the honesty.
Telecom ConsolidationA year ago, smart grid telecom discussions seemed to be
all about technology winners. WiMax, cellular, radio, satellite
— lots of technologies, lots of small providers and a few large
(but not as vocal) ones. Within the utility industry there was
general agreement that for many utilities, no one technology
would meet the needs of the entire service area. However, we
found in our earlier interviews that many of
the telecoms were pitching one-size-fi ts-all
solutions — a pitch that utilities rightfully
pronounced naïve.
The picture has now shifted. At a recent
utility industry trade show, there seemed to
be less participation by the smaller telecom
providers. But the ones that were there were
sharp, focused and had their value proposi-
tions well laid out.
Telecoms are now looking to be seen as
solution providers rather than just telecom
technology suppliers. All the buzzwords
— open systems, interoperability, standards-based — are
there to try and assure the potential buyer that the risks of
stranded assets and obsolescence are minimal. Some are go-
ing after the “middleware” and network management market
— choose your technology and they’ll make it work.
The really big companies, such as Alcatel-Lucent and
Schneider, are branding themselves as total solution provid-
ers — meters, communications, customer management to
back-offi ce, soup to nuts. The appeal here is proven compe-
tence and low risk. That has appeal to many beleaguered util-
ity decision makers.
Smoother Utility-Telecom PartnershipsAs some loose utility-telecom partnerships began to form,
it seemed that telecoms in general didn’t give enough credit
to the utility industry’s telecom sophistication.
Those of us in the industry know utilities have been heav-
ily involved in telecom for years. Even before smart grid was
a gleam in anyone’s eye, utilities were managing massive
amounts of data communications, usually on proprietary net-
works, and doing it well.
Utilities perceived telecoms as being naïve regarding the
needs of power companies, and the communications compa-
nies underestimated the utilities’ telecom technology sophis-
tication. No wonder the courtship got off to a rocky start.
Now, however, both sides are meeting in the middle and
are forming long-term relationships.
Nothing Succeeds Like SuccessThe good news is that smart grid communications enabled
telecom investments are already paying off for millions of
customers. PEPCO customers are seeing a 50% increase in
reliability. PECO greatly improved storm outage restoration
as did Alabama Power. These and other success stories result
from strategically integrating distribution automation, out-
age management and other existing operational systems with
new smart grid telecom networks.
www.tdworld.com
4 May 2012 l Transmission & Distribution World
I Love It When a Plan Comes Together
The editors of are proud to
bring you an in-depth view of how our
utility industry is building out enter-
prisewide telecommunications platforms to
support and enable smart grid. Smart grid
is being developed along the same S-curve
that most technology evolutions follow:
start slow, build interest, accelerate invest-
ment, increase number of participants, in-
crease speed of innovation and then begin
to fl atten out and mature. But we couldn’t
have foreseen all the twists and turns.
A Time for Straight TalkSome utilities had seen smart grid primarily as an oppor-
tunity to build up the rate base, while telling their customers
how much smart grid and smart meters would benefi t their
lives. But customers in several states dug into the issue and
found they wouldn’t benefi t much but would experience in-
creased rates. Some even feared health risks from the meter
electromagnetic radiation. Potential risk, higher costs and
foggy benefi ts — what’s the customer to like?
Fortunately, there is a rest of the story. Some utilities de-
cided to take a second approach and build out a business plan
to meet customers’ needs and, in the process, discovered
that an enhanced and well thought out smart grid would be
essential.
Take Oklahoma Gas and Electric (OG&E). Rick Bush,
’s editorial director, was so impressed with what
was going at this utility that he visited twice to make sure he
really grasped what it was achieving.
OG&E was denied a rate increase to build a coal-fi red
plant, but the state defi nitely needed more electric supply. So
OG&E worked with regulators to fi nd a way to fund load-
shifting solutions that would meet increased demand with the
same ability to control that would have existed on new gen-
eration. It is now building out the smart grid and communica-
tions platform to meet a legitimate need and at a legitimate
price.
So, let’s be honest up-front and build what the customers
need, want and are willing to pay for. In the long run, they
will appreciate the honesty.
Telecom ConsolidationA year ago, smart grid telecom discussions seemed to be
all about technology winners. WiMax, cellular, radio, satellite
— lots of technologies, lots of small providers and a few large
(but not as vocal) ones. Within the utility industry there was
general agreement that for many utilities, no one technology
would meet the needs of the entire service area. However, we
found in our earlier interviews that many of
the telecoms were pitching one-size-fi ts-all
solutions — a pitch that utilities rightfully
pronounced naïve.
The picture has now shifted. At a recent
utility industry trade show, there seemed to
be less participation by the smaller telecom
providers. But the ones that were there were
sharp, focused and had their value proposi-
tions well laid out.
Telecoms are now looking to be seen as
solution providers rather than just telecom
technology suppliers. All the buzzwords
— open systems, interoperability, standards-based — are
there to try and assure the potential buyer that the risks of
stranded assets and obsolescence are minimal. Some are go-
ing after the “middleware” and network management market
— choose your technology and they’ll make it work.
The really big companies, such as Alcatel-Lucent and
Schneider, are branding themselves as total solution provid-
ers — meters, communications, customer management to
back-offi ce, soup to nuts. The appeal here is proven compe-
tence and low risk. That has appeal to many beleaguered util-
ity decision makers.
Smoother Utility-Telecom PartnershipsAs some loose utility-telecom partnerships began to form,
it seemed that telecoms in general didn’t give enough credit
to the utility industry’s telecom sophistication.
Those of us in the industry know utilities have been heav-
ily involved in telecom for years. Even before smart grid was
a gleam in anyone’s eye, utilities were managing massive
amounts of data communications, usually on proprietary net-
works, and doing it well.
Utilities perceived telecoms as being naïve regarding the
needs of power companies, and the communications compa-
nies underestimated the utilities’ telecom technology sophis-
tication. No wonder the courtship got off to a rocky start.
Now, however, both sides are meeting in the middle and
are forming long-term relationships.
Nothing Succeeds Like SuccessThe good news is that smart grid communications enabled
telecom investments are already paying off for millions of
customers. PEPCO customers are seeing a 50% increase in
reliability. PECO greatly improved storm outage restoration
as did Alabama Power. These and other success stories result
from strategically integrating distribution automation, out-
age management and other existing operational systems with
new smart grid telecom networks.
www.tdworld.com
4 May 2012 l Transmission & Distribution World
I Love It When a Plan Comes TogetherBy Paul Mauldin, Senior Editor
The editors of T&D World are proud to
bring you an in-depth view of how our
utility industry is building out enter-
prisewide telecommunications platforms to
support and enable smart grid. Smart grid
is being developed along the same S-curve
that most technology evolutions follow:
start slow, build interest, accelerate invest-
ment, increase number of participants, in-
crease speed of innovation and then begin
to fl atten out and mature. But we couldn’t
have foreseen all the twists and turns.
A Time for Straight TalkSome utilities had seen smart grid primarily as an oppor-
tunity to build up the rate base, while telling their customers
how much smart grid and smart meters would benefi t their
lives. But customers in several states dug into the issue and
found they wouldn’t benefi t much but would experience in-
creased rates. Some even feared health risks from the meter
electromagnetic radiation. Potential risk, higher costs and
foggy benefi ts — what’s the customer to like?
Fortunately, there is a rest of the story. Some utilities de-
cided to take a second approach and build out a business plan
to meet customers’ needs and, in the process, discovered
that an enhanced and well thought out smart grid would be
essential.
Take Oklahoma Gas and Electric (OG&E). Rick Bush,
T&D World’s editorial director, was so impressed with what
was going at this utility that he visited twice to make sure he
really grasped what it was achieving.
OG&E was denied a rate increase to build a coal-fi red
plant, but the state defi nitely needed more electric supply. So
OG&E worked with regulators to fi nd a way to fund load-
shifting solutions that would meet increased demand with the
same ability to control that would have existed on new gen-
eration. It is now building out the smart grid and communica-
tions platform to meet a legitimate need and at a legitimate
price.
So, let’s be honest up-front and build what the customers
need, want and are willing to pay for. In the long run, they
will appreciate the honesty.
Telecom ConsolidationA year ago, smart grid telecom discussions seemed to be
all about technology winners. WiMax, cellular, radio, satellite
— lots of technologies, lots of small providers and a few large
(but not as vocal) ones. Within the utility industry there was
general agreement that for many utilities, no one technology
would meet the needs of the entire service area. However, we
found in our earlier interviews that many of
the telecoms were pitching one-size-fi ts-all
solutions — a pitch that utilities rightfully
pronounced naïve.
The picture has now shifted. At a recent
utility industry trade show, there seemed to
be less participation by the smaller telecom
providers. But the ones that were there were
sharp, focused and had their value proposi-
tions well laid out.
Telecoms are now looking to be seen as
solution providers rather than just telecom
technology suppliers. All the buzzwords
— open systems, interoperability, standards-based — are
there to try and assure the potential buyer that the risks of
stranded assets and obsolescence are minimal. Some are go-
ing after the “middleware” and network management market
— choose your technology and they’ll make it work.
The really big companies, such as Alcatel-Lucent and
Schneider, are branding themselves as total solution provid-
ers — meters, communications, customer management to
back-offi ce, soup to nuts. The appeal here is proven compe-
tence and low risk. That has appeal to many beleaguered util-
ity decision makers.
Smoother Utility-Telecom PartnershipsAs some loose utility-telecom partnerships began to form,
it seemed that telecoms in general didn’t give enough credit
to the utility industry’s telecom sophistication.
Those of us in the industry know utilities have been heav-
ily involved in telecom for years. Even before smart grid was
a gleam in anyone’s eye, utilities were managing massive
amounts of data communications, usually on proprietary net-
works, and doing it well.
Utilities perceived telecoms as being naïve regarding the
needs of power companies, and the communications compa-
nies underestimated the utilities’ telecom technology sophis-
tication. No wonder the courtship got off to a rocky start.
Now, however, both sides are meeting in the middle and
are forming long-term relationships.
Nothing Succeeds Like SuccessThe good news is that smart grid communications enabled
telecom investments are already paying off for millions of
customers. PEPCO customers are seeing a 50% increase in
reliability. PECO greatly improved storm outage restoration
as did Alabama Power. These and other success stories result
from strategically integrating distribution automation, out-
age management and other existing operational systems with
new smart grid telecom networks.
www.tdworld.com
Transmission & Distribution World l May 2012 7
Smart Grid Communications: The Right Platform at the Right Time
By John Egan, Egan Energy Communications
No question, 2012 is shaping up to be a criti-
cal year in utility smart grid deployments.
The last 12 to 24 months have been a time of
intense learning, some of it painful. Look for
more of that over the next year or two.
Gradually, early-adopter utilities are getting a sense of
what works and what does not in their smart grid deploy-
ments. Surprises — welcome and unwelcome — have been
the norm, not the exception, as utilities scour data for key
insights to make their smart grid investments more effective,
politically palatable and successful (see “Five Leaders Share
Cautions and Recommendations”).
Over the last 12 to 24 months, several utilities have been
surprised by adverse regulatory rulings and customer push-
back around smart meters. Going forward, utilities vow there
will be fewer surprises from the regulatory commissions, be-
cause they will do more homework with their commissioners
and commission staff.
Also, there will be more stakeholder engagement at the
front end of a smart grid or smart meter project. Referring to
Pacific Gas and Electric’s (PG&E’s) smart meter problems in
Bakersfield, California, U.S., Karen Lefkowitz, Pepco Hold-
ings’ vice president of business transformation, said, “Utili-
ties must be prepared for their Bakersfield moment, because
if we don’t effectively manage customers’ concerns, these
projects could blow up in our face.”
A Customer-Facing ProjectUtility leaders and smart grid project managers rightly
spend a lot of time on the technological and engineering chal-
lenges posed by the smart grid. Technologies have to perform
as advertised. Transmission and distribution networks need
to be altered. Business processes need to be modified.
No one minimizes the magnitude of those challenges. But,
Lefkowitz makes another compelling point, “Although we
talk a lot about the technologies being deployed in smart grid
programs — and, in particular, the communications tech-
nologies — we must remember that the smart grid is not just
a technology project. It uses technology to deliver customer
benefits. It is a means to an end, not an end in itself.”
Lee Krevat, smart grid director for San Diego Gas & Elec-
tric (SDG&E), agrees, “It is possible to select the right smart
grid equipment, whatever it may be, and install it properly,
but if we don’t get the people part of smart grid right, the
projects will fail.”
Who Benefits? Who Pays?In the not-too-distant past, circa 2009, before the industry
www.tdworld.com
8 May 2012 l Transmission & Distribution World
began amassing data on the costs and benefits of smart grid
projects, it was generally accepted a significant chunk — per-
haps the majority — of the benefits of the smart grid would be
captured by customers using smart meters. In the early years
of the smart grid, smart meters received a lot of industry buzz
while the internal, operational benefits of the broader smart
grid endeavor garnered less attention in many quarters.
Over the last year or so, that perspective has changed, as
much by consumer reaction to smart meters as by the grow-
ing evidence a large amount of benefits may be created in
utilities’ internal operational areas.
At a 2011 conference sponsored by KEMA, David Eves,
president and CEO of Public Service Company of Colorado,
an Xcel subsidiary, estimated 70% of the value of his utility’s
smart grid investment will be in the transmission and distri-
bution system.
Barbara Lockwood, director of energy innovation for Ari-
zona Public Service Co. (APS), generally agrees with Eves.
She said her utility has seen significant operational benefits
from its smart grid projects, which will “help extend the life
of the utility T&D infrastructure and lower maintenance
costs.”
She was more tentative regarding quantification of cus-
tomer benefits so far. “We’re still working to quantify the
benefits to customers,” she reported. “A self-isolating cir-
cuit we installed in Flagstaff, Arizona, U.S., avoided about
600,000 minutes of outages in about a year. In one particular
instance, the self-isolating technology installed on the dis-
tribution system let us turn a potential 40-minute outage at
Flagstaff City Hall into a momentary flicker.”
Pepco’s Lefkowitz noted the utility’s smart meter invest-
ments allowed it to remotely close 582 outage tickets in its
Delaware, U.S., service area after Hurricane Irene. “We were
really pleased with how the system worked after Hurricane
Irene. Anytime you can avoid a truck roll, that’s good.”
In reality, it is futile to try to
put one cluster of benefits into a
bucket labeled “customer ben-
efits” and another cluster into a
second bucket named “internal
utility benefits.” Benefits are
accruing in both areas, in ways
that are financial as well as
nonfinancial. “The right smart
grid technology and deploy-
ment should create benefits for
both customers and utilities,”
said Doug Kim, director of
advanced technology at South-
ern California Edison (SCE).
“Better-quality asset manage-
ment brings benefits to cus-
tomers, as well. It’s a both/and
situation, not either/or.”
Regulatory IssuesIf the last 12 to 24 months was a period of learning from
field deployments, the next 12 to 24 months promise to be
an equally challenging time of learning in the public utility
commission hearing room.
Many utilities have a large and growing capital spending
program, driven by the following, among other things:
l The need to replace aging infrastructure
l The need to comply with mandated state renewable en-
ergy standards
l The need to clean up or close older coal-fired generators
to comply with new environmental regulations.
“We have no shortage of investments right now, includ-
ing nearly US$1 billion in solar generation,” said APS’s
Lockwood. She also said the utility is currently looking at
its smart grid communications platforms and will consider
leasing bandwidth from other telecommunications providers
as well as building it (see “Telecommunications Networks:
Own or Lease?”).
State utility regulators are being “very, very cost con-
scious these days. How much financial burden do they want
to place on customers? Very little,” said Pepco’s Lefkowitz.
She said, “We evaluate all communications approaches,
leased or owned, and select the one that best meets cost and
operational requirements.”
The U.S. Securities and Exchange Commission and the
California Public Utilities Commission are investigating the
costs and benefits of allowing a utility to put its lease costs
into a rate base, and thus earn a return on them.
However, as these own versus lease discussions progress,
there is a white elephant in the room that few, if any, par-
ticipants want to acknowledge. The industry is installing new
technology at a rapid pace. This carries high risks, which
translates into upward pressure on electric rates. No one
wants to talk about increasing rates today to pay for benefits
that may not become clear for several years, if ever.
Five Leaders Share Cautions and RecommendationsKevin Dasso, senior director, smart grid and technology integration, Pacific Gas and Electric: “You only
have one chance to make a good first impression. It’s important that the technology works, and it works for
customers. You have to be able to tell customers what’s in it for them.”
Doug Kim, director, advanced technology, Southern California Edison: “This is a long journey. It’s critical
to develop a strong strategy and a clear road map with specific milestones. Take time to create links across
internal stakeholders.”
Lee Krevat, director, smart grid, San Diego Gas & Electric: “Don’t get locked into proprietary technology
that limits your options. Standards change, technologies change and customer needs change; don’t let
yourself get put in a box.”
Karen Lefkowitz, vice president, business transformation, Pepco Holdings: “We live in an era where a
small group of dedicated stakeholders can create lot of controversies and problems for smart grid deploy-
ments. Regulators and legislators are compelled to listen to those concerns. You need to engage with your
stakeholders early and often.”
Barbara Lockwood, director, energy innovation, Arizona Public Service: “Take it slow until you under-
stand the operational benefits and customer needs around smart grid. Learn from others — no one is
doing everything, but everything is being done by someone.”
www.tdworld.com
9Transmission & Distribution World l May 2012
Many regulatory and legis-
lative mandates fit the definition
of “moral hazard” — an initia-
tive that does not fully consider
impacts because the costs are
being paid by someone else. In
effect, regulators and legisla-
tors are playing with other peo-
ple’s money. There is concern
that when the music stops and
the bills have to be paid, utili-
ties will be forced to pay for
mandates enacted by regulators
and lawmakers. These costs
include the undesirable, but
necessary, equipment and operational failures as the industry
goes through a protracted, intense learning curve.
Matching Technologies with NeedsDozens of utilities are implementing smart grid programs.
This robust array of field deployments has confirmed one
fundamental truism: When it comes to the communications
technologies necessary to enable smart grid deployments, one
size does not fit all. When one thinks about the geographic
size and diverse terrains utilities must serve, this truism may
not be surprising. Utilities like PG&E often serve an area
that ranges from very densely populated urban areas to very
sparsely populated rural mountain regions.
The volume of data generated and latency are two of the
most critical factors in determining which communications
technologies a utility uses for its various smart grid projects.
Some mission-critical applications tolerate virtually no la-
tency in their communications networks. One example of this
is the synchrophasor technologies PG&E is installing in high-
voltage transmission systems in the West, in collaboration
with a handful of other utilities. “The synchrophasors take
up to 60 measurements per second and give us much better
intelligence into the way that the high-voltage transmission
system works,” said Kevin Dasso, PG&E’s senior director for
smart grid and technology integration.
Other smart grid applications are less time sensitive; data
can be transmitted over a period of hours or days instead of
seconds or fractions of a second. For example, for most smart
meter applications, the longer latencies offered by mesh radio
are acceptable.
“As with most things involving our industry, choice of
communications platforms involves a number of trade-offs,”
said Jeff Nichols, SDG&E’s director of information technol-
ogy infrastructure. “We have found that no single commu-
nications technology works optimally in all settings.” The
trade-offs SDG&E uses to evaluate communications tech-
nologies include cost, coverage, capacity, security and opera-
tional integrity.
Road Map for 2012 and BeyondUtilities are going through a vertical learning curve on
the smart grid and the communications platforms needed
to realize its benefits. During this acute period of learning,
when frontline experience is at a premium, smart grid leaders
offered some words of wisdom for their colleagues at other
utilities.
It takes time to turn raw data into actionable intelligence,
acknowledged APS’s Lockwood. “We’re still in our infancy
regarding turning data into intelligence. This year, we’re go-
ing to spend more time understanding the actualized benefits
from our existing projects and further developing the busi-
ness case based on operational benefits within the utility.”
“We could end up having several dozen smart grid pilots
because we need to respond to the ever-changing needs of
society and its leaders,” said SCE’s Kim. “That may be true
at your utility, too. We expect the smart grid will help us more
effectively utilize our assets so we don’t have to make such
sizable investments to serve customers in the future.”
Kim urges other utility leaders to spend plenty of time
— perhaps more than they think is necessary — educating
and engaging all of their stakeholders, including regulators,
legislators, customers, employees, business groups, vendors
and even investors. “When the pilot programs end and you
go to full-scale deployment, you will be glad you made that
investment.”
John Egan is president of Egan Energy Communications, a utility-
industry communications consulting firm. Before that, he was a reporter
and editor at The Energy Daily, a spokesman for Salt River Project and
a research director at E Source.
Telecommunications Networks: Own or Lease?When it comes to deciding whether it is better to own the telecommunications assets necessary to
support smart grid deployments or lease them from a third party, utilities are all over the map.
Southern California Edison’s Doug Kim, director of advanced technology, says his utility typically owns
and operates its own fiber-optic and radio networks to relay data around its system. “We built it, we operate
it and we own it. From our perspective, ownership of these assets works out best from the perspectives of
safety, affordability and reliability.”
Other utilities say they are comfortable with a mix of owned and leased telecommunications assets.
Interestingly, utility regulators are considering control issues, not only costs, in their lease versus build
decisions. If a utility contracts with a third party, regulators can only assess the transaction from one van-
tage point — the utility’s side. But they can view both sides of a transaction if a utility transmitted smart
grid data over a communications network it built, owns and operates.
Companies mentioned:Arizona Public Service Co. | www.aps.com
California Public Utilities Commission | www.cpuc.ca.gov
KEMA | www.kema.com
Pacific Gas and Electric | www.pge.com
Pepco Holdings | www.pepco.com
Public Service Co. of Colorado | www.xcelenergy.com
San Diego Gas & Electric | www.sdge.com
Securities and Exchange Commission | www.sec.gov
Southern California Edison | www.sce.com
www.tdworld.com
8 May 2012 l Transmission & Distribution World
began amassing data on the costs and benefits of smart grid
projects, it was generally accepted a significant chunk — per-
haps the majority — of the benefits of the smart grid would be
captured by customers using smart meters. In the early years
of the smart grid, smart meters received a lot of industry buzz
while the internal, operational benefits of the broader smart
grid endeavor garnered less attention in many quarters.
Over the last year or so, that perspective has changed, as
much by consumer reaction to smart meters as by the grow-
ing evidence a large amount of benefits may be created in
utilities’ internal operational areas.
At a 2011 conference sponsored by KEMA, David Eves,
president and CEO of Public Service Company of Colorado,
an Xcel subsidiary, estimated 70% of the value of his utility’s
smart grid investment will be in the transmission and distri-
bution system.
Barbara Lockwood, director of energy innovation for Ari-
zona Public Service Co. (APS), generally agrees with Eves.
She said her utility has seen significant operational benefits
from its smart grid projects, which will “help extend the life
of the utility T&D infrastructure and lower maintenance
costs.”
She was more tentative regarding quantification of cus-
tomer benefits so far. “We’re still working to quantify the
benefits to customers,” she reported. “A self-isolating cir-
cuit we installed in Flagstaff, Arizona, U.S., avoided about
600,000 minutes of outages in about a year. In one particular
instance, the self-isolating technology installed on the dis-
tribution system let us turn a potential 40-minute outage at
Flagstaff City Hall into a momentary flicker.”
Pepco’s Lefkowitz noted the utility’s smart meter invest-
ments allowed it to remotely close 582 outage tickets in its
Delaware, U.S., service area after Hurricane Irene. “We were
really pleased with how the system worked after Hurricane
Irene. Anytime you can avoid a truck roll, that’s good.”
In reality, it is futile to try to
put one cluster of benefits into a
bucket labeled “customer ben-
efits” and another cluster into a
second bucket named “internal
utility benefits.” Benefits are
accruing in both areas, in ways
that are financial as well as
nonfinancial. “The right smart
grid technology and deploy-
ment should create benefits for
both customers and utilities,”
said Doug Kim, director of
advanced technology at South-
ern California Edison (SCE).
“Better-quality asset manage-
ment brings benefits to cus-
tomers, as well. It’s a both/and
situation, not either/or.”
Regulatory IssuesIf the last 12 to 24 months was a period of learning from
field deployments, the next 12 to 24 months promise to be
an equally challenging time of learning in the public utility
commission hearing room.
Many utilities have a large and growing capital spending
program, driven by the following, among other things:
l The need to replace aging infrastructure
l The need to comply with mandated state renewable en-
ergy standards
l The need to clean up or close older coal-fired generators
to comply with new environmental regulations.
“We have no shortage of investments right now, includ-
ing nearly US$1 billion in solar generation,” said APS’s
Lockwood. She also said the utility is currently looking at
its smart grid communications platforms and will consider
leasing bandwidth from other telecommunications providers
as well as building it (see “Telecommunications Networks:
Own or Lease?”).
State utility regulators are being “very, very cost con-
scious these days. How much financial burden do they want
to place on customers? Very little,” said Pepco’s Lefkowitz.
She said, “We evaluate all communications approaches,
leased or owned, and select the one that best meets cost and
operational requirements.”
The U.S. Securities and Exchange Commission and the
California Public Utilities Commission are investigating the
costs and benefits of allowing a utility to put its lease costs
into a rate base, and thus earn a return on them.
However, as these own versus lease discussions progress,
there is a white elephant in the room that few, if any, par-
ticipants want to acknowledge. The industry is installing new
technology at a rapid pace. This carries high risks, which
translates into upward pressure on electric rates. No one
wants to talk about increasing rates today to pay for benefits
that may not become clear for several years, if ever.
Five Leaders Share Cautions and RecommendationsKevin Dasso, senior director, smart grid and technology integration, Pacific Gas and Electric: “You only
have one chance to make a good first impression. It’s important that the technology works, and it works for
customers. You have to be able to tell customers what’s in it for them.”
Doug Kim, director, advanced technology, Southern California Edison: “This is a long journey. It’s critical
to develop a strong strategy and a clear road map with specific milestones. Take time to create links across
internal stakeholders.”
Lee Krevat, director, smart grid, San Diego Gas & Electric: “Don’t get locked into proprietary technology
that limits your options. Standards change, technologies change and customer needs change; don’t let
yourself get put in a box.”
Karen Lefkowitz, vice president, business transformation, Pepco Holdings: “We live in an era where a
small group of dedicated stakeholders can create lot of controversies and problems for smart grid deploy-
ments. Regulators and legislators are compelled to listen to those concerns. You need to engage with your
stakeholders early and often.”
Barbara Lockwood, director, energy innovation, Arizona Public Service: “Take it slow until you under-
stand the operational benefits and customer needs around smart grid. Learn from others — no one is
doing everything, but everything is being done by someone.”
www.tdworld.com
May 2012 l Transmission & Distribution World10
When lightning caused a pole-top fire in
Flagstaff, Arizona, U.S., the community
could have experienced an extended and
costly outage. Instead, says Barbara Lock-
wood, director of energy innovation for
Arizona Public Service (APS), robust self-isolating technol-
ogy and a 900-MHz S&C Electric Co. radio communication
system reduced the effect to a momentary flicker of lights, a
mere blip. In fact, over several months in 2011, the utility’s
smart grid investment helped it to avoid some 600,000 cus-
tomer outage minutes.
Similarly, when Hurricane Irene caused widespread
outages on the East Coast in the U.S. last August, Pepco’s
smart grid telecommunications system proved resilient. The
utility’s advanced metering infrastructure (AMI) mesh net-
work in Delaware allowed enough last-gasp messages to get
through to help the utility not only predict the severity of the
damage but also locate which pieces of equipment were most
likely damaged, according to Karen Lefkowitz, Pepco’s vice
president of business transformation.
“Even a small percentage of last-gasp messages reaching
our outage management system during large-scale outages
greatly enhances our ability to send repair crews to the appro-
priate locations to begin restoration efforts,” Lefkowitz said.
Although the utility received some 600 last-gasp messages
from its smart meters, it was able to ping those meters and
clear 582 of the outage events.
In contrast, other service areas pounded by Irene where
the smart grid had not been fully embraced did not fare so
well. News reports revealed customers often were shocked to
learn their utility did not even know when they were out of
power. Advantage: smart grid.
Reliability Up 50% at PepcoLike utilities in other parts of the country, Pepco has had
to adopt and adapt in dealing with the lack of spectrum avail-
ability for its smart grid communications system, a problem
particularly acute in the Washington, D.C., metropolitan
area.
According to Mike Kuberski, Pepco’s manager of enter-
prise architecture, the utility went with a hybrid system for
distribution automation (DA) that incorporates a Silver Spring
Adopting & Adapting:A Communications Strategy
for the Smart Grid
By Lee Harrison, Contributing Writer
www.tdworld.com
11Transmission & Distribution World l May 2012
Networks wireless fi eld area network (FAN) operating in the
unlicensed 902-MHz to 928-MHz spectrum. Backhaul is ei-
ther through a public or private wireless system, depending
on availability. In turn, that system connects to the utility’s
core network of multiple dedicated leased lines to bring data
back to its control center.
According to Lefkowitz, the utility’s DA work so far has
led to a greater than 50% improvement in reliability. As such,
the utility plans to upgrade 50 additional distribution substa-
tions by the end of 2013. It will replace analog relays with
digital relays, add smart power meters, add distributed re-
mote terminal units to expand visibility and control, and
establish decentralized automation of fi eld devic-
es with an automatic sectionalizing and restora-
tion control program at each substation.
Alabama Power had a similar experi-
ence. When storms struck on April 27,
2011, cutting power to more than 300 substa-
tions and destroying or signifi cantly damaging six
others, some 270,000 customers were left without pow-
er. Fortunately, the previous fall the utility had successfully
merged its proprietary outage management system (OMS)
with a Sensus FlexNet two-way wireless communications
network to improve real-time situation awareness and grid
stabilization, and to enhance outage estimation systems. As
a result, the utility was able to restore most service two days
earlier than it did during prior storms, including Hurricane
Katrina.
Faster Restoration
Alabama Power had learned that, while its OMS could es-
timate where service was out, it could not tell system opera-
tors where service had been restored or, more importantly,
what locations could actually take power. However, with the
Sensus AMI system sending last-gasp signals over the Flex-
Net system back to the OMS, the utility not only could speci-
fy critical loads (hospitals, fi re stations and traffi c signals) for
priority restoration, it also could tell when and where power
was on without having to dispatch personnel, allowing it to
prioritize restoration work.
The key was the robustness of the FlexNet telecom sys-
tem, which continued to provide point-to-multipoint commu-
nication with nearly 1.5 million electric meters. Although it
incorporates 150 antenna towers, each with battery backup
and some with backup generators, the network remained
largely intact throughout the storms.
What are the lessons learned? If both utilities and society
at large are to realize these kinds of benefi ts from the smart
grid — increased safety, reliability, effi ciency and security
along with a lower carbon footprint — utilities fi rst need to
invest in communications systems that also are effi cient, safe,
reliable and secure. But in North America, where geography
and topography are as varied as population density, one size
defi nitely does not fi t all.
Most utilities already operate with a half dozen or so dif-
ferent legacy communications systems. So, it is no surprise
that, in moving toward the smart grid, many utilities are
developing and building advanced hybrid communications
systems that employ any combination of telecommunications
systems: broadband over power line, digital microwave, fi ber
optics, satellite, wireless technologies such as worldwide in-
teroperability for microwave access (WiMAX), licensed and
unlicensed radio, cellular and mesh networks based on un-
licensed spectrum. Many of these utilities, like APS, Pepco
and Alabama Power, are already seeing the benefi ts.
One other crucial lesson bears mentioning: Multiple ap-
plication-specifi c, single-purpose networks are incompatible
with the smart grid. In the past, utilities typically developed
multiple communications systems in parallel with one an-
other, said Michelle McLean, Silver Spring Networks’ direc-
tor of product marketing. “The metering guy didn’t know the
distribution automation guy,” for instance; and, as a result,
utilities wound up with a whole set of parallel communica-
tions systems.
Silver Spring’s idea, she said, was to develop a communi-
cations platform that could handle multiple communications
needs — from operations to security — and accept multiple
hardware and software applications.
No Silver Bullet
“You may decide to lead with DA, so buy a platform that
does that well, but not only that,” said McLean. The multi-
application platform should be built on the IPv6 Internet pro-
tocol, which offers considerable advantages over IPv4, the
previous protocol. But, when choosing the type of network
transport, cell, WiMAX or mesh, she said, utilities realize
that sub-gigahertz spectrum is available, unlicensed, usually
cheaper than cell and open for use with excellent propaga-
tion. As a result, McLean added, Silver Spring and numer-
Point-to-multipoint network
Sensus FlexNet point-to-multipoint wireless communications survived severe storms in 2011, allowing Alabama Power to tell when and where power was on without having to dispatch personnel, enabling the utility to prioritize restoration work.
www.tdworld.com
May 2012 l Transmission & Distribution World10
When lightning caused a pole-top fire in
Flagstaff, Arizona, U.S., the community
could have experienced an extended and
costly outage. Instead, says Barbara Lock-
wood, director of energy innovation for
Arizona Public Service (APS), robust self-isolating technol-
ogy and a 900-MHz S&C Electric Co. radio communication
system reduced the effect to a momentary flicker of lights, a
mere blip. In fact, over several months in 2011, the utility’s
smart grid investment helped it to avoid some 600,000 cus-
tomer outage minutes.
Similarly, when Hurricane Irene caused widespread
outages on the East Coast in the U.S. last August, Pepco’s
smart grid telecommunications system proved resilient. The
utility’s advanced metering infrastructure (AMI) mesh net-
work in Delaware allowed enough last-gasp messages to get
through to help the utility not only predict the severity of the
damage but also locate which pieces of equipment were most
likely damaged, according to Karen Lefkowitz, Pepco’s vice
president of business transformation.
“Even a small percentage of last-gasp messages reaching
our outage management system during large-scale outages
greatly enhances our ability to send repair crews to the appro-
priate locations to begin restoration efforts,” Lefkowitz said.
Although the utility received some 600 last-gasp messages
from its smart meters, it was able to ping those meters and
clear 582 of the outage events.
In contrast, other service areas pounded by Irene where
the smart grid had not been fully embraced did not fare so
well. News reports revealed customers often were shocked to
learn their utility did not even know when they were out of
power. Advantage: smart grid.
Reliability Up 50% at PepcoLike utilities in other parts of the country, Pepco has had
to adopt and adapt in dealing with the lack of spectrum avail-
ability for its smart grid communications system, a problem
particularly acute in the Washington, D.C., metropolitan
area.
According to Mike Kuberski, Pepco’s manager of enter-
prise architecture, the utility went with a hybrid system for
distribution automation (DA) that incorporates a Silver Spring
Adopting & Adapting:A Communications Strategy
for the Smart Grid
By Lee Harrison, Contributing Writer
www.tdworld.com
12 May 2012 l Transmission & Distribution World
down to a small number of technologies. The critical issue, of
course, is making all technologies work together. They must
support interoperability.”
Of course, none of this comes easy. Dean Siegrist, who
leads Black & Veatch’s utility telecom team, said simply,
“Everyone wants an easy button, but there’s no such thing
in this industry. Strategic planning is key.” Still, he added,
a hybrid, fully integrated system is most often the best solu-
tion. “Use a public network when available and a private
network in other circumstances,” he advised. Still, he
added, “The art is knowing how to integrate to get
the best cost, performance and reliability.”
According to Tim Godfrey, EPRI
senior project manager, when moving
toward the smart grid, utilities basically
fall into two broad categories. “One group has
installed AMI and will build on that. They can do
simple distribution automation with traditional capacitor
banks, regulator adjustment, conservation adjustment, etc.
They don’t need the highest performance and, as a result, can
use their existing networks.” Latencies, he said, generally
range from one second to one minute. They require a large
number of repeaters on the system, and designers must be
aware of the system’s limitation.
The second group, said Godfrey, already employs a FAN,
which not only offers the higher performance required to in-
clude DA with AMI but also newer applications such as those
necessary for the inclusion of distributed energy sources on
their grids. And, he added, of course “some utilities are under
mandates that require higher-performance networks.”
Going Hybrid Makes SenseIf a utility really wants to control its assets, especially if
those assets are of strategic importance, said IEC’s Sullivan,
ous other vendors focus on mesh networks in the 915-MHz
industrial, scientifi c and medical band.
Yet, mesh networks are no silver bullet. Inevitably, when
utilities build out their networks, they run into pockets where
mesh networks are not viable, making cellular communica-
tions the best choice. Still, McLean advised, “Mesh where
you can; cell where you must.”
An example of Silver Spring’s mesh architecture is in
Pacifi c Gas and Electric’s service area. Silver Spring built
access points (red squares in the image) to get data from indi-
vidual meters, or other end-point devices, back to the utility’s
data center.
“Essentially, it’s the point
where you either leave the util-
ity’s wireless FAN or NAN to join
the utility’s Ethernet link or con-
nect with a cell carrier to get the
data to the back offi ce,” McLean
said. “One access point can serve
5,000 to 10,000 meters.”
According to McLean, where
PG&E runs into connectiv-
ity issues, for example, where
topology or topography creates
problems, Silver Spring provides
relays (white circles in the image)
to boost signal strength.
Barry Sullivan of the Interna-
tional Engineering Consortium
(IEC) does not believe in silver
bullet technologies, either. “Stan-
dards are being written to accom-
modate a variety of solutions,” he
noted. “I don’t see a narrowing
Mesh network
An example of Silver Spring Networks’ mesh architecture in PG&E’s service area.
In PG&E’s service area, Silver Spring Networks built access points (red squares) to get data from individual meters, or other end-point devices, to the utility’s back offi ce. “Es-sentially, it’s the point where you either leave the utility’s wireless FAN or NAN to join the utility’s Ethernet link or connect with a cell carrier to get the data to the back offi ce,” said Michelle McLean. “One access point can serve 5,000 to 10,000 meters.” Where the utility runs into connectivity issues, say, where topology or topography creates prob-lems, she adds, Silver Spring provides relays (white circles) to boost signal strength.
www.tdworld.com
13Transmission & Distribution World l May 2012
a hybrid network makes sense: “Build infrastructure to the
substations and use a public network to reach each customer.”
Still, he noted, because utilities are heavily regulated, the de-
cision on which way to proceed can come down to capital
expenditure versus operating expenditure funding. In that
case, the discussion could depend on the utility’s relationship
with its regulator.
At Florida Power & Light (FPL), however, the driver to
upgrade telecommunications was neither the smart grid nor
direct mandates. It was simply reliability. After the utility ex-
perienced a number of hurricane-induced outages, it sought
a more robust telecom system, and the key,
according to Ron Critelli, director of trans-
mission engineering and technical services
at FPL, was redundancy.
Because it never wanted to lose commu-
nication with its substations, FPL began in-
stalling both landlines and private wireless
communications systems to its substations
in the late 1990s and early 2000s. “We saw
a pretty significant gain in reliability,” Cri-
telli noted. “Both systems are monitored, so
we always know which is up and which is
down.”
Operated by AT&T, the landline is pre-
ferred because it offers more bandwidth,
Critelli said. But, because the utility seeks
even more bandwidth for increased substa-
tion security reliability, including video, FPL
is converting from AT&T’s existing frame
relay network technology to multiprotocol
label switching technology. “AT&T forced
our hand because it’s sunsetting frame re-
lays,” he said, “but we need more bandwidth
in any case.”
The utility uses local cell carriers, such
as AT&T, Verizon and T-Mobile, for wire-
less communications. “There have been a
lot of improvements in cell since the hurri-
canes,” Critelli added. “Wireless coverage is
getting better and better.”
Fiber in Vermont, Wireless at OG&E
In Vermont, where the service area is
both small and rural by comparison, the
state’s transmission utility took a differ-
ent approach. Vermont Electric Power Co.
(VELCO) has announced an agreement
with IBM to build an intelligent fiber-optic
and carrier Ethernet communications and
control network across the state to enhance
reliability.
The network will span more than 1,000
miles (1,609 km) to connect transmission
substations to Vermont’s distribution utili-
ties and provide “an innovative model for the rest of the coun-
try.” The communications system will relay information on
usage, voltage, existing or potential outages, and equipment
performance.
Like VELCO, Oklahoma Gas & Electric (OG&E) serves
a largely rural area, but, unlike VELCO, it is considerably
larger, roughly 30,000 sq miles (77,700 sq km), which made a
wireless system for AMI and DA telecom almost a foregone
conclusion.
AMI data for dynamic pricing is collected from the me-
ters by a Silver Spring Networks radio frequency mesh net-
Transformers. Switchgear. Substations.
Integrated solutions. Automation. Services.
CG is a global leader in electrical products and integrated
solutions. Its products, solutions & services ranges from
distribution & power transformers, to medium & high voltage
switchgear, to SCADA & automation to complete turn-key
substation EPC solutions.
CG has proven track-record of on-time delivery & completion
at its installed base of more than 20,000 MW in North
America, making CG one of the most reliable and preferred
equipment & solution provider in renewable market today.
www.cgglobal.us
AWEA
Visit us at AWEA in Hall B, booth 5919
and at InterSolar USA booth 8053
ADDING POWER TO LIFE
www.tdworld.com
12 May 2012 l Transmission & Distribution World
down to a small number of technologies. The critical issue, of
course, is making all technologies work together. They must
support interoperability.”
Of course, none of this comes easy. Dean Siegrist, who
leads Black & Veatch’s utility telecom team, said simply,
“Everyone wants an easy button, but there’s no such thing
in this industry. Strategic planning is key.” Still, he added,
a hybrid, fully integrated system is most often the best solu-
tion. “Use a public network when available and a private
network in other circumstances,” he advised. Still, he
added, “The art is knowing how to integrate to get
the best cost, performance and reliability.”
According to Tim Godfrey, EPRI
senior project manager, when moving
toward the smart grid, utilities basically
fall into two broad categories. “One group has
installed AMI and will build on that. They can do
simple distribution automation with traditional capacitor
banks, regulator adjustment, conservation adjustment, etc.
They don’t need the highest performance and, as a result, can
use their existing networks.” Latencies, he said, generally
range from one second to one minute. They require a large
number of repeaters on the system, and designers must be
aware of the system’s limitation.
The second group, said Godfrey, already employs a FAN,
which not only offers the higher performance required to in-
clude DA with AMI but also newer applications such as those
necessary for the inclusion of distributed energy sources on
their grids. And, he added, of course “some utilities are under
mandates that require higher-performance networks.”
Going Hybrid Makes SenseIf a utility really wants to control its assets, especially if
those assets are of strategic importance, said IEC’s Sullivan,
ous other vendors focus on mesh networks in the 915-MHz
industrial, scientifi c and medical band.
Yet, mesh networks are no silver bullet. Inevitably, when
utilities build out their networks, they run into pockets where
mesh networks are not viable, making cellular communica-
tions the best choice. Still, McLean advised, “Mesh where
you can; cell where you must.”
An example of Silver Spring’s mesh architecture is in
Pacifi c Gas and Electric’s service area. Silver Spring built
access points (red squares in the image) to get data from indi-
vidual meters, or other end-point devices, back to the utility’s
data center.
“Essentially, it’s the point
where you either leave the util-
ity’s wireless FAN or NAN to join
the utility’s Ethernet link or con-
nect with a cell carrier to get the
data to the back offi ce,” McLean
said. “One access point can serve
5,000 to 10,000 meters.”
According to McLean, where
PG&E runs into connectiv-
ity issues, for example, where
topology or topography creates
problems, Silver Spring provides
relays (white circles in the image)
to boost signal strength.
Barry Sullivan of the Interna-
tional Engineering Consortium
(IEC) does not believe in silver
bullet technologies, either. “Stan-
dards are being written to accom-
modate a variety of solutions,” he
noted. “I don’t see a narrowing
Mesh network
An example of Silver Spring Networks’ mesh architecture in PG&E’s service area.
In PG&E’s service area, Silver Spring Networks built access points (red squares) to get data from individual meters, or other end-point devices, to the utility’s back offi ce. “Es-sentially, it’s the point where you either leave the utility’s wireless FAN or NAN to join the utility’s Ethernet link or connect with a cell carrier to get the data to the back offi ce,” said Michelle McLean. “One access point can serve 5,000 to 10,000 meters.” Where the utility runs into connectivity issues, say, where topology or topography creates prob-lems, she adds, Silver Spring provides relays (white circles) to boost signal strength.
www.tdworld.com
14 May 2012 l Transmission & Distribution World
work, which operates in the unlicensed 900-MHz spectrum.
It connects to a private wireless Motorola WiMAX network
operating at 3.6 GHz. In some cases where WiMAX cover-
age is limited, AMI backhaul service is leased from local cel-
lular carriers, for example, AT&T or Sprint.
From the WiMAX layer, the data is transported by an
Alcatel-Lucent microwave backbone, operating at 6 GHz,
to OG&E’s data center. This system also provides substation
and DA connectivity for the utility. Alcatel-Lucent is han-
dling the build-out of OG&E’s wireless backhaul network,
and the three-year project is scheduled for completion in fall
2012.
According to Scott Milanowski, director of grid intelli-
gence at OG&E, after reviewing the total cost of ownership
and risk assessment of a range of options, the utility decided
ownership and operation of a private network was the best
option to meet its needs going forward.
The project is complex, with an aggressive schedule and
rigorous technical specifications. For example, OG&E set
strict latency and bandwidth requirements for the automatic
reclosers and capacitor controllers on the grid — the DA piece
of the project — and those switches have to send information
back and forth quickly enough to the distribution manage-
ment system to deliver the reliability improvement and grid
performance goals the utility envisioned.
Milanowski said the network not only will have enough
bandwidth to support every necessary smart grid component
OG&E plans to install, but it also will meet the utility’s future
growth needs. The network is a critical part of a complex sys-
tem of integrated technologies that will allow OG&E to meet
its smart grid program goals to engage customers, mitigate
Last-gasp messages from smart meters helped PEPCO quickly identify equipment damaged by Hurricane Irene, thus enhancing the utility’s ability to send repair crews to the appropriate locations to begin restoration efforts.
Overcome customer resistance to the smart grid.
Consumer resistance to AMI and smart meter projects centers on issues
related to safety, security, and/or privacy concerns and affects how
utilities plan and deploy their smart meter programs. This resistance
has caught the ear of regulators who are requiring smart meter opt-out
provisions. Black & Veatch helps utilities to take proactive measures to
build consumer confi dence and reduce challenges associated with smart
meter opt-out programs.
That’s the Black & Veatch difference.
Consulting • Engineering • Construction • Operation I w w w.bv.com
Safety
Security
www.tdworld.com
15Transmission & Distribution World l May 2012
Companies mentioned:Alabama Power | www.alabamapower.com
Alcatel-Lucent | www.alcatel-lucent.com
Black & Veatch | www.bv.com
EnerNex | www.enernex.com
EPRI | www.epri.com
Florida Power & Light | www.fpl.com
IBM | www.ibm.com
International Engineering Consortium | www.iec.org
Oklahoma Gas & Electric | www.oge.com
Pepco | www.pepco.com
Pacific Gas and Electric | www.pge.com
S&C Electric Co. | www.sandc.com
Sensus | www.sensus.com
Silver Spring | www.silverspringnet.com
Trilliant | www.trilliantinc.com
Utilities Telecom Council | www.utc.org
VELCO | www.velco.com
cost increases and reduce peak electricity demand, while in-
creasing operational efficiency and reliability.
Strategic Planning is KeyNo matter what combination of smart grid communica-
tions networks utilities have selected to adopt or adapt, the
key to successful implementation is strategic planning. The
planning should commence with four goals in mind:
1. All devices must be interoperable within an open stan-
dard environment.
2. The system must be extensible to protect the utility’s
investment.
3. Security must be built into the architecture.
4. There must be a plan to oversee and manage all those
devices.
Another concept utilities appear to be coalescing around
is the choice of Internet protocol (IP) for end-to-end network
layer technology, which not only offers the required levels
of reliability, redundancy and availability but also supports
legacy systems and applications.
Like Silver Spring’s McLean, Mark Madden, Alcatel-
Lucent’s regional vice president for North American energy
markets, supports an IP approach. “IP can carry legacy pro-
tocols through a variety of methods such as tunneling via
MPLS, a proven technology that is being deployed broadly
by the utility industry,” he said.
Still, for those utilities seeking to install wireless systems,
frequency availability can be a challenge. Unlike Canada,
which has allocated 1800 MHz to 1830 MHz to support its
electric grid, the U.S. still has no overall policy to ensure ad-
equate spectrum for smart grid applications. That said, with
the military abandoning the 700-MHz spectrum, there may
be hope. Officials in Michigan recently asked the Federal
Communications Commission to grant a 700-MHz broad-
band waiver in the state to build a shared long-term evolution
(LTE) network for first responders that also would support
commercial utility users.
According to Alcatel-Lucent’s Madden, LTE is an emerg-
ing technology with great promise, though it is not widely
deployed in the U.S. because of spectrum difficulties. Still,
he said, “LTE offers better spectral efficiency than WiMAX
for both fixed and mobile service. It almost looks like MPLS
quality.” Accordingly, he noted, “We expect LTE to overtake
WiMAX.”
Think Inside the BoxesTechnology could help to resolve the scramble for fre-
quency, too, according to Doug Houseman, vice president
of technical innovation at EnerNex Corp. Highly directional,
phased array antennas that use small segments of the spec-
trum, like Trilliant’s SkyPilot technology, could produce
tailor-made solutions for the urban environment, he said.
But, he cautions, utilities still need a sound methodology
to determine which type of telecom system to choose. First,
said Houseman, they must determine which smart grid appli-
cations they want to install, the level of assurance of delivery
they want to achieve and the latencies required to achieve it.
Once that is done, he said, they should draw four boxes to
evaluate their communications options and needs in certain
situations.
For example, when a utility is in restoration mode after
a major outage, “This is the hardest [situation] because we
only have part system, and you need to know what’s going
on,” said Houseman. Too frequently, he said, “Nobody looks
at the bandwidth requirements necessary to bring the system
back.” It also is important for the utility to plan for firmware
download (that is, when field devices, including security
keys, need to be updated). “Instead of pulling data from field
as usual, we need to send large messages out, but most utili-
ties don’t consider this need,” Houseman cautions.
If a utility goes through this process and considers a wire-
less network the best solution, Houseman noted, “It should
get involved with the Utilities Telecom Council. If they
don’t,” he warned, “they may find their answer handed to
them by a government agency” and have no choice in the
matter.
Lee Harrison ([email protected]) has been writing about the power
industry since 1978. He has been an editor for Business Week, a research-
er with EPRI and a freelance writer, writing articles for The New York Times
and the EPRI Journal. Harrison holds a bachelor’s degree in engineering
from Northeastern University and a master’s degree in journalism from
Columbia University. He is a former writing instructor at Massachusetts
College of Liberal Arts.
Four Situations to Consider in Smart Grid Telecom Planning
Maintaining business as usual
How will the utility keep things going as they are right now?
In the middle of a major outage
When the system crashes, what will the real-time information needs be?
In restoration mode after an outage is over
What bandwidth and equipment will be needed to bring the system back?
When field device software and security need to be updated
Instead of the utility pulling data from the field as usual, large messages need to be sent to its field devices.
How will the utility do this?
www.tdworld.com
14 May 2012 l Transmission & Distribution World
work, which operates in the unlicensed 900-MHz spectrum.
It connects to a private wireless Motorola WiMAX network
operating at 3.6 GHz. In some cases where WiMAX cover-
age is limited, AMI backhaul service is leased from local cel-
lular carriers, for example, AT&T or Sprint.
From the WiMAX layer, the data is transported by an
Alcatel-Lucent microwave backbone, operating at 6 GHz,
to OG&E’s data center. This system also provides substation
and DA connectivity for the utility. Alcatel-Lucent is han-
dling the build-out of OG&E’s wireless backhaul network,
and the three-year project is scheduled for completion in fall
2012.
According to Scott Milanowski, director of grid intelli-
gence at OG&E, after reviewing the total cost of ownership
and risk assessment of a range of options, the utility decided
ownership and operation of a private network was the best
option to meet its needs going forward.
The project is complex, with an aggressive schedule and
rigorous technical specifications. For example, OG&E set
strict latency and bandwidth requirements for the automatic
reclosers and capacitor controllers on the grid — the DA piece
of the project — and those switches have to send information
back and forth quickly enough to the distribution manage-
ment system to deliver the reliability improvement and grid
performance goals the utility envisioned.
Milanowski said the network not only will have enough
bandwidth to support every necessary smart grid component
OG&E plans to install, but it also will meet the utility’s future
growth needs. The network is a critical part of a complex sys-
tem of integrated technologies that will allow OG&E to meet
its smart grid program goals to engage customers, mitigate
Last-gasp messages from smart meters helped PEPCO quickly identify equipment damaged by Hurricane Irene, thus enhancing the utility’s ability to send repair crews to the appropriate locations to begin restoration efforts.
Overcome customer resistance to the smart grid.
Consumer resistance to AMI and smart meter projects centers on issues
related to safety, security, and/or privacy concerns and affects how
utilities plan and deploy their smart meter programs. This resistance
has caught the ear of regulators who are requiring smart meter opt-out
provisions. Black & Veatch helps utilities to take proactive measures to
build consumer confi dence and reduce challenges associated with smart
meter opt-out programs.
That’s the Black & Veatch difference.
Consulting • Engineering • Construction • Operation I w w w.bv.com
Safety
Security
www.tdworld.com
May 2012 l Transmission & Distribution World16
Smart Utilities: Can the Smart Grid Market Explode
Without Full Interoperability?
As of June 2011, more than 5 million smart me-
ters had been installed in the United States
as part of federal stimulus-funded efforts to
accelerate modernization of the nation’s elec-
tric grid. Today, according to the Department of
Energy, every cent of the US$813 million in federal stimulus
funds dedicated to advanced metering infrastructure (AMI)
has been spent on — or has been committed to — smart meter
installations.
Couple that with highly publicized consumer resistance
to those same smart meters in California and elsewhere, and
it is not all that surprising to hear executives at smart grid
telecom companies saying the market is shifting away from
AMI and toward distribution automation (DA). Indeed, many
telecom executives are already proclaiming 2012 as a break-
out year for DA in the U.S.; some are expecting the market
to explode.
“With stimulus money going away, utility investment has
to be tied to a concrete business case,” said David Lubkeman,
distribution product manager for Sensus, a provider of point-
to-multipoint radio networks.
Lubkeman believes utilities will be able to make that case
for DA, especially in what he calls the “hot areas,” such as
advanced volt/VAR optimization (VVO), automatic section-
alization and restoration (ASR) and conservation voltage
reduction (CVR). “We’re having a lot of conversations with
customers along those lines,” he said.
Lizardo Hernandez of Landis+Gyr agrees. “A lot more can
be done with DA,” he said, and because of that, Landis+Gyr
expects an “explosion” in the market for DA products and
services. “In our view, this is the next best area for expan-
sion,” he added.
Ready for Smart Meters?Others, like Rob Conant, Trilliant’s CMO, still see life
in the AMI market. With regard to smart meters, “The big-
gest change this year is that we’re seeing a lot more activity
outside the U.S.,” he said. He cites a couple reasons for the
domestic slowdown: the winding down of the federal stimu-
lus and the regulatory uncertainty. He cautioned, “A lot of
regulators look at what’s happening with consumers and, as a
result, are asking, ‘Are we ready for smart meters?’”
Hernandez is similarly wary, noting regulatory policies
could present a possible hurdle to smart grid investment.
“Coming off stimulus grants, we’re now entering a phase
where utilities will need to show tangible benefits of their
smart grid investments,” he said.
But Conant also underscores what he said is the difference
between the domestic U.S. and foreign AMI markets. Other
countries have different drivers pushing them toward smart
meters, he said. In the European Union, for instance, the en-
vironment is a big driver, and in the U.K., the government has
stated its commitment to rolling out 56 million meters over
the next seven years.
Interest in smart meters goes beyond North America and
Western Europe. “There’s a lot of movement toward smart
meters in Brazil and Asia,” Conant noted. By contrast, in
the U.S., “There’s a lot more certainty — and a very clear
business driver — for distribution automation, so in the U.S.,
we’re seeing a lot more utilities focus on DA instead of smart
metering,” he said.
AMI Market Still ViableMark Madden, Alcatel-Lucent’s regional vice president
for North American energy markets, has a bit of a different
By Lee Harrison, Contributing Writer
www.tdworld.com
17Transmission & Distribution World l May 2012
take. He sees the smart meter market mov-
ing to the municipal utilities and coopera-
tives, with greater emphasis on substation
automation and DA at the investor-owned
utilities. “We see that now in the RFPs that
are coming out,” he noted, and it is largely
because federal dollars are less available
and utilities need to provide a strong busi-
ness case to their regulators to invest in the
smart grid.
Yet, Silver Spring Networks’ Michelle
McLean views the AMI market with opti-
mism. “We’re seeing a pretty strong return,
including U.S. and international markets, to
demand for smart metering,” said McLean,
director of product marketing for Silver
Spring. “The lull in smart metering was
more last year.” This year, she said, “Fore-
casts are up again.”
“The use case for AMI doesn’t go away
just because stimulus funds are gone,”
said Scott Truitt, director of marketing
for Grid Net, whose machine-to-machine
network operating system manages devices and applications
on broadband networks. “However, the business case for
‘AMI only’ certainly does,” he added.
According to Truitt, Grid Net sees three things happening
in the market today:
l A move to leverage cellular data networks
l A push to deploy more and higher-value applications
(DA being just one of them)
l A need to do flexible deployments that show immediate
returns and deliver lasting value. “This is the next phase of
smarter grid deployments,” Truitt added.
Still, McLean recognizes the appeal of DA, both to her
customers and to regulatory commissions. “A lot of folks are
realizing smart grid is so much more than smart metering,”
she said. “We think of DA as the unsung hero of smart grid
— huge benefits in energy efficiency and energy reliability,
but fairly invisible to the average consumer.” However, she
added, “DA is not invisible to commissions, which seem very
inclined to approve DA projects because of their obvious
benefits and good payback.”
Difficult DecisionsOf course, the decision to invest in AMI or DA, or both —
along with what technology and architecture to deploy — is
never easy. And different utilities come to different conclu-
sions. A December 2011 report by Newton-Evans Research
bluntly stated: “We begin 2012 in desperate need of a national
mandate and strong federal investment to move the electric
power industry ahead and to shore up our entire range of
critical infrastructure sectors.”
The report also documented the range of choices utilities
are making in communications technologies for supervisory
control and data acquisition (SCADA) systems. “Fiber was
the clear leader among the many communications options
available for acquisition of SCADA data from transmission
and distribution substations,” the report noted. “Microwave
was next in importance, followed by licensed spectrum radio
and a mix of licensed and unlicensed spectrum,” according
to the report.
“When is the best time to buy a computer?” asked Mar-
tin Travers, head of telecommunications at Black & Veatch.
“Tomorrow,” he said, and “it’s the same with utilities.” Ac-
cordingly, he advises utilities to plan for the future, “so even
if you’re only focusing on AMI today, you don’t waste the
entire deployment when you upgrade.” Travers said Black &
Veatch tries to provide clients a migration path that is ex-
pandable and scalable.
Utilities seem to get the message. Whether utilities are
considering an investment in smart meters or focusing on
DA, or both, virtually all telecom companies see two trends
unfolding: utilities are pushing for equipment interoperabil-
ity (no Tower of Babel effect wanted here) and the ability to
run multiple applications over a single network (leveraging).
Interoperability is CriticalLike Black & Veatch’s Travers, Sensus’ Lubkeman re-
flected a common sentiment, “The choice of a communica-
tions system is a big decision for utilities.” Not only do utili-
ties have to live with the system for a long time, they likely
will want to choose more and more endpoints (that is, meters
or field devices) every year, and they will want the ability to
switch vendors at any time. “So interoperability is critical,”
he said.
Lubkeman also noted utilities’ desire to ensure their smart
grid telecommunications system can handle multiple applica-
tions over the same infrastructure. “If a customer can apply
A December 2011 report by Newton-Evans Research Co. documented the range of choices utilities are making in communications technologies for SCADA systems.
0 10 20 30 40 50 60 70 80
Licensed spectrum
Unlicensed spectrum
Combination of licensed/unlicensed
Private networks/leased licensed spectrum
IP
Wireless
Satellite
Fiber
Microwave
Frame relay
Other
26%
15%
19%
11%
23%
17%
6%
75%
33%
29%
11%
www.tdworld.com
May 2012 l Transmission & Distribution World16
Smart Utilities: Can the Smart Grid Market Explode
Without Full Interoperability?
As of June 2011, more than 5 million smart me-
ters had been installed in the United States
as part of federal stimulus-funded efforts to
accelerate modernization of the nation’s elec-
tric grid. Today, according to the Department of
Energy, every cent of the US$813 million in federal stimulus
funds dedicated to advanced metering infrastructure (AMI)
has been spent on — or has been committed to — smart meter
installations.
Couple that with highly publicized consumer resistance
to those same smart meters in California and elsewhere, and
it is not all that surprising to hear executives at smart grid
telecom companies saying the market is shifting away from
AMI and toward distribution automation (DA). Indeed, many
telecom executives are already proclaiming 2012 as a break-
out year for DA in the U.S.; some are expecting the market
to explode.
“With stimulus money going away, utility investment has
to be tied to a concrete business case,” said David Lubkeman,
distribution product manager for Sensus, a provider of point-
to-multipoint radio networks.
Lubkeman believes utilities will be able to make that case
for DA, especially in what he calls the “hot areas,” such as
advanced volt/VAR optimization (VVO), automatic section-
alization and restoration (ASR) and conservation voltage
reduction (CVR). “We’re having a lot of conversations with
customers along those lines,” he said.
Lizardo Hernandez of Landis+Gyr agrees. “A lot more can
be done with DA,” he said, and because of that, Landis+Gyr
expects an “explosion” in the market for DA products and
services. “In our view, this is the next best area for expan-
sion,” he added.
Ready for Smart Meters?Others, like Rob Conant, Trilliant’s CMO, still see life
in the AMI market. With regard to smart meters, “The big-
gest change this year is that we’re seeing a lot more activity
outside the U.S.,” he said. He cites a couple reasons for the
domestic slowdown: the winding down of the federal stimu-
lus and the regulatory uncertainty. He cautioned, “A lot of
regulators look at what’s happening with consumers and, as a
result, are asking, ‘Are we ready for smart meters?’”
Hernandez is similarly wary, noting regulatory policies
could present a possible hurdle to smart grid investment.
“Coming off stimulus grants, we’re now entering a phase
where utilities will need to show tangible benefits of their
smart grid investments,” he said.
But Conant also underscores what he said is the difference
between the domestic U.S. and foreign AMI markets. Other
countries have different drivers pushing them toward smart
meters, he said. In the European Union, for instance, the en-
vironment is a big driver, and in the U.K., the government has
stated its commitment to rolling out 56 million meters over
the next seven years.
Interest in smart meters goes beyond North America and
Western Europe. “There’s a lot of movement toward smart
meters in Brazil and Asia,” Conant noted. By contrast, in
the U.S., “There’s a lot more certainty — and a very clear
business driver — for distribution automation, so in the U.S.,
we’re seeing a lot more utilities focus on DA instead of smart
metering,” he said.
AMI Market Still ViableMark Madden, Alcatel-Lucent’s regional vice president
for North American energy markets, has a bit of a different
By Lee Harrison, Contributing Writer
www.tdworld.com
18 May 2012 l Transmission & Distribution World
detection, isolation and restoration for managing outages.
“Trying to extract the same level of information from siloed,
proprietary networks adds operational cost and employee
resources,” Amberkar said. Additionally, he noted, the lay-
ered architecture of Cisco’s fi eld area network not only offers
utilities the fl exibility to deploy multiple applications over
common network infrastructure but also the ability to sup-
port both wired and wireless communications over the same
converged network.
“When we decided to build a smart grid platform, the
whole point was to serve multiple smart grid applications, not
just one given solution,” Silver Springs’ McLean said. Along
with networking equipment and back-offi ce software, Silver
Spring sells communications modules, essentially network
cards, third parties can embed in other smart grid devices.
Essentially, Silver Spring builds the middle layer of the eco-
system, McLean explained.
“Our hardware partners plug in underneath, and our soft-
ware partners plug in on top.” McLean said. “We make a
great advanced metering system but not the meters. We part-
ner for all our meters and put our communications module in
those meters.” And the same goes for other smart grid appli-
cations, she said, “We’re meter agnostic, DA device agnostic,
load control switch agnostic, electric-vehicle charging station
agnostic; just plug in our communications module, and they
run over our platform.”
Of course, said McLean, these are not either/or decisions
for most Silver Spring customers “because they’re leveraging
the same infrastructure they use for smart meters to deploy
DA applications.” That is, they can use the information gath-
ered by their smart meter (that is, voltage readings) to feed
the same telecom infrastructure to operate multiple systems
— such as water and gas — in addition to electricity, it lowers
the overall cost.” He cites growing utility interest in outdoor
lighting control as an example. Landis+Gyr’s FlexNet system
could be used to dim streetlights, turn them up or turn them
off, or for emergency notifi cation, thus helping to spread the
cost of the system over multiple applications, Lubkeman
said.
Of course, if utilities want more functionality in their tele-
com systems, they will need to add more processing power
and more memory to those systems, and they will need the
ability to update application and security software wherever
and whenever they need it. As such, Landis+Gyr’s Hernan-
dez said the ability to do “over-the-air updating” is vital.
Multiple ApplicationsSanket Amberkar, senior manager of smart grid market-
ing at Cisco, says utilities face two common problems:
● Networks designed for AMI cannot support the more
demanding needs of DA.
● There is a lack of interoperability between proprietary
legacy telecom systems.
According to Amberkar, rather than periodically replac-
ing those underlying networks to resolve the fi rst problem,
utilities seek a telecom infrastructure that protects their in-
vestment by scaling to meet future applications. To solve the
second problem, utilities need an open standards-based com-
munications infrastructure that can share information from
multiple sources.
For instance, Amberkar said, AMI information integrated
with distribution management systems can improve fault
Cisco maintains that a robust, single converged network infrastructure, supporting telephone, video and data communica-tions — along with multiple applications — provides investment protection and will increase the return on investment over time.
Connected Grid Field Area Network Solution
Lower CapEx/OpEx on a multi-service platform
Cost saving fromconverged platform
New value from functional integration
Residentialmetering
Transformermonitoring
Distributionautomation
EV charginginfrastructure
Large C&I meters
Work forceautomation
Distributedgeneration
Distributionprotection andcontrol network
Customerportal
MDM Loadcontrol
SCADA DMS
CIS/billing AMIhead-end
EMS OMS
New
NMS
GatewayProtection and
control network
RF/PLCmesh
Substation
www.tdworld.com
19Transmission & Distribution World l May 2012
Utility Communications Trends and Observations Over the past three decades, Newton-Evans Research Co. has studied a variety of control systems and related technology used by the world’s
electric power industry and, to a lesser extent, the use of similar control systems in other energy segments. There are a number of issues confronting
utility telecommunications officials in the first half of 2012. Here are a top five:
1. Network Security and Operational Effective-ness. The questions swirl around whether we can and should extend,
make available and then unify Tier 3 and Tier 4 linkages (field networks
and neighborhood and home networks) for customer premises applica-
tions using operational links constructed for distribution automation
applications. The converse trend is to use the new implementations of
metering communications paths to also serve as communications paths
for new installations of distribution automation devices.
2. Lack of Available Spectrum. There is a paucity of
spectrum available at reasonable costs today for use by electric power
utilities. The Utilities Telecom Council is championing the rights and
needs of utilities to acquire additional spectrum to enable the further
development of automation and the growth in deployment of intelligent
field devices that can communicate to utility control centers.
3. The Future of Private Utility-Operated Networks. In recent years, the major public communications carriers
have been pushing for a larger share of telecommunications spending
by utilities, which in North America now exceed $3 billion (for electric,
gas and water utility telecommuni-
cations investments annually). The
debate centers on the “make or buy”
decisions with which utility telecom-
munications departments contend.
Carriers are making their points at
high levels within utilities and within
regulatory and legislative bodies that
they can provide cost-effective com-
munications in a secure and highly
reliable manner. However, in most
recent discussions at industry confer-
ences, there is that persistent attitude
that a well-architected, finely tuned
private network can provide six 9’s of
reliability versus a possible four 9’s of
reliability from public carriers. All in all,
utilities are not likely to shift from their
current stance (and significant invest-
ments) regarding the value and need
for continuation of largely private networks, with ancillary and judicious
use of commercial services.
4. Technology Transfer for Managed Network Services. Not at all the same as using a commercial network
provider, the use of a managed network service is simply one way to
recycle private-hybrid communications networks originally constructed
for another purpose but with enough capability to undertake additional
missions of a critical nature. In turn, this saves hundreds of millions of
dollars in duplicate investments in network design and construction. A
case in point is the Harris Corp.’s operation of the FAA Telecommunica-
tions Infrastructure, as a managed network service. This is one of the
largest managed network services in the nation, perhaps the world. In
2011, Harris was awarded the contract to operate the communications
network for the Western Electric Coordinating Council’s synchrophasor
initiative that spans a broad swath of the Western United States. There
will be additional opportunities for managed services operations of
large-scale, assured communications networks as the smart grid rollout
continues to evolve and as North America begins to be able to develop a
composite real-time portrait of the interconnected electric power system.
5. Divergence Between North America and the International Electric Power Community in the Approach to Telecommunications Networks. The
differences in power systems architecture among international utilities
contrasted with their North American counterparts are substantial at the
medium-voltage and low-voltage levels for power delivery. In addition to
the differing design of the power delivery networks, there are different
approaches in use and planned related to telecommunications meth-
odologies and to communications protocols. In many countries where
state-managed electric power utilities are operated, the telecommunica-
tions ministry provides a “managed
network service” approach for utility
communications.
n Telecommunications
Technologies. In many international
communities, the use and planned
use of power line communications
techniques continues to grow. Yet, in
North America, after an initial flurry of
activity in the 2004-2007 periods, the
interest level has waned. Much of this
is traceable to the differences in dis-
tribution system network design and
the resulting simplicity (internation-
ally) or complexity (North America)
of using a broadband over power line
and distribution power line carrier.
n Communications Protocols.
At least some of the differences have
to do with the simple fact of procure-
ment methods used here and abroad. While much of the international
community prefers to issue turnkey contracts for large projects, most
North American utility procurements are divided among a number of sup-
pliers and services providers. Thus, while IEC 61850 makes a lot of sense
when a single supplier is involved in substation construction and auto-
mation, the need for a simpler plug-and-play approach in North America,
and several international markets, is the rule and not the exception. This
is where DNP 3 (now IEEE Standard 1815) remains dominant.
Source: Newton-Evans Research Co. “Global Study of Data Communications Usage Patterns and Plans in the Electric Power Industry.” For additional information, visit www.newton-evans.com.
Current and planned use of protocol(s) from the sub-station to external EMS/SCADA/DMS host/network. (Source: “The World Market Study of SCADA, Energy Manage-
ment Systems and Distribution Management Systems in
Electric Utilities: 2010-2012, Volume 1: North American Market,”
Newton-Evans Research Co.)
0% 20% 40% 60% 80%
Leased line
Dial-up
Frame relay
Power line carrier or BPL
Fiber/SONET
T-1 or other multiplexer
Internet (IP)
Microwave
Spread-spectrum multiple...
Licensed radio
Satellite
Cellular (CDMA)
Cellular (GSM)
Cellular (UMTS)
Wireless 802.11 (a, b, g)
Current By year 2013
www.tdworld.com
18 May 2012 l Transmission & Distribution World
detection, isolation and restoration for managing outages.
“Trying to extract the same level of information from siloed,
proprietary networks adds operational cost and employee
resources,” Amberkar said. Additionally, he noted, the lay-
ered architecture of Cisco’s fi eld area network not only offers
utilities the fl exibility to deploy multiple applications over
common network infrastructure but also the ability to sup-
port both wired and wireless communications over the same
converged network.
“When we decided to build a smart grid platform, the
whole point was to serve multiple smart grid applications, not
just one given solution,” Silver Springs’ McLean said. Along
with networking equipment and back-offi ce software, Silver
Spring sells communications modules, essentially network
cards, third parties can embed in other smart grid devices.
Essentially, Silver Spring builds the middle layer of the eco-
system, McLean explained.
“Our hardware partners plug in underneath, and our soft-
ware partners plug in on top.” McLean said. “We make a
great advanced metering system but not the meters. We part-
ner for all our meters and put our communications module in
those meters.” And the same goes for other smart grid appli-
cations, she said, “We’re meter agnostic, DA device agnostic,
load control switch agnostic, electric-vehicle charging station
agnostic; just plug in our communications module, and they
run over our platform.”
Of course, said McLean, these are not either/or decisions
for most Silver Spring customers “because they’re leveraging
the same infrastructure they use for smart meters to deploy
DA applications.” That is, they can use the information gath-
ered by their smart meter (that is, voltage readings) to feed
the same telecom infrastructure to operate multiple systems
— such as water and gas — in addition to electricity, it lowers
the overall cost.” He cites growing utility interest in outdoor
lighting control as an example. Landis+Gyr’s FlexNet system
could be used to dim streetlights, turn them up or turn them
off, or for emergency notifi cation, thus helping to spread the
cost of the system over multiple applications, Lubkeman
said.
Of course, if utilities want more functionality in their tele-
com systems, they will need to add more processing power
and more memory to those systems, and they will need the
ability to update application and security software wherever
and whenever they need it. As such, Landis+Gyr’s Hernan-
dez said the ability to do “over-the-air updating” is vital.
Multiple ApplicationsSanket Amberkar, senior manager of smart grid market-
ing at Cisco, says utilities face two common problems:
● Networks designed for AMI cannot support the more
demanding needs of DA.
● There is a lack of interoperability between proprietary
legacy telecom systems.
According to Amberkar, rather than periodically replac-
ing those underlying networks to resolve the fi rst problem,
utilities seek a telecom infrastructure that protects their in-
vestment by scaling to meet future applications. To solve the
second problem, utilities need an open standards-based com-
munications infrastructure that can share information from
multiple sources.
For instance, Amberkar said, AMI information integrated
with distribution management systems can improve fault
Cisco maintains that a robust, single converged network infrastructure, supporting telephone, video and data communica-tions — along with multiple applications — provides investment protection and will increase the return on investment over time.
Connected Grid Field Area Network Solution
Lower CapEx/OpEx on a multi-service platform
Cost saving fromconverged platform
New value from functional integration
Residentialmetering
Transformermonitoring
Distributionautomation
EV charginginfrastructure
Large C&I meters
Work forceautomation
Distributedgeneration
Distributionprotection andcontrol network
Customerportal
MDM Loadcontrol
SCADA DMS
CIS/billing AMIhead-end
EMS OMS
New
NMS
GatewayProtection and
control network
RF/PLCmesh
Substation
www.tdworld.com
20 May 2012 l Transmission & Distribution World
DA applications. “Conservation voltage reduction applica-
tions are better tuned with better end-of-line data from smart
meters,” she added. “But yes, there is a strong business case
with DA to be sure.”
Standards-Based Approach“Interoperability comes from standards-based approach
(that’s an overused phrase, of course, and it goes much deeper
than IP),” said Grid Net’s Truitt. “The industry has accom-
plished much in the way it catalogs grid assets (IEC CIM
61970) and interacts with other grid applications (IEC CIM
61968). Indeed, he said, Grid Net built those very same mod-
els into its web services layer to provide a standards-based
interface to its applications, legacy systems “and even appli-
cations that have yet to be built.” So, he asked, “Why reinvent
the wheel when the industry has already defined its preferred
approach?”
“There is going to be some networking standardiza-
tion,” Truitt said, but the real story will be in the explosion
of smart grid applications. “Our next-generation system has
more processing capability just because of that,” he said. For
example, look at the iPhone. People buy it not to make calls
but rather because of the multiple applications that run on it,
Truitt explained.
“It’s the same with Landis+Gyr’s next-generation plat-
form,” Truitt said. “It allows several applications to run on the
same hardware, which actually leverages the mesh network
through the concept of distributed intelligence.” The industry
is going to move away from command control at central loca-
tions and push decisions lower in the network, he said.
In a recent speech to the Federal Energy Regulatory Com-
mission, George W. Arnold, national coordinator for smart
grid interoperability at the National Institute of Standards and
Technology, said the vision of a truly smart grid “requires a
movement away from proprietary systems to interoperable
systems based on open standards.” Without such standards,
he added, “There is the potential for technologies now be-
ing implemented with sizable public and private investments
to become prematurely obsolete or be implemented without
adequate security.”
Voluntary vs. MandatoryTo develop those standards, the National Institute of Stan-
dards and Technology established a public-private partner-
ship called the Smart Grid Interoperability Panel to continue
development of interoperability standards and drive longer‐
term progress. The panel produces and maintains a catalog of
standards that now contains six entries related to high-priori-
ty standards for smart grid interoperability:
l Internet-protocol standards, which will allow grid de-
vices to exchange information
l Energy usage information standards, which will permit
consumers to know the cost of energy used at a given time
l Standards for vehicle-charging stations
l Use cases for communication between plug-in vehicles
and the grid
l Requirements for upgrading smart meters
l Guidelines for assessing standards for wireless commu-
nications devices.
Still, Arnold acknowledged the pressure for faster imple-
mentation of the standards: “With 3,200 electric utilities and
hundreds of suppliers from industries that have never before
had to work together, provisions in [the Energy Independence
and Security Act of 2007] reflect a desire by policymakers
that this transition take place in a timely manner, which may
not happen if left entirely to market choice, and that regula-
tion might need to play a role in making it happen.”
As such, said Arnold, “An important question the com-
mission should seek to understand is whether the smart grid
standards will be adopted by industry in a timely way or
whether it is necessary for the commission to use its regula-
tory authority to encourage their use.”
Lee Harrison has been writing about the power industry since 1978.
He has been an editor for Business Week, a researcher with EPRI and a
freelance writer, writing articles for The New York Times and the EPRI Jour-
nal. Harrison holds a bachelor’s degree in engineering from Northeastern
University and a master’s degree in journalism from Columbia University.
He is a former writing instructor at Massachusetts College of Liberal Arts.
Companies mentioned:Alcatel-Lucent | www.alcatel-lucent.com
Black & Veatch | www.bv.com
Cisco | www.cisco.com
Federal Energy Regulatory Commission
www.ferc.gov
Grid Net | www.grid-net.com
Landis+Gyr | www.landisgyr.com
National Institute of Standards and Technology
www.nist.gov
Newton-Evans Research Co. | www.newton-evans.com
Sensus | www.sensus.com
Silver Spring Networks | www.silverspringnet.com
Trilliant | www.trilliantinc.com
DNP 3.0 LAN
DNP 3.0 serial
IEC 61850 (UCA 2/MMS)
Modbus serial
TCP/IP
ICCP/MMS
Legacy/other
0 2 4 6 8 10 12
Applications of communications links from substation to control center. Source: “The World Market for Substation Auto-
mation and Integration Programs in Electric Utilities: 2010-2013,”
Newton-Evans Research Co.
The Cisco® Connected Grid portfolio of solutions brings a level
of intelligence to the grid that helps ensure system uptime and
simplifies management. Our Substation Automation solutions,
the Cisco 2000 Series Connected Grid Router and 2500
Series Connected Grid Switch, provide a secure and scalable
communications infrastructure that helps utility operators manage
substation networks more efficiently—and increase the reliability
of power transmission.
Our purpose-built, ruggedized routers and switches are specially
designed for the most demanding substation environments. What’s
more, these solutions deliver:
�� Remote monitoring and management of substation systems for
improved situational awareness and worker safety
�� Investment protection for legacy devices and a migration path
to next generation networks based on IEC-61850 standards
�� Built-in security and threat control for coordinated threat
mitigation and to prevent unauthorized access
�� Multi-services supporting voice, video, data, and controls for
video, data, and controls on a scalable converged network for
improved worker safety and productivity at the substation
�� Extended temperature, EMI, and surge protection to meet IEC
61850-3 and IEEE 1613 standards
With Cisco Substation Automation solutions, you can deliver power
all day—every day. Visit www.cisco.com/go/smartgrid to see what
Cisco Substation Automation solutions can do for you.
© 2012 Cisco Systems, Inc. All rights reserved.
Reliable substation networking solutions that run 24/7. So you don’t have to.
Cisco 2000 Series
Connected Grid Router
Cisco 2500 Series
Connected Grid Switch
www.tdworld.com
20 May 2012 l Transmission & Distribution World
DA applications. “Conservation voltage reduction applica-
tions are better tuned with better end-of-line data from smart
meters,” she added. “But yes, there is a strong business case
with DA to be sure.”
Standards-Based Approach“Interoperability comes from standards-based approach
(that’s an overused phrase, of course, and it goes much deeper
than IP),” said Grid Net’s Truitt. “The industry has accom-
plished much in the way it catalogs grid assets (IEC CIM
61970) and interacts with other grid applications (IEC CIM
61968). Indeed, he said, Grid Net built those very same mod-
els into its web services layer to provide a standards-based
interface to its applications, legacy systems “and even appli-
cations that have yet to be built.” So, he asked, “Why reinvent
the wheel when the industry has already defined its preferred
approach?”
“There is going to be some networking standardiza-
tion,” Truitt said, but the real story will be in the explosion
of smart grid applications. “Our next-generation system has
more processing capability just because of that,” he said. For
example, look at the iPhone. People buy it not to make calls
but rather because of the multiple applications that run on it,
Truitt explained.
“It’s the same with Landis+Gyr’s next-generation plat-
form,” Truitt said. “It allows several applications to run on the
same hardware, which actually leverages the mesh network
through the concept of distributed intelligence.” The industry
is going to move away from command control at central loca-
tions and push decisions lower in the network, he said.
In a recent speech to the Federal Energy Regulatory Com-
mission, George W. Arnold, national coordinator for smart
grid interoperability at the National Institute of Standards and
Technology, said the vision of a truly smart grid “requires a
movement away from proprietary systems to interoperable
systems based on open standards.” Without such standards,
he added, “There is the potential for technologies now be-
ing implemented with sizable public and private investments
to become prematurely obsolete or be implemented without
adequate security.”
Voluntary vs. MandatoryTo develop those standards, the National Institute of Stan-
dards and Technology established a public-private partner-
ship called the Smart Grid Interoperability Panel to continue
development of interoperability standards and drive longer‐
term progress. The panel produces and maintains a catalog of
standards that now contains six entries related to high-priori-
ty standards for smart grid interoperability:
l Internet-protocol standards, which will allow grid de-
vices to exchange information
l Energy usage information standards, which will permit
consumers to know the cost of energy used at a given time
l Standards for vehicle-charging stations
l Use cases for communication between plug-in vehicles
and the grid
l Requirements for upgrading smart meters
l Guidelines for assessing standards for wireless commu-
nications devices.
Still, Arnold acknowledged the pressure for faster imple-
mentation of the standards: “With 3,200 electric utilities and
hundreds of suppliers from industries that have never before
had to work together, provisions in [the Energy Independence
and Security Act of 2007] reflect a desire by policymakers
that this transition take place in a timely manner, which may
not happen if left entirely to market choice, and that regula-
tion might need to play a role in making it happen.”
As such, said Arnold, “An important question the com-
mission should seek to understand is whether the smart grid
standards will be adopted by industry in a timely way or
whether it is necessary for the commission to use its regula-
tory authority to encourage their use.”
Lee Harrison has been writing about the power industry since 1978.
He has been an editor for Business Week, a researcher with EPRI and a
freelance writer, writing articles for The New York Times and the EPRI Jour-
nal. Harrison holds a bachelor’s degree in engineering from Northeastern
University and a master’s degree in journalism from Columbia University.
He is a former writing instructor at Massachusetts College of Liberal Arts.
Companies mentioned:Alcatel-Lucent | www.alcatel-lucent.com
Black & Veatch | www.bv.com
Cisco | www.cisco.com
Federal Energy Regulatory Commission
www.ferc.gov
Grid Net | www.grid-net.com
Landis+Gyr | www.landisgyr.com
National Institute of Standards and Technology
www.nist.gov
Newton-Evans Research Co. | www.newton-evans.com
Sensus | www.sensus.com
Silver Spring Networks | www.silverspringnet.com
Trilliant | www.trilliantinc.com
DNP 3.0 LAN
DNP 3.0 serial
IEC 61850 (UCA 2/MMS)
Modbus serial
TCP/IP
ICCP/MMS
Legacy/other
0 2 4 6 8 10 12
Applications of communications links from substation to control center. Source: “The World Market for Substation Auto-
mation and Integration Programs in Electric Utilities: 2010-2013,”
Newton-Evans Research Co.
www.tdworld.com
22 May 2012 l Transmission & Distribution World
New Demands, New Technologies, New Partnership
By John R. Janowiak, International Engineering Consortium
Utilities have been dared to radically
change the power-delivery business,
and they have taken that challenge.
Smart grid deployments are modernizing
the century-old electric grid. This incred-
ible undertaking requires the electric utility
and information and communication tech-
nologies (ICT) industries to work together
like never before.
The International Engineering Consor-
tium (IEC) conceived the Grid ComForum
conference series to enhance this relation-
ship. Now we are particularly excited about
IEC sponsoring this T&D World supplement, which provides
a snapshot of key utility strategy issues, what utilities are
experiencing in smart grid deployment and how the smart
grid ICT market is shaking out.
From the ICT industry viewpoint, the electric utility in-
dustry offers diverse and sustainable growth opportunities.
Utilities have spent more than US$3 billion annually on tele-
communications equipment and services during the last two
years, an increase of 21% over 2009 levels. These expendi-
tures are expected to approximately double by 2016, primarily
in support of the 65 million smart meters expected to be de-
ployed by 2020. That is good news to the U.S. ICT industry.
Smart meters are only part of the big picture. Experts
increasingly agree the biggest benefi ts of the smart grid
will come from improved operations on the utility side and
will require a utilitywide, nearly seamless communications
platform. As a fi rst step toward this goal, most utilities are
deploying advanced metering infrastructure (AMI) to trans-
port latency-tolerant, low-bandwidth metering data.
By regulation, the service usually must be offered to ev-
ery utility customer. That in itself presents a big problem,
because no single communications technology solution
works everywhere, so choosing the right mix of technolo-
gies for AMI alone is daunting. An even bigger challenge
is to construct an enterprisewide communications platform
so that it also provides high-speed, mission-critical data for
grid monitoring and control.
And that is the ICT challenge: The communications plat-
form, which can be made up of many different networks and
technologies, is being asked to provide large quantities of
latency-tolerant meter data, while being available to reliably
send unpredictable high-speed bursts of emergency-grid
control data.
Fortunately, this challenge comes at a time when the tele-
communications industry is sorting through
and focusing on technologies that are adapt-
able to a wider range of applications. These
developments, such as long-term evolution,
also are expected to have a longer life cycle
more fi tting to the investment cycles and
support needs of utilities.
On the other hand, this is déjà vu for
electric utilities. U.S. utilities have been
building large, integrated systems of gen-
eration and electric grids since the early
1900s. They have built in extra capacity in
the face of rapid and uncertain load growth
as well as high reliability standards. They have charted their
way through regulatory spasms and stayed afl oat fi nancially
while continuing to keep rates low compared to other nations
with similar-quality power. As a result, the electric utility
industry has enabled the United States to achieve world lead-
ership in economic and industrial growth for over a century.
Now, utilities are using their system design, construction
and management skills to build communications platforms
to support the smart grid. Not that communications are any-
thing new; utilities already have a combined communica-
tions network in North America second in size only to the
telecommunications industry.
Nonetheless, utilities are dependent on the ICT industry
to get the smart grid done right for the lowest cost. Although
the more operationally critical networks will, in many cases,
be owned by the utility, backhaul services leased from pub-
lic carriers will be required to pipeline enormous amounts
of metering data to central facilities. Of course, utility-
specialized carriers will continue to offer diverse and im-
proved schemes for meter communications.
The bottom line is the utility and ICT industries have op-
portunities to benefi t each other. They have the obligation to
work together for the common good of the nation. And the
growth of smart grid deployments over the last several years
has shown they play together quite well, indeed.
John R. Janowiak is president of the International Engineering Consortium.
With more than 25 years of experience, he leads a team that helps catalyze
progress in the global information industry through educational conferenc-
es and exhibitions. Janowiak is responsible for IEC’s business and market
development activities. He is active with and serves as IEC’s principal liaison
to many information industry corporations and non-profi t organizations. He
also guides the IEC’s university relations and serves as executive director of
the Electrical and Computer Engineering Department Heads Association.
Defy the constraints of time and technology. Deploy Itron’s smart grid solutions
and you turn the grid into an interoperable, enterprise-class network powered by Cisco.
Smart metering. Customer engagement. Advanced distribution applications. You’ll be
able to seamlessly connect applications, devices, infrastructure, customers and whatever
else your future may bring.
www.tdworld.com
22 May 2012 l Transmission & Distribution World
New Demands, New Technologies, New Partnership
By John R. Janowiak, International Engineering Consortium
Utilities have been dared to radically
change the power-delivery business,
and they have taken that challenge.
Smart grid deployments are modernizing
the century-old electric grid. This incred-
ible undertaking requires the electric utility
and information and communication tech-
nologies (ICT) industries to work together
like never before.
The International Engineering Consor-
tium (IEC) conceived the Grid ComForum
conference series to enhance this relation-
ship. Now we are particularly excited about
IEC sponsoring this T&D World supplement, which provides
a snapshot of key utility strategy issues, what utilities are
experiencing in smart grid deployment and how the smart
grid ICT market is shaking out.
From the ICT industry viewpoint, the electric utility in-
dustry offers diverse and sustainable growth opportunities.
Utilities have spent more than US$3 billion annually on tele-
communications equipment and services during the last two
years, an increase of 21% over 2009 levels. These expendi-
tures are expected to approximately double by 2016, primarily
in support of the 65 million smart meters expected to be de-
ployed by 2020. That is good news to the U.S. ICT industry.
Smart meters are only part of the big picture. Experts
increasingly agree the biggest benefi ts of the smart grid
will come from improved operations on the utility side and
will require a utilitywide, nearly seamless communications
platform. As a fi rst step toward this goal, most utilities are
deploying advanced metering infrastructure (AMI) to trans-
port latency-tolerant, low-bandwidth metering data.
By regulation, the service usually must be offered to ev-
ery utility customer. That in itself presents a big problem,
because no single communications technology solution
works everywhere, so choosing the right mix of technolo-
gies for AMI alone is daunting. An even bigger challenge
is to construct an enterprisewide communications platform
so that it also provides high-speed, mission-critical data for
grid monitoring and control.
And that is the ICT challenge: The communications plat-
form, which can be made up of many different networks and
technologies, is being asked to provide large quantities of
latency-tolerant meter data, while being available to reliably
send unpredictable high-speed bursts of emergency-grid
control data.
Fortunately, this challenge comes at a time when the tele-
communications industry is sorting through
and focusing on technologies that are adapt-
able to a wider range of applications. These
developments, such as long-term evolution,
also are expected to have a longer life cycle
more fi tting to the investment cycles and
support needs of utilities.
On the other hand, this is déjà vu for
electric utilities. U.S. utilities have been
building large, integrated systems of gen-
eration and electric grids since the early
1900s. They have built in extra capacity in
the face of rapid and uncertain load growth
as well as high reliability standards. They have charted their
way through regulatory spasms and stayed afl oat fi nancially
while continuing to keep rates low compared to other nations
with similar-quality power. As a result, the electric utility
industry has enabled the United States to achieve world lead-
ership in economic and industrial growth for over a century.
Now, utilities are using their system design, construction
and management skills to build communications platforms
to support the smart grid. Not that communications are any-
thing new; utilities already have a combined communica-
tions network in North America second in size only to the
telecommunications industry.
Nonetheless, utilities are dependent on the ICT industry
to get the smart grid done right for the lowest cost. Although
the more operationally critical networks will, in many cases,
be owned by the utility, backhaul services leased from pub-
lic carriers will be required to pipeline enormous amounts
of metering data to central facilities. Of course, utility-
specialized carriers will continue to offer diverse and im-
proved schemes for meter communications.
The bottom line is the utility and ICT industries have op-
portunities to benefi t each other. They have the obligation to
work together for the common good of the nation. And the
growth of smart grid deployments over the last several years
has shown they play together quite well, indeed.
John R. Janowiak is president of the International Engineering Consortium.
With more than 25 years of experience, he leads a team that helps catalyze
progress in the global information industry through educational conferenc-
es and exhibitions. Janowiak is responsible for IEC’s business and market
development activities. He is active with and serves as IEC’s principal liaison
to many information industry corporations and non-profi t organizations. He
also guides the IEC’s university relations and serves as executive director of
the Electrical and Computer Engineering Department Heads Association.
Life Line 64D | Field Applications 64F | Fire Prevention 64H | Storm Drainage Pipes 64N
MA
Y 2
012
www.tdworld.com
Proactive Measures Reduce Fire Risk
WeÕreÊ#1ÊinÊequipmentÊforÊaÊsimpleÊreason...Safety
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ElEctric Utility OpEratiOnsElEctric Utility OpEratiOns
liFELine
l Born in Waco, Texas.
l Married to Sarah for 39 years and has two children, Jami and
Trey, and four grandchildren, Madylin, Jace, Emery and Laken.
l Enjoys being outside, doing competitive bass fishing, racing
cars, serving as a track chaplain at the Heart of Texas Speedway
and being involved in the church. He raced for 14 years and was
a five-state champion 10 years in a row.
l Describes himself as honest, caring, dependable and versatile.
l Can’t live without his laptop, his truck and his test equipment,
such as a current voltage recorder, amp meter and volt meter.
His service territory has a lot of trees, so he also depends on his
long pole saw and chain saw to restore power quickly.
l Inspired by God and his family. He considers himself a public
servant and gets a lot of satisfaction from helping people.
Early Years I went to work for Oncor when I was 19 years old and grew
to love it. I came from a family of custom home builders, and
I’ve always enjoyed working with my hands.
My first job was as a hole digger operating a pole setter. I
had a probation time of about three months to see if I would
make it in the utility industry. I then graduated into linemen
training and became a senior lineman in 1977. From that
point, I became a serviceman and troubleshooter. I answered
trouble calls and lights-out calls and then served as part of the
restoration effort during storms.
Day in the LifeI’ve worked for Oncor for more than 38 years. My current
title is distribution operations technician (DOT) lead.
On a typical day, I am responsible for more than 100 dis-
tribution feeders. I also manage the vegetation management
budget and maintain all the feeders. There are six other tech-
nicians in my group, and we all work together. Because I’m
an outside DOT, I can go outdoors to help the linemen. It’s a
challenge, and I really enjoy it.
My team soon will be working on a project to update the
downtown distribution system in Waco, Texas. It will be fun to
take an old system and bring it up to the latest technology.
Advanced Meter TechnologyOncor is in the process of deploying advanced meters to its
customers. During the deployment, I was responsible for in-
stalling the radios and routers that collected data from the ad-
vanced meters; that process took about three or four months.
So far, we have gotten good response from our customers.
All of our automated equipment is working and the reliability
is high.
Now our customers are able to go online and get informa-
tion about their peak usage. With the interfacing of AMR and
OMS, we are able to get outage information from the custom-
er. Through pulse-closing technology on the switches, we can
get the lights on before the customer even calls us.
Safety LessonIn 1982, I received a flash burn from a lightning arrester. I
was running some jumpers and the lightning arrestor faulted,
resulting in a phase-to-phase flash. Back then, I wore a T-shirt
and my sunglasses to work instead of all the personal protec-
tive equipment we have today. I tried to block my face with
my arms, but I still received burns to my chest, face and my
forearms. I had the chance to really think about safety during
the time I was in the hospital recovering.
I’m now a safety champion. I’m concerned about my fellow
workers and don’t want them to go through the same thing
that I did. We have weekly safety meetings, and we read about
incidents and accidents. At Oncor, safety is first and foremost.
We are our brother’s keeper, and we watch out for each other.
We want everyone to go home to their families in the same
condition that they came to work.
Memorable StormIn 2005, I worked on restoring power following Hurricanes
Katrina and Wilma. There were a lot of trees down, and we
helped to rebuild the lines.
When it comes to storm restoration, my company is second
to none. I get a feeling of satisfaction, and I’m very proud to be
part of that. When we roll into these towns for storm restora-
tion, we have that kind of reputation.
Career-Defining MomentWhen they offered me the lead DOT job, it was one of the
most exciting times in my career. The technology and automa-
tion was right up my alley. I thought I could make a bigger
impact in this position than a lineman building lines.
As for the future, I want to use any technology I can to
improve our system and increase reliability.
Jim Fielding Oncor
Jim Fielding is one of Oncor’s lead distribution operations technicians helping to bring new technologies to the distri-bution smart grid system.
Drawing on the experience gained from over 100 years designing and manufacturing accessory products for deployment by electric power utilities, AFL strives to provide superior product performance that improves the
reliability of the critical electrical and optical infrastructure used for the transmission and distribution of electricity.
4VCTUBUJPO�t�5SBOTNJTTJPO�t�.PUJPO�$POUSPM�t�8JSF�1SPEVDUT"FSJBM�$BCMF�)BSEXBSF�t�/FUXPSL�6OEFSHSPVOE�t�5PPMT�BOE�$PNQPVOET�t�3BJM�5SBOTJU
If you need one company with the experience, integrity and technical expertise to supply your critical infrastructure needs, call AFL.
www.AFLglobal.com
800-235-3423
*.1"$$5®�*NQMPTJWF�5FDIOPMPHZ $POEVDUB$MFBO® )*#64®�)JOHFE�#VTIJOH�4ZTUFN
quickly and easily on existing 5/8- and 3/4-inch bolts, and re-
places the existing washer by design.
A team with an extensive background in construction safety
designed the device, which was then manufactured in Renton,
Washington. Before launching it into the market 18 months
ago, Utility Safety Technologies first had it tested by the same
lab that works with Boeing and NASA. The M.U.T.T. met all of
the OSHA and ANSI testing standards.
Protecting LinemenSome utilities are creating a standard requiring linemen to
install the M.U.T.T. device on every new structure when they
dress them out. On new poles, this device can be specified at
predetermined, key locations on a utility structure to improve
linemen’s safety and efficiency. It can be installed quickly on 5/8- and 3/4-inch through bolts.
Right now, Potelco and other companies are showing inter-
est in the device. For example, Southern California Edison
has made a commitment to retrofit all of its poles over the
next five years with the M.U.T.T. devices. As the linemen go
out into the field to maintain the poles, they will place the
M.U.T.T. devices on the existing poles at the cut-out location.
To showcase the new tool to more utilities, Utility Safety
fieldApplications
electric Utility OperatiOns
By rob carrigan, Potelco
Linemen confront transformers, crossarms and low-
voltage wiring when climbing structures. To get
around these obstructions, they often unhook their
belts, putting them at risk for a fall hazard. Because
they sometimes have nothing to tie off to, they can slip off of a
structure, causing serious injury or death.
To maximize the safety of its linemen, Potelco recently field
tested a device called the Multi-Use Technical Tool (M.U.T.T.)
from Utility Safety Technologies. Potelco, a Quanta Services
company, maintains the lines and performs all of the trans-
mission and distribution work for Puget Sound Energy in the
Pacific Northwest.
One year ago, Potelco implemented a pilot program. The
company then ordered 60 of the devices for its foremen to use
out in the field.
Tool of Many UsesFollowing the field testing, the linemen responded favor-
ably to the M.U.T.T. because of its versatility. The device can
handle rigging, hoisting, rescue, fall protection and other
applications such as securing tools and equipment.
One reason why the Potelco linemen began using the
M.U.T.T. is to adhere to the restrictions when working hot on
Puget Sound Energy’s system. Linemen can install the M.U.T.T.
on the backside of the through bolt at the cut-out points. They
can then hook off to the device and work 360 degrees around
a structure without getting within the 5-ft minimum clearance
of the live line. If they do get within this distance, they need to
use gloves, hot sticks, sleeves and covers for protection.
In addition to being used as a secondary tie-off point, the
M.U.T.T. can be used to lift up to 2,500 lbs up a structure. Line-
men also can use the device on substation steel lattice or fiber-
glass structures.
Fall ProtectionQuanta and Potelco require their linemen to wear 100%
fall protection. When they can get into the working position
and attach themselves to the M.U.T.T., they are then free to
work on both sides of the pole without any restrictions. When
they work on a structure, they can pre-install the M.U.T.T.
devices on the ground or in the air as an attachment point
rated for fall restraint.
The linemen also no longer need to sling a strap around
one of the obstacles to circumvent it. The M.U.T.T. installs
Linemen Improve Climbing Safety
May 2012 | www.tdworld.com64F
The M.U.T.T. is a tool of many uses. Here a lineman uses the M.U.T.T.
as fall protection to ensure he goes home to his family every night.
The company is also donating $1 of each sale
of the product to its nonprofit organization called
the Believe Foundation. These funds help to sup-
port the families of linemen who are injured or
killed on the job site. For example, the board of
directors gives families money for groceries, bills
and college tuition for their children.
By giving linemen a secure attachment point,
UST is working to help protect linemen at not
only Potelco but companies nationwide. This tool
can also help linemen to be more productive and
get more accomplished without sacrificing safety
on the job site.
Rob Carrigan ([email protected]) is a foreman
in a line crew working for Potelco. Potelco, a
Quanta Services company, provides services to
Puget Sound Energy in the Puget Sound Region
of western Washington. He has been in the indus-
try for 25 years.
ElEctric Utility OpEratiOns
Technologies is donating 100 of its M.U.T.T. tools to the
International Lineman’s Rodeo. Each of the competitors in
the pole-top rescue event be able to use the M.U.T.T. for rig-
ging and fall protection during the competition as they reach
their working position, said Mark Hendricks of Utility Safety
Technologies.
Companies mentioned:Potelco | www.potelco.net
Puget Sound Energy | www.pse.com
Southern California Edison | www.sce.com
Utility Safety Technologies | www.utilityanchor.com
1.800.435.0786www.greenleeutility.com
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Rigging, hoisting and securing equipment, tools and material, the M.U.T.T. is versa-
tile on wood and steel structures, providing efficiency, quality and safety for today’s
highly skilled linemen.
ElEctric Utility OpEratiOns
May 2012 | www.tdworld.com64H
SDG&E Implements Fire-Prevention ProgramCalifornia utility develops proactive measures to reduce fire risk and enhance emergency response.
By lena Fotland, San Diego Gas & Electric
After several wild�res caused major damage to San
Diego Gas & Electric Co.’s (SDG&E) electrical sys-
tem in 2007, the utility developed a Community
Fire Safety Program to enhance power line safety,
mitigate �re risk, increase system reliability and help the re-
gion’s overall emergency preparedness.
Over the last �ve years, the utility has made signi�cant en-
hancements in system design, operational procedures, and
supplemental inspection and maintenance practices. SDG&E
implemented these changes to increase safety and to reduce
the potential for electrical facilities to be an ignition source
for wildland �res. The company, which supplies energy service
to 3.4 million consumers through 1.4 million electric meters
and more than 850,000 gas meters, continues to focus on re-
ducing �re risk throughout its 4,100-sq-mile service area.
Educating the Community and the WorkforceOne of the �rst efforts SDG&E undertook to reduce �re
risk was community outreach and education. Today, the San
Diego utility partners with 53 �re agencies, �re safe councils,
Community Emergency Response Teams (CERTs) and other
community organizations. For example, the American Red
Cross, 2-1-1 San Diego and the Burn Institute provide resourc-
es and information on disaster preparedness and living with
�re danger.
The utility also invited its customers and community lead-
ers to participate in a �re safety collaboration process. About
40 stakeholders — representing local schools, water districts,
disability rights advocates, consumer groups and �re depart-
ments, among others — worked with SDG&E for more than a
year to develop a joint �re-prevention plan. The process was fa-
cilitated by a federal mediator.
The outcome: the group pro-
posed more than 100 potential
solutions to help prevent major
�res.
SDG&E already is imple-
menting many of the solutions
identi�ed by stakeholders, such
as turning off reclosers, hard-
ening its overhead electrical
system through the use of steel
poles and larger conductor, and
undergrounding portions of
the system where feasible.
In addition to working with
regional stakeholders on �re-
prevention measures, SDG&E
has trained every employee
and contractor involved in day-
to-day operations on �re pre-
vention and �re suppression.
Further, the company has out-
�tted its vehicles with light-duty Following the 2007 wildfires, dedicated crews worked around the clock to get the power back on.
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ElEctric Utility OpEratiOns
May 2012 | www.tdworld.com64J
fire-suppression equipment, such as shovels and small water
pumps, so field crews have the tools to extinguish a spot fire,
if necessary.
Enhancing Vegetation ManagementSDG&E also has reduced its fire risk by increasing tree trim-
ming and brush clearing in high-risk fire areas. For example, it
has increased the frequency of its tree inspections and hazard
tree evaluations. In addition, recent regulatory changes have
increased minimum clearance requirements between trees
and power lines in the Fire Threat Zone (FTZ), thereby re-
quiring greater clearances at time of trim.
SDG&E maintains clearance for more than 400,000 trees
near power lines; nearly 100,000 of these trees are located
in the Highest Risk Fire Area (HRFA). The HRFA was deter-
mined using Cal Fire data and is defined as the area within
SDG&E’s service territory where the combination of poten-
tially high winds, vegetation and overhead facilities create the
most critical fire hazard.
Compounding the challenge, more than 16,000 wood
poles within the HRFA have “non-exempt” equipment, which
means they represent a potential fire-ignition risk. As a result,
SDG&E crews routinely must clear away the brush from the
base of these poles to mitigate the fire risk. The company is
replacing some non-exempt equipment, where feasible, with
more fire-resistant equipment.
In acknowledgement of the utility’s extensive vegetation
management efforts, the National Arbor Day Foundation has
named SDG&E a Tree Line USA utility for 10 years in a row for
demonstrating “best practices in utility arboriculture.”
Revising Rules for Overhead LinesRegulatory changes also have been a factor in SDG&E’s
success with fire prevention. With SDG&E’s urging, the Cali-
fornia Public Utilities Commission (CPUC) initiated an Order
Instituting Rulemaking (OIR) to improve fire safety statewide.
To date, SDG&E has implemented the OIR Phase 1 enhance-
ments, such as increasing the minimum vegetation clearance
for the area of San Diego County deemed by Cal Fire to be the
FTZ. Cal Fire is the statewide fire agency responsible for fire
protection in largely rural, state responsibility areas. The com-
pany is also increasing the frequency of patrol inspections for
electric distribution circuits in the FTZ. Further, the CPUC or-
dered communications infrastructure providers (CIPs), whose
equipment is attached below the power lines on utilities’ poles,
to perform patrol inspections. Those inspections were com-
pleted by the CIPs Sept. 30, 2010.
On Jan. 12, 2011, the CPUC approved the safety OIR Phase
2 enhancements, which included adding pole-loading criteria
as well as clarifying vertical clearance requirements. Phase 2
also required additional patrol requirements for CIPs.
Hardening the SystemSince 2007, SDG&E has implemented transmission system
hardening projects such as replacing wood poles with steel
poles and installing stronger multistranded steel core con-
ductors. The company has increased vertical and horizontal
spacing of conductors, and its steel structures are designed to
withstand higher wind speeds. To date, the utility has invested
about $200 million to replace more than 1,650 transmission
wood poles with steel. Over the next five years, SDG&E plans
to invest more than $900 million to harden all transmission
lines currently on wood poles in the FTZ. In addition, SDG&E
now also is focusing its hardening efforts on its distribution
equipment. Since February 2011, all new and replacement dis-
tribution poles in the FTZ must be steel. To date, SDG&E has
installed or replaced more than 850 distribution poles.
SDG&E has expanded its inspections of overhead lines,
poles and associated equipment. In 2009, SDG&E inspected
60,000 power poles in the FTZ, looking for conditions that
could create a fire-ignition risk and made necessary modifica-
tions. The ongoing special inspections are done every three
years, even though the required inspection cycle is five years.
The company is using smart technology to reduce fire risk.
For example, SDG&E has installed more than 160 S&C Elec-
tric IntelliRupter PulseCloser switches to protect lines. The
utility also has acquired and analyzed LiDAR laser-scanning
data for every transmission line and structure in the HRFA
to identify potential clearance issues. In addition, SDG&E has
notified the third-party utilities (CIPs) that have equipment
attached to its poles when there are conductor clearance viola-
tions and has followed up to make sure the CIPs have made
the necessary corrections.
The utility has completed undergrounding of several seg-
ments of lines in the HRFA and plans to do more in the future.
In fact, in its General Rate Case, which will establish funding
levels for the next four year, SDG&E requested approval of
funding for the conversion of selected overhead facilities to
SDG&E has increased the frequency of line inspections in the Fire Threat Zone.
ElEctric Utility OpEratiOns
www.tdworld.com | May 2012 64K
underground as part of its continued focus on mak-
ing its system more fire safe.
SDG&E, in an ongoing project, has analyzed, de-
veloped plans and taken action to harden selected
long spans of conductor, adding specialized equip-
ment designed for improved fire safety. These include
Fault Tamer fuses, a type of fuse that doesn’t expel
any parts or sparks during a circuit interruption, as
well as wireless fault indicators to better support vis-
ibility of faults on the electrical system.
Creating Enhanced Response MeasuresIn addition to hardening its electrical system,
SDG&E brings in contract firefighters to serve as
a Utility Wildfire Prevention Team to accompany
SDG&E crews during high fire-risk conditions to pro-
vide immediate fire suppression in case of a utility-
caused ignition. Contracts for 2010 and 2011 covered
transmission and distribution activities and staffed up
to eight fire engines and crews. For 2012, similar con-
tracts are in place and are being implemented. This approach
provides early fire detection and rapid response because the
team is on standby during hazardous fire weather conditions.
The company also can deploy the team during outage restora-
tion or other work on power lines.
Another way SDG&E can respond quickly to emergencies is
with its Erikson Air-Crane S64F helitanker, also known as the
“Sun Bird.” This heavy-lift helicopter plays a dual role by assist-
ing with the construction of SDG&E’s 500-kV Sunrise Power-
link project as well as fire suppression. The utility has entered
into cooperative agreements with local fire agencies — both
city and county — to use this helicopter as needed. The Erick-
son Air-Crane has a 2,500-gallon tank, a 2,000-gallon bucket
and a refill capability of just 50 seconds, which gives fire agen-
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ElEctric Utility OpEratiOns
May 2012 | www.tdworld.com64L
cies additional support for initial attack.
In September 2010, at the request of Cal Fire, SDG&E dis-
patched the helitanker to the Cowboy Fire in east San Diego
County, where it made 62 water drops totaling 87,000 gallons,
or enough water to fill 174 fire trucks. This was a successful in-
tegration of the giant bird with other air attack efforts on the
fire. A similar Erickson Air-Crane helicopter, which SDG&E
had leased for power line construction, was sent to help fight
the Eagle Fire over five days in July 2011. During this event,
the utility’s helitanker made 356 water drops, which equaled
178,000 gallons.
SDG&E also has developed a dedicated staff of five fire
coordinators, all of whom have long-term experience as fire
chiefs with state, federal and local fire agencies. Their role in
the utility is to coordinate training and also respond to fires
throughout its service territory. Among other fire-prevention-
related activities, they educate and train SDG&E linemen on
how to respond safely to substation, transformer and oil fires.
SDG&E has also formed a Reliability Improvement Team to
focus on overall fire-risk reduction in the HRFA.
SDG&E’s Weather Station NetworkSDG&E continues to manage its weather station network
(see “Linemen Deploy Smart Grid Technology,” T&D World,
September 2011). The company employs two meteorologists
to monitor and forecast potentially hazardous weather condi-
tions to improve its operational readiness. So far, the utility
has installed at least one SDG&E-owned and -operated Camp-
bell Scientific anemometer weather station on every circuit in
the HRFA, with redundant communications via cellular and
SCADA connections. The utility also continuously monitors
existing Remote Automated Weather Stations within the ser-
vice territory.
With these kinds of additions, SDG&E now owns and oper-
ates the third-largest and the densest nongovernmental weath-
er network in the United States. SDG&E has 128 fixed weather
stations as well as eight portable weather stations, which re-
port weather data every 10 minutes, for a total of 130,000 data
points daily, providing real-time information for operations,
forecasting ability and research. SDG&E makes this data avail-
able to the public via the National Oceanic and Atmospheric
Administration to support research, the community and first
responders. SDG&E also has six back-country weather camer-
as that stream live video back to a central control center where
operators can see the actual hazardous weather conditions for
better operational decision making.
Putting the Plan to the TestSDG&E has implemented many proactive measures to en-
hance public safety and, as a result, was able to manage the
2011 fire season without any significant events. The utility’s
prevention strategies were tested, however, during a Red Flag
Warning event Nov. 2, 2011.
SDG&E activated its Emergency Operations Center to pre-
pare and monitor the forecasted dry, windy conditions. The
utility contacted about 11,500 customers in the areas where
the winds were expected to be strongest to alert them of the
weather conditions and to advise them the utility could shut off
the power for public safety if the winds exceeded system design
limits. In the end, it wasn’t necessary to de-energize any lines.
SDG&E staged crews, troubleshooters and contract fire-
fighting crews in those areas to shorten response time. The
wind during the event gusted up to about 50 mph in the north-
east portion of SDG&E’s service territory around the Rincon
Reservation. There were no SDG&E-related fires during this
Red Flag Warning, a testament to the utility’s comprehensive
fire-prevention measures and its commitment to public safety,
customer service and reliability.
Looking Ahead SDG&E has made significant progress in reducing system-
wide fire risk, but recognizes there still could be other op-
portunities for improvements to add to its fire-preparedness
program. A team of employees across various departments of
the organization continues to meet biweekly to discuss ways to
improve community outreach, customer education and com-
munication; to explore best practices in vegetation manage-
ment, system hardening and enhanced response measures;
and to find opportunities to expand the SDG&E weather sta-
tion network and/or add new technologies to further improve
situational awareness.
Lena Fotland ([email protected]) is a project
manager in electric distribution operations for San Diego Gas &
Electric. She has been with the company since 2000.
Companies mentioned:2-1-1 San Diego | 211sandiego.org
American Red Cross | www.redcross.org
Arbor Day Foundation | www.arborday.org
Burn Institute | www.burninstitute.org
Campbell Scientific | www.campbellsci.com
Erickson Air-Crane | www.ericksonaircrane.com
San Diego Gas & Electric | www.sdge.com
S&C Electric Co. | www.sandc.com
SDG&E is committed to exploring new technologies and best practices, always looking for ways to enhance system reliability and safety throughout its diverse service territory.
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May 2012 | www.tdworld.com64N
ElEctric Utility OpEratiOns
GTC Breathes New Life into Storm DrainageUtility uses the pipe-in-pipe strategy to extend the lifetime of its substations.
By chip Buttrill and randy Wise, Georgia Transmission Corp.
Electric utility maintenance requires vigilant atten-
tion to the condition of equipment, from the small-
est wires on transformers to the tall towers carrying
transmission lines. In addition to constant exposure
to weather conditions and vegetation encroachment, mainte-
nance professionals must consider the durability and longevity
of equipment and its material components. When facilities are
constructed, a maintenance plan is put in place to ensure that
the investment is protected for at least 40 years.
For Georgia Transmission Corp. (GTC), which plans, builds
and maintains the high-voltage power infrastructure for 39 of
Georgia’s 42 electric membership cooperatives, this requires
periodic inspections, regularly scheduled maintenance and
upgrades to keep the system at peak performance to deliver
safe, reliable electric power. This diligence has helped GTC
achieve an impeccable reliability record.
In some cases, though, electric grids and reliability are
affected by the unexpected. The utility recently turned its
thorough approach toward maintenance to a different kind
of infrastructure: the web of storm drains underneath bulk
transmission substations. In the process, collaboration be-
tween two companies led to groundbreaking innovation, all
without actually breaking ground.
Sinkhole Brings Aging Infrastructure to LightGTC oversees roughly 3,000 miles of transmission lines and
600 substations, including upwards of 60 stations that bear the
electric grid’s bulk load. Many of these bulk-load-serving sta-
tions are part of aging infrastructure built decades ago. Be-
neath the complex network of the electric grid lies an equally
complex network of storm drainage pipes. While the substa-
tions are continuously monitored and receive regular mainte-
A remote-controlled camera goes into the pipe to provide a closed-circuit feed of the interior conditions to guide preparation and repair efforts.
Once in the pipe, the camera delivers images to a technician who is able to visually assess damage and mark locations on the pipe where repairs are needed (top). The camera feed shows where extreme deterioration has created a hole in the corrugated metal pipe (bottom).
Transmission & Distribution Worlds’Vegetation Management Resource Center Sponsored by DuPont Land Management, this online
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ElEctric Utility OpEratiOns
May 2012 | www.tdworld.com64P
nance, the tens of thousands of feet of storm drain infrastruc-
ture beneath them does not.
Evidence in some recent studies indicates that corrugated
metal pipes realistically have a lifespan less than the 40 to 50
years expected at the time of installation. Instead, current es-
timates suggest the lifespan is more likely about 20 years, a
milestone for a significant portion of the infrastructure that
has already come and gone.
The implications of the compromised stability of some of
these pipes became clear when a maintenance team arrived
at one of GTC’s major substations. A deteriorating corrugat-
ed pipe collapsed underneath the wheels of the vehicle and
caused a sinkhole.
In order to repair the pipe, heavy equipment was brought
in to excavate and replace the damaged section. That’s no sim-
ple task when near energized substation equipment. Extensive
and invasive repair procedures presented safety concerns that
had to be addressed, from electrical working clearance issues
to deep excavation of drainage structures in close proximity to
critical substation equipment.
With thousands of feet of pipe surrounding and running
under other crucial substations, GTC considered how wide-
spread the problem might be and how to address it.
Facing the Challenge of Repair and ReplacementPipe failures introduced safety concerns beyond sinkholes.
Collapsed pipes can lead to blockages that result in substation
flooding. Though the equipment is grounded, standing water
is a definite hazard that threatens system reliability.
The substation design’s civil engineering group took on
the task of identifying a solution to the problem of deteriorat-
ing storm drains. The fix for the initial collapse incident — ex-
cavation and replacement — may not work in every instance.
Some affected pipes lie under large equipment, breakers and
energized transformers. Excavation equipment needed to re-
move and replace the damaged pipe could experience clear-
ance issues with parts of the substation and initiate soil settling
that would affect substation foundations. Deep trenches where
piping lay would require reinforcement to prevent collapse.
To resolve these issues using conventional means, a substa-
tion would have to be taken offline, and those that support
Georgia’s 230-kV and 500-kV ranges cannot be taken out of
service without careful planning to mitigate major risk to reli-
ability, especially when excavation, repairs and using the ap-
propriate precautionary measures could take several weeks.
With these challenges, the team considered the possibility
of abandoning the original infrastructure in places where de-
terioration had occurred and rerouting with new pipes. That,
too, came with a list of concerns, including the possibility of
having to regrade the property to ensure proper drainage. In
addition to causing certain engineering problems, both exca-
vation and replacement or abandonment and rerouting came
with a hefty price tag.
Innovative Technique Allows Trenchless RepairThe most efficient and cost-effective solution would be one
that allowed the utility to repair the pipe without excavation.
Through a consultant to the utility, GTC was introduced to
cured-in-place pipe (CIPP) liner. This trenchless method of
pipe repair forms a pipe inside a pipe to repair the damaged
section.
After reviewing a presentation on the technology that had
never been used on behalf of an electric utility, GTC engaged
Southeast Pipe Survey to make the repairs. The Patterson,
Georgia-based company specializes in maintaining and repair-
ing sewer and water lines with services ranging from inspec-
tion, line cleaning, rehabilitation and preventive strategies.
Since 1985, Southeast Pipe Survey has employed the CIPP
technique in hundreds of thousands of linear feet of piping on
behalf of municipal utilities and the private sector. For the first
GTC project, Southeast Pipe installed 640 linear feet of cured-
in-place lining and two catch basins in the Adamsville, Geor-
gia, substation. Georgia Transmission is the first electric utility
for which Southeast Pipe Survey has provided CIPP services.
With CIPP, a custom-made flexible sleeve of polyethylene
mat and fiberglass strand is created and saturated with a ther-
mosetting resin coating. Prior to installation, a camera with a
closed-circuit video feed is inserted into the pipe to verify the
diameter, length, the exact condition of the pipe and active
service connections and their locations. The pipe is cleaned to
remove debris and any protruding taps.
During installation, an overhead rig is used to insert the
inverted tube into the damaged pipe through manhole access.
The crew sets up the base of the overhead rig a short dis-tance from the substation over a manhole where the liner will be fed into the pipe.
ElEctric Utility OpEratiOns
www.tdworld.com | May 2012 64Q
A boiler truck is used to heat the pipe and hot water is forced
through it, turning the inverted sleeve right side out. The flex-
ible material easily navigates bends in the pipe.
A consistent circulated flow of 180°F cures the resin. Slowly,
the water is cooled to a temperature of 100°F and the patch
hardens, restoring the structural integrity of the pipe. The
liner fully cures in about eight hours.
Success and Ongoing Infrastructure RestorationCIPP resolved many of the issues presented by invasive ex-
cavation and replacement. First, CIPP offered a safer way to
address pipe repair that eliminates the need for heavy equip-
ment or extensive digging that can unsettle substation foun-
dations. The overhead rig used during installation maintains
a safe distance from power lines and other sensitive equip-
ment, and minimizes or eliminates environmental concerns.
Before starting the project, GTC collaborated with Southeast
Pipe Survey to ensure all safety concerns were identified and a
detailed plan was in place.
Use of CIPP represents a significant cost savings, as well.
In the first project Southeast Pipe Survey undertook for GTC,
pipe repairs cost 27% less than the estimated cost of pipe exca-
vation and replacement. Those costs did not include necessary
grading and replacement of the ground grid and cable trays
or the gravel dressing that would need to be replaced after
repair and grading.
Ultimately, the cost savings could have been as much as
50%. In the four projects Southeast Pipe Survey completed,
GTC has benefited from an estimated $500,000 in cost savings.
For a cooperative like GTC, cost savings for the utility trans-
lates into cost savings for its members and their customers.
CIPP also minimizes the risk to reliability. In Adamsville,
work was performed during a planned substation shutdown.
To protect system reliability, repairs had to be completed be-
fore the station was re-energized. By preparing a thorough
plan, the repairs were made successfully within the allotted
time. Most CIPP installations can be completed in a day.
Lastly, CIPP reinforces the structural integrity of the pipe
for about 50 years. While the liner reduces the diameter of the
pipe by about 1/8 inch, its smooth interior increases the water
flow in comparison to corrugated metal.
Georgia Transmission’s mission is to deliver safe, reliable
and affordable electric power to its members. In the case of
the CIPP liner repairs, GTC and partner Southeast Pipe Sur-
vey were able to reinforce that by reinforcing the integrity of
the underlying infrastructure without a threat to reliability
and at a significant cost savings.
To date, Southeast Pipe Survey has installed more than
10,500 linear feet of cured-in-place pipe in storm drains at
three substations for GTC. Southeast Pipe Survey is now using
a new technology that uses ultraviolet light to cure the liner.
This new method provides an even faster installation and a
better, stronger finished product. It is being used at the fourth
substation project currently underway and repairs will contin-
ue as GTC identifies the need.
Chip Buttrill ([email protected]), a design services
manager for GTC, manages the engineering department
responsible for transmission line, substation and civil site
designs. Buttrill is a professional engineer.
Randy Wise ([email protected]), a senior civil engineer
for GTC, leads the civil site design group in developing
and implementing design standards and project designs,
conducting quality reviews of project designs, and investigating
process improvement opportunities with new technologies.
Wise is a professional engineer.
Companies mentioned:Georgia Transmission Corp. | www.gatrans.com
Southeast Pipe Survey | www.southeastpipe.com
The full set-up requires no excavation or heavy equipment. One truck supports the overhead rig and the other carries the custom-made liner, which is threaded through the overhead rig.
PRODUCTS&Services
ELECTRIC UTILITY OPERATIONS
various sizes and is compact enough for use in small spaces. To operate, users need to properly position the hook
brackets with the chain to accommodate the transformer size. They then tilt the Transformer Dolly forward, allowing the hook brackets to be lowered for attachment to the transformer. Next, they attach the hook brackets to the mount brackets on the transformer. Using the step positioned on top of the pilot wheel, they lean the dolly back. Finally, users must secure the transformer with the hold-down strap.Hi-Line Utility Supply | www.hilineco.com
Load-Rated Lift Bucket
Klein Tools introduces a bucket that is load rated at 150 lbs. The top of bucket zips closed, and its 14-inch diameter accommodates standard 5-gal buckets. The body is constructed of heavy-duty No. 1 canvas. A web strap extends down the side of the bucket, and a leather-reinforced bottom extends 3 inches up the side. It also has a durable steel rim. Klein Tools is offering the bucket both in 17-inch and 22-inch versions.
In addition, the manufacturer has a new Torque Wrench Bucket that is 36 inches high to lift torque wrenches, a Refi nery Bucket with pockets, an All Purpose Work Bucket and a Top Closing Bolt Bag. Klein Tools | www.kleintools.com
Cable Bending Tool
Huskie Tools introduces the SL-CB battery-powered cable bender. The tool uses the pull-pin design, allowing technicians to change jaws from compression to cutting to cable bending. The SL-CB is just one of the many ergonomic solutions provided by Huskie Tools to help reduce strains and sprains associated with the daily tasks of a powerline technician.
The SL-CB has several different settings so the tool can be used on either secondary or primary conductor in a variety of sizes. Featuring a low profi le, the SL-CB can be used in a variety of close-quarter environments, such as underground vaults, meter bases and substation applications, and wherever cable bending is required. Huskie Tools | www.huskietools.com
Transformer Handler
The Hi-Line Utility Supply Transformer Dolly is constructed with high-yield strength steel. It is designed for safe, easy handling of pole-mounted transformers. It can accommodate
Pole & Tower Maintenance
• PoleInspection&Treatment
• PoleRestoration&Upgrading
• Below-GradeCorrosion
Inspection&Repair
Field Surveys & Audits
• NetworkInventory
• Joint-UseAttachmentSurvey
• VisualCodeViolation,Reliability,
SafetyAudit
Osmose knows PolesExperience • Commitment • Innovation
716.319.3423 • osmoseutilities.com • [email protected]
Withmorethan75yearsofdiverseexperienceasafoundation,Osmose
proudlyservesAmerica’sutilitiesastheymanageaginginfrastructureand
buildtomorrow’sintelligentutility.
A Trusted Name in Utilities
Services since 1934
Make-Ready Services
• PoleLoading&ClearanceAnalysis
• PoleReplacementDesign
ELECTRIC UTILITY OPERATIONS
Productivity.
Made in America • Best in the World
800-927-8486 • Fort Worth, Texas
Watson Philosophy:While it is true that “makin’ hole” basicallytranslates to “makin’ money”, it is the overall time on the job that translates into profitability.
From the moment a rig leaves the yard, the clock is ticking on your
profits. Watson rigs not only excel at the drilling itself, but are specifically
designed to reduce the time spent outside the hole.
The 4400 targets big diameter rock drilling, but minimal setup and cycle times are two keys to its success:
• Remote controls and hydraulic pins keep setup/teardown to under an hour.
• Top crowd system = no bar locking down to 40’(the exact same 40’ you
find in just about every hole.)
• Continuous Torque rotary and variable speed hoist reduce cycle time.
• New interchangeable short mast option and superior mobility make short
work of rugged powerline jobs.
Minimizing the time you spend NOT turning to the right.
Short Mastconfigurationnow available.
Lineman’s Work Gloves
Kunz work gloves are sewn in the gunn pattern for extra comfort using strong nylon thread for maximum durability. Reinforced welted thumb seams, Davey tips on the fi ngers and a leather welt at the base of the fi ngers protect seams from opening in critical high wear locations. Three specially tanned heavy-weight (4 oz. plus) grain leathers are used in the manufacture of Kunz work gloves. Each has distinctly different characteristics.
The Foreman’s style glove is designed for light duty and has a 10-inch overall length with an open cuff, making it suitable for jobs needing maximum
dexterity. The Slip-on style is a durable glove for almost any application. The 2-inch split leather safety cuff with its reinforcing wrist pad offers limited arm protection.
The Gauntlet style is the most popular style for line workers. A reinforcing thumb strap makes this design the most durable. The 4.5-inch and 6.5-inch lined split leather cuffs provide different degrees of arm protection. The elastic back secures the glove on the hand, eliminating any possibility of slipping. For extra-heavy-duty applications, 5-oz to 5.5-oz heavy buckskin leather is recommended.
The Wide-Cuff style is designed to accommodate heavy winter clothing requiring additional room in the gauntlet. Palms are constructed the same as the Gauntlet style work gloves. One-fi nger work mittens are also available when extra warmth in cold weather is needed. They feature an inseam sewn with cotton thread and a reinforced thumb strap. The 9-inch-wide split leather lined cuff easily accommodates winter clothing. These work mittens can be worn with different styles of liners for additional warmth. Kunz Glove Co. | www.kunzglove.com
Band Saw
At less than half the weight and size compared to a traditional deep cut band saw, the Milwaukee 2429-21XC M12 Sub-Compact Band Saw provides one-handed power and portability to users cutting small-diameter materials.
The M12 Band Saw weighs 6.75 lbs and measures 12 inches, making it suitable for overhead or one-handed cutting applications. The saw can cut through ¾-inch EMT in 3 seconds and will deliver more than 150 cuts per charge with the included M12 REDLITHIUM XC high-capacity battery. With a 1⅝-inch by 1⅝ -inch cut capacity and low vibration, the M12 Band Saw performs clean cuts on the most common small-diameter metal-cutting applications.
The saw also features a dual-latching lower guard that covers the blade outside the active cutting area, addressing OSHA guarding requirements and making the tool suitable for one-handed use. Milwaukee Tools | www.milwaukeetool.com
www.tdworld.com | May 2012 64S
ElEctric Utility OpEratiOns
PartingsHOt
Photograph by roxy stone, Roxify Studio; Courtesy of Hubbell Power Systems
ElEctric Utility OpEratiOns
May 2012 | www.tdworld.com64T
Linemen Aaron Corbin and Brent Rider from
Capital Electric Line Builders clip in bundle 345-kV
wire as part of a project for Westar Energy.
The utility is building a new 345-kV high-capacity
transmission line from its Rose Hill Substation, about
6 miles southeast of Wichita, Kansas, to the Oklahoma
border. Westar will then connect to Oklahoma Gas &
Electric’s portion of the line. Oklahoma Gas & Electric
will build the transmission line from the Oklahoma
border to its Sooner Substation, about 13 miles
northeast of Perry, Oklahoma.
BOOKS
Book Smart Just Got Smarter.New! Introducing Transmission & Distribution World books. Now you can fi nd books with the very latest Power Utility information and make your purchase online.
Get books on systems, engineering and Code. Shop for handbooks on bushings, monitoring systems and transformers.
You’re just a click away from TDW’s comprehensive book store. Visit BuyPenton.com. Click on the Electrical Systems, Energy & Construction link.
Read on.
May 2012 | www.tdworld.com66
Products&Services
Process Efficiency Software
LumaSense Technologies Inc. has released a suite of off-the-shelf software that will allow manufacturers to improve industrial processes by tightly integrating thermal imaging cameras with a wide range of temperature and gas-sensing technologies.
The LumaSpec R/T software is ideal for industrial segments where critical vessel monitoring and combustion imaging are vital to running processes safely and efficiently. The software is designed to monitor and analyze
processes in real time to help plants improve product quality, lower production costs, and reduce safety hazards and downtime.
Using LumaSpec R/T, plants can set up monitoring applications and seamlessly configure alerts with their control systems. This allows operators to detect and correct process and equipment irregularities before they can cause loss, damage or injury. It can also guide them to cost-saving opportunities through reduced energy usage, improved efficiency and less waste in their processes.
When combined with cameras such as the LumaSense MC320, LumaSpec R/T can accurately measure process temperatures and ensure production quality where individual images would be insufficient. Among others, the software includes features such as camera control functionality via standard or GigE Ethernet interface, power-over-Ethernet real-time image acquisition, thousands of regions of interest (ROI), ROI minimum and maximum alarm setpoints, pop-up display tools and multiple color palettes for optimal image quality.LumaSense Technologies Inc. | www.lumasenseinc.com
Surge Arresters
The new Cooper Power Systems UltraSIL polymer arrester improves energy-handling capability, increases creep distance and provides superior — up to 15% Margin of Protection (MOP) over common industry offerings — equipment protection in a lightweight polymer arrester.
The three levels of energy-handling capability (standard, high and extra high) are ideal for utilities, commercial or industrial applications for protection against repeated high energy switching surges, and provide reliable protection for substation equipment, capacitor banks, multiple lines and cable circuits.
Cooper Power Systems offers customizable options for special applications to meet discharge and protection characteristics to optimize overvoltage protection in specific transformers and to adhere to specific height requirements.
The UltraSIL design also offers SKU reduction benefits; the base unit can easily convert from standard base-mount to suspension or cubicle-mount, so only one product is needed for three applications, and without impacting the seal integrity.Cooper Power Systemswww.cooperpower.com
(800) 515-4040 www.sterlingpadlocks.com
Sterling
Security Systems
A Division Of Engineering Unlimited
Sterling DL-2S-3
Sterling Padlock
Sterling One Shot
We’ve got the lock onaffordable security.
PTZ Dome Camera
Toshiba Surveillance & IP Video Products Group, a business unit of Toshiba America Information Systems, has expanded its IP portfolio with the IK-WP41A Pan-Tilt-Zoom (PTZ) IP dome camera.
Purpose-engineered to provide broad surveillance coverage outdoors, the camera features full 1080p HD video resolution, 20x optical zoom to help identify distant objects, 360-degree continuous pan for overview surveillance, along with high-speed PTZ to precisely follow moving objects.
The camera’s self-contained IP66-rated weatherproof housing protects sensitive electronics from adverse conditions. Power-over-Ethernet 802.3af further simplifies installation since only one Ethernet cable is needed for transmitting video, power and PTZ controls. Plus, because a single IK-WP41A provides as much video coverage as six standard resolution cameras (VGA), it will monitor a much larger area with fewer cameras to reduce installation and maintenance expenses.
With true day/night imaging (IR cut filter) and low-light sensitivity down to 0.3 lux, the IK-WP41A captures detail-rich video even in near-total darkness. H.264 video compression preserves bandwidth on the network while streaming full-frame 1080p resolution video at 30 frames per second. Dual-streaming H.264 and MJPEG lets the camera simultaneously produce high-quality 720p images for live viewing and recording plus transmit JPEG images to a remote server or handheld device. Toshiba | www.toshibasecurity.com
Aluminum Brackets
CHANCE single-phase bolted pole brackets by Hubbell Power Systems offer three configurations in two sizes. Models
include a dual-mount, a single-mount and
a single-L style. For more options,
the system includes an offset
extension that can be added to any model. The 6061-T6 aluminum brackets are fitted with galvanized-steel fasteners. Each bracket is rated for 500 lb (227 kg) and mounts with two thru bolts. Hubbell Power Systems www.hubbellpowersystems.com
www.tdworld.com | May 2012 67
PRODUCTS&Services
Protective Relay Test Set Flame-Resistant Rain Protection
National Safety Apparel rereleases its inventive arc rainwear lines. The Arc Extreme FR rain jacket and overall pant features unique multilayered
material to offer arc protection and breathability. The Nomex layers provide protection from arc fl ash fi res and open fl ames, while the PTFE microporous moisture barrier is wind- and waterproof, along with breathability for additional comfort.
The Arc Extreme Hybrid rainwear line combines arc fl ash and FR protection with ANSI/ISEA 107 compliant high visibility for Class 2 and Class 3 applications. The material is the same breathable fabric used in the Arc Extreme rain apparel and features fl uorescent yellow material and refl ective striping. The jacket is built to minimize exposure of seams to direct moisture impact.
The Arc Extreme and Extreme Hybrid FR rainwear lines meet ASTM F1891 and F2733 standards for arc and fl ash fi re, and include additional safety features, such as a roll-away hood that fi ts over a hard hat and a D-Ring harness opening on the back for fall protection equipment. National Safety Apparel | www.nsamfg.com
Smaller, lighter and with a higher output power than any other comparable three-phase instrument, Megger’s new SMRT 36 smart protective relay test set is ideally suited not only for testing today’s installations and legacy plant, but also for meeting the future challenges associated with testing the smart grid.
The SMRT Power Box is specifi cally designed to test protective relays that are used in conjunction with CTs having 1-A and 5-A secondaries. It combines the capacity to simulate high current faults with the amplifi er precision needed to satisfy demanding requirements.
The instrument has three current output channels, plus three convertible channels that can be confi gured as either voltage or current outputs. This makes it possible, for example, to test numerical current differential relays that require six currents.
Its patented design allows the SMRT 36 to deliver high power in both the voltage and current channels as needed in high-burden applications, such as testing electromechanical relays. The constant power output of the current amplifi ers produces a compliance voltage of 50 V at up to 4 A (200 VA
rms) and
maintains 200 VA output power up to 30 A. Two current outputs can be series connected to double the compliance voltage to 100 V and provide a constant 400 VA output power at 4 A and up.
To facilitate panel testing, and the testing of high-burden electromechanical distance protection relays, the high constant power output is also available from the new PowerV voltage amplifi ers. From 30 V to 150 V, these deliver a constant 150 VA, providing high current output at “diffi cult” low test voltages.
The new SMRT current amplifi ers can deliver 30 A per phase continuous and up to 60 A per phase for short durations. Megger | www.megger.com
68 May 2012 | www.tdworld.com
products & services
help wanted
Join the revolution...Since 1927, Chattanooga-based Sherman & Reilly has been a leading manufacturer
of tools and equipment for underground and aerial transmission, and distribution of
electrical power and communications systems, including a complete line of bundle
blocks, pullers, tensioners and reel trailers.
Sherman & Reilly is growing, and we’re looking to recruit a number of qualified,
talented individuals who possess both the skills and the desire to help build the
company that started it all.
Our goal is simple... “Bring Every Lineman Home, Every Night, No Exceptions.” We
want new members of our team that take this as seriously as we do and to take pride in
partnering with the Power Industry to create products that deliver on our commitment.
We offer competitive compensation, benefits package and a work environment where
principles, openness, and dedication are appreciated and rewarded.
Visit our NEW Website for More Information!
www.sherman-reilly.com
Current Opportunities:
• Regional Sales Managers
• Business Development Manager, Transmission Market
• Mechanical Engineers
• Designers / Drafters
• Welders
• Machine Operators
SHERMAN & REILLYDesigned for Safety. Built to Last.
800.251.7780sherman-reilly.com
The Transmission & Distribution department of R.G. Vanderweil Engineers, LLP based in Boston, has an exciting opportunity for a Transmission Line Engineer to lead a technical staff of 25 people on utility transmission and distribution line projects. Ideal candidates would possess a PE license, civil/structural engineering degree and 15 years prior success in a Consulting or Utility company. Strong leadership and mentoring skills and the ability to work closely with clients is required.
See careers section at www.vanderweil.com for further details and send resume to [email protected]
Industry competitive salary and bonuses, full benefits. EOE employer
Transmission Line Lead Engineer
auctions
JOBzoneThe Industry’s #1 Job Zone
Recruit • Retain • Explore
Finally, a job site created exclusively for the transmission and distribution industry.
http://jobzone.tdworld.com
Superintendent of Substations($6,935 - $10,400)/per month
Please inquire at www.bpu.com
AVAILABLE IMMEDIATELY
This is a partial listing only. More information will be available at
Hilco Industrial LLC, IL License #444.000215
On Behalf Of Preview:By appointment only.
LocationMultiple Locations
in California
For More information please contact:Mark Reynolds at [email protected]
or +1 205 595 5999or
David Barkoff [email protected]
or +1 650 649 0147
www.hilcoind.com / www.hgpauction.com
Onsite turnkey Or fOr relOcatiOn
with Large Inventory of Spare and Replacement Parts
Five (5) Complete 22 MWand One (1) 30 MW Fluidized Bed
Petroleum Coke Power Plants
69www.tdworld.com | May 2012
PRODUCTS & SERVICES
Smart Grid Solutions
• Distribution Management System
• Energy Management System
• Microgrid Master Controller
• Generation Portfolio Management
• Intelligent Geospatial Electrical Views
• Integrated Network Analysis
• Visualization, Control & Optimization
etap.com 8 0 0 . 4 7 7. E TA P | 9 4 9 . 9 0 0 .1 0 0 0
RECRUITING
www.tdworld.com
A vital source of industry information with breaking news and feature archives from the
pages of Transmission & Distribution
World is just one click away!
Need Help?
Need A Job?
Contact Lisa–
TOLL FREE 877-386-1091
Se Habla Español
www.lineal.comElectromechanical • Electronic
Electrical Service & Systems Specialists
LISA LINEAL: RecruitingLINEAL Services
Call or send confidential resume to
MORE THAN 25 YEARS EXPERIENCE!
70 May 2012 | www.tdworld.com
SOFTWARE
But be prepared to explain how you accomplished so much
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For more information about classifi ed advertising, please contact:
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Check us out at
WWW.TDCOMPARE.COM
TD CompareTM is a newly launched resource of up-to-
date product information and new technologies for
the power delivery industry, which allows users to
compare up to fi ve products side-by-side. With
almost 300 vendors and 12,500 detailed product
listings, TD CompareTM is the “Go To” online
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Produced by industry experts, our mission is to
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Midwestern, Mid-Atlantic,New England, Eastern Canada:Stephen M. Lach13723 Carolina LaneOrland Park, IL 60462Phone: 708-460-5925 Fax: 913-514-9017 E-mail: [email protected]
Southeastern, Mid-Atlantic, New England: Douglas J. Fix 590 Hickory Flat Road Alpharetta, GA 30004 Phone: 770-740-2078 Fax: 770-740-1889 E-mail: [email protected] Southwest: Gary Lindenberger 7007 Winding Walk Drive, Suite 100 Houston, TX 77095 Phone: 281-855-0470 Fax: 281-855-4219 E-mail: [email protected] West/Western Canada: Ron Sweeney 303 Johnston Drive San Rafael, CA 94903 Phone: 415-499-9095 Fax: 415-499-9096E-mail: [email protected]
Craig Zehntner 15981 Yarnell Street, Suite 230Los Angeles, CA 91342Phone: 818-403-6379 Fax: 818-403-6436 E-mail: [email protected]
Western/Eastern Europe: Richard Woolley P.O. Box 250Banbury, OXON, OX16 5YJ UKPhone: 44-1295-278-407Fax: 44-1295-278-408 E-mail: [email protected]
Asia: Hazel Li InterAct Media & Marketing66 Tannery Lane#04-01 Sindo Ind BuildingSingapore 347805Phone: 65-6728-2396 Fax: 65-6562-3375 E-mail:[email protected] Japan: Yoshinori Ikeda Akutagawa Bldg., 7-7, Nihonbashi Kabutocho, Chuo-ku, Tokyo 103-0026, Japan Phone: 81-3-3661-6138 Fax: 81-3-3661-6139 E-mail: [email protected] Korea: Y.B. Jeon Storm Associates Inc. 4F. Deok Woo Building 292-7, Sung-san dong, Ma-po ku, Seoul, Korea Phone: 82-2-755-3774 Fax: 82-2-755-3776 E-mail:[email protected] Classified Sales: Susan Schaefer 870 Wyndom Terrace Secane, PA 19018 Phone: 484-478-0154 Fax: 913-514-6417 E-mail: [email protected]
Advertiser Page # Website
*Denotes ads appearing in only certain geographic areas.
Transmission & Distribution World (ISSN 1087-0849) is published once monthly by Penton Media Inc., 9800 Metcalf Ave., Overland Park, Kansas
66212-2216 U.S. Periodicals postage paid at Shawnee Mission, Kansas, and additional mailing offices. Canadian Post Publications Mail Agreement No.
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POSTMASTER: Send address changes to Transmission & Distribution World, P.O. Box 2100, Skokie, Illinois 60076-7800 U.S.
71www.tdworld.com | May 2012
3M . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 www.3m.com/accr
AFL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64e www.aflglobal.com
Alcan Cable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 www.cable.alcan.com
Ampacimon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57 www.ampacimon.com
Black & Veatch . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 www.bv.com
Burndy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31A www.burndy.com
Burns & McDonnell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .IBC www.burnsmcd.com/td
Doble . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 www.doble.com
Doubletree Systems/JSHP Transformer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64 www.jshp.com
Dow Electrical & Telecommunications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 www.dowinside.com
DuPont . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 www.countondupont.com
Engineering Unlimited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 www.sterlingpadlocks.com
Freewave . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 www.freewave.com
FWT Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 www.fwtllc.com
GE Digital Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 www.gedigitalenergy.com
Greenlee Textron . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64G www.greenleeutility.com
Grid One Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . BC www.gridonesolutions.com
Hubbell Power Systems Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 www.hubbellpowersystems.com
Hubbell Power Systems Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 www.hubbellpowersystems.com
Hughes Brothers Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 www.hughesbros.com
Huskie Tools Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 www.huskietools.com
Hyundai Heavy Industries Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 www.hyundai-elec.com
Krenz & Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36-37 www.krenzvent.com
Lindsey Mfg. Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 www.lindsey-usa.com
Lug-All Corp. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .64I www.lug-all.com
Mears Group Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 www.mears.net
Merrick & Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 www.merrick.com
NLMCC/NECA-IBEW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 www.thequalityconnection.org
Nordic Fiberglass Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 www.nordicfiberglass.com
Osmose Utilities Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64R www.osmoseutilities.com
Penton / Wright’s Reprints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 www.wrightsmedia.com
Penton Equipment Auction.com . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51 www.pentonequipmentauctions.com
PowerPD Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 www.powerpd.net
PowerSense A/S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 www.sensethepower.com
Quanta Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 www.quantaservices.com
S&C Electric Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31B www.sandc.com
S&C Electric Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .IFC www.sandc.com
Sabre Industries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 www.sabretubularstructures.com
Sherman & Reilly Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64B-C www.sherman-reilly.com
Siemens AG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 www.siemens.com
Siemens Energy Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 www.usa.siemens.com
Southwire . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 www.southwire.com
T&D World Books . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65 www.buypenton.com
T&D World Grid Optimization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 www.tdworld.com/newsletters
TDW Vegetation Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64O www.tdworld.com/vegetationmanagement
Thomas & Betts/Meyer Steel Structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 www.tnb.com
Thomas & Betts/Utility Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 www.tnb.com
Time Mfg. Co./Versalift . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64K www.versalift.com
Underground Devices Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 www.udevices.com
U.P.T. Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .64M [email protected]
Utilx . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67 www.utilx.com
Valmont/Newmark . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39A www.valmont-newmark.com
Valmont/Newmark . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39B www.valmont-newmark.com
Watson Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64S www.watsonusa.com
May 2012 | www.tdworld.com72
StraightTalk
In-house engineers also inherently understand the organi-
zation’s culture more than contracted entities. BPA as a non-
profit, federal entity has a goal to keep its customers rates as
low as possible. Contract or owner engineers may not always
approach a project from that perspective. Sometimes we might
add value to a project that an outside engineering firm would
not. In instances where our system knowledge contributes to
project design, our savings more than warrant a robust in-
house engineering presence.
One of our most significant in-house success stories to
date has been a redesign of some of our steel lattice towers. A
team of BPA engineers I worked with designed towers that are
stronger, yet use less steel. They’re also sturdier but cheaper.
The icing on the cake: They’re easier to assemble but better
withstand winds and storms. The new designs saved BPA more
than US$11 million on the McNary-John Day line, a 500-kV
79-mile (127-km) line located mostly in central Washington.
Let’s say we can save 10% in project costs by using in-house
engineers versus contract engineers. We have had projects that
cost hundreds of millions of dollars, so if we can save 20 mil-
lion on a project, the in-house staff has paid for their keep.
The Northwest is prone to significant winter wind storms
that can wreak havoc on our system. When we experience
major damage that requires engineers to perform or consult
on system design, it has to happen quickly. This is another ad-
vantage to having seasoned, knowledgeable in-house engineers
who can help save critical hours and minutes when people and
public safety officials are eager to have power restored.
There are many advantages to having a robust in-house en-
gineering staff. We are learning that turnover can take its toll
though. To ensure we keep pace, we have programs to start
working with students in college, and when they complete their
education, they come to work for BPA. We have also learned
that workload does not wait, so we have created a system to
document our processes, procedures and standards so we can
seamlessly pass on critical system knowledge and techniques
to our newer engineers.
BPA has found immense value in its in-house engineering
staff. This staff helps us save money, provide advice and coun-
sel to outside engineers, and seamlessly train and educate new
staff to ensure BPA and its customers a reliable and safe electri-
cal future.
By David Hesse, Bonneville Power Administration
Value of In-House Engineers
Construction of any transmission line and caring for ex-
isting lines and equipment requires the collaboration
of design, engineering and building talents from both
within and outside the utility. External, project or owner engi-
neers play a vital role in determining just how their products
or services fit into overall transmission line design. That said,
there is no substitute for the value of strong in-house engineer-
ing talent within utilities.
At the Bonneville Power Administration (BPA), we own and
operate more than 15,000 circuit miles (24,140 km) of high-
voltage transmission lines on more than 8,500 miles (13,680
km) of rights-of-way across a diverse territory that stretches
across Washington, Oregon, Idaho and western Montana. Our
in-house engineers have broad and long-standing historical
knowledge about system design and other factors that could
impact the system.
The Pacific Northwest has the potential of transmission
system threats — ice, mudslides, seismic activity and other geo-
specific threats — not posed in other areas of the country.
For instance, we have towers designed in the 1970s on which
we’ve experienced many failures related to ice buildup. As staff
engineers, we know that we need to be careful when reconduc-
toring or adding fiber to a line that uses these towers because
adding load could cause additional tower failures. Contractors
may not be aware that historically the stress loads caused by
ice potentially threatens these particular towers. That kind of
institutional and system knowledge can help organizations
avoid unplanned outages and maintain system reliability.
No in-house staff of engineers can design and maintain a
system as large as BPA’s without the help of external and owner
engineers. In-house staff can pass on years of system knowl-
edge to these contractors to ensure they are aware of nuanced
system information. In some cases, because of our system
knowledge, we have found it makes more sense to keep work
in-house. BPA has areas of expertise in, for instance, lattice
tower analysis and design. Another example are our fiber sys-
tems, especially on 500-kV towers. There are significant issues
with electrical fields on these towers, and we have people here
who have made a career of knowing these issues and getting
it right all the time. Knowing what you’re good at helps you to
prioritize what work you should contract to outside entities.
Utility engineering staff must have expertise not only in
what to do and how to do it, but also be able to evaluate the fi-
nal product. Staff engineers need to have significant expertise
to make sure the contract work is being done as it should.
David Hesse ([email protected]) has been a structural
engineer at Bonneville Power Administration since 1991.
2012 Game Changers Lineup
January: Sustainable Substations
March: 3-D Substation Design
April: Distributed Solar
May: Plug-in Hybrid Electric Vehicle
Charging Stations
May: Thermal Measurements on Lines
June: Grid Analytics
July: Smart Grid Communications
August: Enterprise Data Management
September: Standards and Interoperability
October: Marine Renewables
November: High-Voltage Direct Current
.
TECHNOLOGIES, STRATEGIES AND BIG IDEAS THAT ARE RESHAPING OUR WORLD
E n g i n e e r i n g , A r c h i t e c t u r e , C o n s t r u c t i o n , E n v i r o n m e n t a l a n d C o n s u l t i n g S o l u t i o n s
GAME CHANGERS 2.0
Burns & McDonnell and GE, in partnership with Transmission & Distribution
World, are hosting a series of webinars in 2012 exploring innovative
technologies and ideas that are changing how power is delivered and used.
This 11-part series kicked off in January and concludes next November.
Join Burns & McDonnell, GE and Pepco Holdings Inc. on May 30 as they
introduce an online discussion exploring the impact of electric vehicle (EV)
charging stations on the electrical distribution system in Washington, D.C., and
surrounding areas. Please join us to learn how these charging stations may
affect system planning and operations on one of the highest concentrations of
EVs per capita in the nation.
GAME CHANGERS: Innovation Brought to Life
www.burnsmcd.com/td
Sponsored by Burns & McDonnell and GE
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