AMR Deployment Stories - Electric Today · 2015-06-30 · 3 6 many still misunderstanding gore’s...

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September 2007 Volume 19, No. 7


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September 2007 Volume 19, No. 7

AMR Deployment Stories

Various utilities share their experiencesPage 8

Autovation 2007September 30 - October 3

Reno-Sparks Convention CenterReno, Nevada

and

The State of Ontario’s Smart Metering InitiativePage 22

ET September 9/5/07 12:57 PM

3

6 MANY STILL MISUNDERSTANDING GORE’S MESSAGE

8 UTILITIES SHARE THEIR VARIOUS AMR DEPLOYMENT STORIES

22 THE STATE OF ONTARIO’S SMART METERING INITIATIVE

24 EVOLVING TECHNOLOGIES IN AMR

14 POWER TRANSMISSION CAPACITY UPGRADE OF OVERHEAD LINES - PART II

xxxxx16 reGIVING NEW LIFE TO CABLE UNDERGROUND

38 A COOL WAY TO MONITOR HEAT

18 EXAMINING ADVANCED TRANSMISSION TECHNOLOGIES - PART II

30 INTERSTATE TRANSMISSION VISION FOR WIND INTEGRATION

41 FACTORS AFFECTING UNDERGROUND PLACEMENT OFTRANSMISSION FACILITIES

28 A SIMPLE ANSWER TO ANIMAL INTRUSION ON POWER SITES

44 DIGITAL CONTROL SYSTEMS FOR HIGH-VOLTAGE SUBSTATIONS - PART I

46 ADDRESSING CLIMATE CHANGE CHALLENGES THROUGH NUCLEAR TECHNOLOGY

52, 53, 54

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in this issueEDITORIAL

METERING

TRANSMISSION

SECURITY

OVERHEAD TRANSMISSION

CONTROL SYSTEMS

CABLES

NUCLEAR

ADVERTISERS INDEX

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PRODUCTS AND SERVICES SHOWCASE


Electricity Today4

editorial board

BRUCE CAMPBELL

DAVID O’BRIEN

CHARLIE MACALUSO

SCOTT ROUSE

BRUCE CAMPBELL, LL.B., Independent Electricity System Operator (IESO)Mr. Campbell holds the position of Vice-President, Corporate

Relations & Market Development. In that capacity he is responsible for theevolution of the IESO-administered markets; regulatory affairs; externalrelations and communications; and stakeholder engagement. He hasextensive background within the electricity industry, having acted as legalcounsel in planning, facility approval and rate proceedings throughout his26-year career in private practice. He joined the IESO in June 2000 and isa member of the Executive Committee of the Northeast Power CoordinatingCouncil. He has contributed as a member of several Boards, and was Vice-Chair of the Interim Waste Authority Ltd. He is a graduate of the Universityof Waterloo and Osgoode Hall Law School.

DAVID O’BRIEN, President and Chief Executive Officer, Toronto HydroDavid O'Brien is the President and Chief Executive Officer of TorontoHydro Corporation. In 2005, Mr. O'Brien was the recipient of theOntario Energy Association (OEA) Leader of the Year Award, establish-ing him as one of the most influential leaders in the Ontario electricityindustry. Mr. O'Brien is the Chair of the OEA, a Board Member of theEDA and a Board Member of OMERS.

CHARLIE MACALUSO, Electricity Distributor’s AssociationMr. Macaluso has more than 20 years experience in the electricity

industry. As the CEO of the EDA, Mr. Macaluso spearheaded the reformof the EDA to meet the emerging competitive electricity marketplace, andpositioned the EDA as the voice of Ontario’s local electricity distributors,the publicly and privately owned companies that safely and reliably deliverelectricity to over four million Ontario homes, businesses, and public institutions.

SCOTT ROUSE, Managing Partner, Energy @ WorkScott Rouse is a strong advocate for proactive energy solutions. He

has achieved North American recognition for developing an energy effi-ciency program that won Canadian and US EPA Climate ProtectionAwards through practical and proven solutions. As a published author,Scott has been called to be a keynote speaker across the continent fornumerous organizations including the ACEEE, IEEE, EPRI, and CombustionCanada. Scott is a founding chair of Canada’s Energy Manager networkand is a professional engineer, holds an M.B.A. and is also a CertifiedEnergy Manager.

DAVID W. MONCUR, P.ENG., David Moncur EngineeringDavid W. Moncur has 29 years of electrical maintenance experience

ranging from high voltage installations to CNC computer applications, andhas conducted an analysis of more than 60,000 various electrical failuresinvolving all types and manner of equipment. Mr. Moncur has chaired aCanadian Standards Association committee and the EASA OntarioChapter CSA Liaison Committee, and is a Past President of the WindsorConstruction Association.

JOHN McDONALD, IEEE PresidentMr. McDonald, P.E., is Senior Principal Consultant and Director of

Automation, Reliability and Asset Management for KEMA, Inc. He isPresident-Elect of the IEEE Power Engineering Society (PES), ImmediatePast Chair of the IEEE PES Substations Committee, and an IEEE Fellow.

DAVID W. MONCUR

JOHN McDONALD


Electricity Today6

Gore Electricity seems to bereceiving the attention of everyonethese days - but mostly negativeattention from political opponentsand righteous environmentalists.The fact that former vice presidentand global warming solutions advo-cate Al Gore uses twenty timesmore electricity in one year than theaverage American, says exactlywhat?

According to the NashvilleElectricity Service, Al Gore's 20-room, 8-bathroom, 10,000 squarefoot home "devoured" nearly221,000 kWh per year, more than20 times the national householdaverage. Gore's electricity monthlybill topped $1,359.

If you listen to groups like theTennessee Center for PolicyResearch, you will hear that whileAl Gore's global-warming documentary,An Inconvenient Truth, collected anOscar for best documentary feature,maybe he deserves a gold statue forhypocrisy.

It's always easy to call someone longon talk and short on walk but the truth isthat Gore electricity is actually "greenelectricity". The Gore electricity billshows that he voluntarily pays the highercost for something called "Green PowerSwitch", which uses more expensiveenergy from renewable sources like windand solar power. How does this work?

Many energy companies are nowoffering consumers the opportunity topurchase electricity from green energysources. These green energy sourcesinclude wind energy, hydro energy, bio-mass, solar energy and will begin toinclude marine energy sources such aswave power, tidal stream and tidalimpoundments and tidal barrages.

This separation of renewable energyfrom oil, gas, coal and nuclear is possibledue to the Renewable Energy certificateschemes now being developed world-wide. These certificates enable units ofelectricity, such as KWh to be identified

as soon as they are produced and fed intothe national grid. All units must beaccounted for both in terms of how andwhen they were produced and who soldthem to whom. Theoretically, this meansconsumers can “buy” units from specificturbines. In reality, the actual electronsrunning through a consumer’s meter willnot be generated by any source in partic-ular, as all electricity (for the most part) -however it has been generated - is fedinto the national grid. Buying green elec-tricity in this manner means that you arebuying up a certain “tokens” thatacknowledge that every unit you haveused has been made up for from a renew-able source.

When you switch to an accredited"Green" electricity provider, you'reinstructing them to purchase your nomi-nated percentage of electricity from newrenewable sources, rather than coal-firedpower stations. You still receive yourelectricity in the normal way, but everykilowatt hour of the nominated percent-age of Green Electricity you purchasedwill be supplied into the grid from arenewable source.

Gore also purchases offsets for

carbon fuel use. So, technically,Gore electricity is probably car-bon neutral, because for everybit of CO2 he puts into the air, aforest is built with his money tosequester that same CO2. Doeshe drive an SUV? Of course,but it's a hybrid SUV.

Gore electricity con-sumption proves what? He hasdone twenty times more for theenvironmental movement thanthe average American. His con-tribution to the exchange ofinformation about GlobalWarming has been much morethan the average American. Thetruth is that the averageAmerican is not a former vicepresident, and the averageAmerican does not reside in a20-room mansion, has no

domestic staff, does not have an exten-sive security system with perimeter light-ing, does not have extensive computerand communications requirements, not tospeak of HVAC duties, etc. Yes, Al Gorelives a life of privilege and luxury, as domost millionaires. If you honestly expecta wealthy politician, no matter how well-intentioned, to live life like a serf, you arebadly misguided about the modernworld. Would honest Abe Lincoln (hadhe lived to see the day) have moved fromthe White House back to the log cabinfrom whence he came? Will the worlddevolve from its addiction to technologyand modernism, only to embrace thestone age?

Instead of the whole world environ-mental initiative being about returningeveryone to the stone age, maybe it couldbe about turning our future world into abigger and better place, with less harm tothe environment, being a more populatedand prosperous world without fossilfuels. Isn't that what Gore Electricity isall about: using more of the "right kind"of electricity? Or is Gore Electricity real-ly about who has what and who doesn'tand who shouldn't?

EDITORIAL

MANY STILL MISUNDERSTANDINGGORE’S MESSAGE

Randy Hurst, Publisher


Electricity Today8

PPL ELECTRIC UTILITIESLate in 2004, PPL Electric Utilities completed an AMR

deployment to all of its 1.35 million customers. At PPLElectric, we deployed a fixed network PLC system for themajority of customers, supplementedwith a fixed network radio frequencysolution to about 6,000 customers.

It was a highly successful project- on time, on budget - and affordedpositive regulatory treatment. Thetype of risks often associated withlarge projects failed to materialize, and the technology is per-forming at or above expectations, meeting the requirements ofthe business case.

In fact, compared with many other high-risk projects suchas customer or financial system deployment, an AMR project isrelatively easy to deploy. In retrospect, one wonders why there

is so much angst in the electric utility industry over deployingAMR solutions.

While all the above certainly is good news, the real insightto deployment is not so much the project’s success but ratherthe versatility of the solution. The new tool, as expected, hasvirtually eliminated estimated bills by automating the meter-reading processes, and has improved other business processesthrough the ability to constantly communicate with the meter.What was unexpected is how business embraced the tool andapplied it in new,creative applica-tions.

In the fall of2003, a major tropi-cal storm wreakedhavoc in the PPLElectric service area,interrupting serviceto more than 40% ofcustomers. Evenwith a partiallydeployed system,storm managers rec-ognized the benefit of two-way communication with the meterin assessing restoration progress.

A completely new storm restoration tool was subsequentlydeveloped incorporating the “ping” capability.

In another unanticipated use, field engineers are geared upto use information on momentary outages - “blink” counts - asreliability predictors. Using this data has resulted in more pre-cisely focused tree trimming efforts, improved analysis of indi-vidual customer power quality problems and, ultimately, high-er customer satisfaction. It is interesting to consider that with amanual meter-reading process, the customer “communicated”with the utility about 12 times a year.

With the ability to get hourly reads, customers now cancommunicate with the company almost 9,000 times a year. Theincreased granularity of this information provides some uniqueopportunities. The company’s customer service representatives,armed with easily accessible data on daily or even hourly usage,approach high-bill complaints with greater levels of confidence.

Having this information has improved credibility with cus-tomers.

One result has been fewer complaints to the regulators overhandling of customer billing disputes. The AMR system allowscustomer call center reps to more effectively address customercomplaints regarding issues such as high bills, connects/dis-connects and estimated meter readings. AMR is particularlyhelpful in addressing high-bill complaints.

METERING

UTILITIES SHARE THEIR VARIOUSAMR DEPLOYMENT STORIES

Continued on Page 10


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For example, the number of high-bill informal complaintsreceived by PPL Electric decreased from 525 in 2003 to 273 in2004 - a drop of 48%. Similarly, the number of justified high-bill informal complaints for the same period declined from 92to 11 - a decrease of 88%.

Revenue protection staff anticipates that usage irregulari-ties will be easier to identify and will result in more solid theftleads. The system’s operation is even helping to “clean up” theelectric system.

AMR system operators will dispatch service personnel tolocations where meters are not communicating. In manyinstances, the source of the failure is not inoperable meteringequipment, but interference associated with problems in theelectric service - i.e., bad neutral. In a similar vein, the compa-ny is able to better align customer usage with rates. With a newmetering infrastructure, it is able to bill demand customersappropriately, resulting in an additional $3 million in annualrevenues.

Pennsylvania is a progressive state in terms of utilityderegulation, offering customers competitive alternatives, suchas demand side response programs and the use of distributedgeneration and renewable technologies. In selecting a technol-ogy, it was important for the utility to try to anticipate the easeor difficulty in adapting it to meet future needs in these areas.Two-way communication at the meter and the ability to obtain

interval reads provide that flexibility.Deploying an AMR solution for all customers can be a

daunting task. Developing an acceptable business case, manag-ing risks and maintaining schedules are significant undertak-ings. Yet companies that deploy these solutions will find greatimprovement in almost every important business dimension -fiscally, operationally and in customer satisfaction.

PENINSULA LIGHT CO.Peninsula Light Company (PLC) has just installed an

Automated Meter Reading system. The new system sends datafrom each meter back to the office over existing power lines.AMR technologyallows us to offer anumber of helpfulbenefits for PLCmembers... likegreater consisten-cy in billing andthe ability for PLC to provide members with more detailedinformation about their power consumption. Should a mem-ber’s power go out, the automated meters help PLC operationspinpoint the cause of the outage and accelerate response time.

By deploying AMR technology, PLC has been able to pro-vide members with more frequent, timely and accurate electricmeter readings without the need for meter readers to go to thecustomer’s property. As a result, the need for estimated billswill be virtually eliminated, leading to greater accuracy on theconsumer’s monthly bill. Another benefit of AMR to PLC cus-tomers is a more accurate and efficient way to monitor report-ed outages.

CLARK PUBLIC UTILITIESItron, Inc. (ITRI) signed a contract with Clark Public

Utilities, electricity supplier to more than 150,000 customers insouthwest Washington State, providing the utility with technol-ogy to automate meter data collection throughout its serviceterritory.

Clark Public Utilities is a customer-owned public utilitydistrict that provides electricservice to more than 150,000customers throughout ClarkCounty in SouthwestWashington State. The utilityalso provides water and waste-water service.

Installation of the $10 million meter reading system, thelargest AMR deployment to date by a consumer-owned electricutility in the U.S., was completed in the fall of 2002. ClarkPublic Utilities now uses vehicles equipped with on-board Itroncomputers and RF transceivers to automatically collect datafrom all of the utility’s 150,000 electric meters simply by dri-ving down the street.

Because Itron’s AMR meter modules can be read by any ofItron’s wireless data collection systems, the system also enablesthe Vancouver, Wash.-based utility to “migrate” to advancedfixed network technology in the future without having toreplace installed meter modules should Clark’s data collectionneeds change.

“At Clark Public Utilities we’re committed to continuallyimprove our operational efficiency so that we can keep our rates

Electricity Today10


AMR deploymentContinued on Page 8


as low as possible, and we’re committedto achieving the highest level of satisfac-tion among our customer-owners,” saidWayne Nelson, CEO and general manag-er of Clark Public Utilities.

“Implementation of automatic meterreading technology from Itron will be akey step in fulfilling both of these vitalcommitments in the years to come.”

Clark’s decision to deploy automaticmeter reading technology, which wasapproved by the utility’s board of com-missioners, came at a time when the util-ity faced considerable budgetary pressuredue to dramatic increases in wholesaleelectricity prices, said Richard Dyer,director of finance and treasurer at Clark.However, the efficiency gains, the rela-tively quick projected payback schedule,and the strategic value of AMR technolo-gy made it a very sound investment forthe utility and its customer-owners.

“Like many other utilities, we’vefaced sky-high wholesale energy prices,but we believe the capabilities and datathis technology provides will prove criti-cal to minimizing risk in today’s highlyvolatile energy market,” said Dyer. “Nowis not the time to shy away from innova-tion and technologies that reduce ourcosts and improve the way we operate asa business.”

Clark’s three-member board of com-missioners echoed that opinion when itunanimously approved the AMR project.“It’s easy when you are in a crisis to hun-ker down and miss opportunities,” ClarkPublic Utilities Commissioner NancyBarnes commented before casting her

vote in support of the project.“When you consider the financial

pressures utilities are facing today due toincreasing energy prices, it would havebeen very easy for Clark to put thisinvestment on the shelf until energyprices stabilize,” said John Hengesh, vicepresident and general manager of Itron’sWater and Public Power business unit.“But Clark Public Utilities sees AMRtechnology as a strategic investment thatreduces costs, increases operational effi-ciency and delivers reliable, accurateknowledge about its customers’ energyconsumption. In today’s volatile marketenvironment, these benefits and capabili-ties are more critical to utilities than everbefore.”

COLORADO SPRINGS UTILITIESColorado Springs Utilities is deploy-

ing an automated meter reading (AMR)program, with full deployment takingplace from late 2006 through 2010.Using wireless radio transmitters, AMRremotely reads customer meters and thentransfers the data into the billing system.AMR will reduce the need for meterreaders to manually gather utility meterreadings each month. Many utilities areusing AMR as a way to improve cus-tomer service and control their meterreading costs, especially in areas withfenced yards, dogs, landscaping andother issues that make accessing metersdifficult or unsafe. Benefits include:

Improved customer service, whichincludes:

· Minimizing the need to accesscustomer property to read meters;

· Reducing customer complaintsand damage claims resulting frommonthly visits to customer site;

· Call resolution improvement –billing complaint calls will be handledmore quickly due to availability of morefrequent meter readings;

· No need for customer to readtheir own meters due to meter accessissues;

· Controlled meter reading costs;· Enhanced customer conve-

nience;· Fewer employee injuries, espe-

cially in areas with fenced yards, dogs

and landscaping;· Improved billing accuracy;· A reduction in operational costs.

EQUITABLE GAS COMPANYItron Inc. has announced a new con-

tract with Equitable Gas Company, head-quartered in Pittsburgh, to install amobile automatic meter reading systemthroughout Equitable’s service territory.

The deployment includes the instal-lation of 260,000 Itron radio-based auto-matic meter-reading endpoints onEquitable’s natural gas meters as well asdelivery of the mobile data collectionequipment and associated software.Itron’s mobile automatic meter readingtechnology will enable Equitable Gas toreduce its meter reading process costswhile enabling the utility’s service tech-nicians to use their time more efficiently.

“We’re deploying Itron’s automaticmeter reading technology as part of ourongoing efforts to improve customer ser-vice and reduce our costs,” said RandallCrawford, president of Equitable GasCompany.

“The use of Itron’s technology willalso improve our relationship with morethan 60,000 customers who currentlyhave indoor meter sets, as the automaticmeter reading technology virtually elimi-nates the need to disrupt our customers’daily schedules to read their meters.

“We will dramatically reduce theneed to estimate meter reads which willimprove our billing accuracy and ulti-mately work to reduce operating costsacross our system.”

Russ Vanos, vice president and gen-eral manager of Itron’s hardware solu-tions group, said Equitable Gas was seek-ing a cost-effective meter data collectionsolution with proven results, and thatItron’s mobile automatic meter readingtechnology was the best fit to meetEquitable’s business objectives.

EnergyBusinessReports.com

Electricity Today12

AMR deploymentContinued on Page 10


Electricity Today14

DC VERSUS ACThe vast majority of electric power

transmissions use three-phase alternatingcurrent. The reasons behind a choice ofHVDC instead of AC to transmit powerin a specific case are often numerous andcomplex. Each individual transmissionproject will display its own set of reasonsjustifying the choice.

General characteristicsThe most common arguments

favouring HVDC are:1) Investment cost. A HVDC trans-

mission line costs less than an AC line forthe same transmission capacity.However, the terminal stations are moreexpensive in the HVDC case due to thefact that they must perform the conver-sion from AC to DC and vice versa. Onthe other hand, the costs of transmissionmedium (overhead lines and cables), landacquisition/right-of-way costs are lowerin the HVDC case. Moreover, the opera-tion and maintenance costs are lower inthe HVDC case. Initial loss levels arehigher in the HVDC system, but they donot vary with distance. In contrast, losslevels increase with distance in a highvoltage AC system

Above a certain distance, the socalled “break-even distance”, the HVDCalternative will always give the lowestcost. The break-even-distance is muchsmaller for submarine cables (typicallyabout 50 km) than for an overhead linetransmission. The distance depends onseveral factors, as transmission medium,different local aspects (permits, cost oflocal labour etc.) and an analysis must bemade for each individual case (Fig. 3).

2) Long distance water crossing. In along AC cable transmission, the reactivepower flow due to the large cable capac-itance will limit the maximum transmis-sion distance. With HVDC there is nosuch limitation, so, for long cable links,HVDC is the only viable technical alter-native.

3) Lower losses. An optimized

HVDC transmission line has lower loss-es than AC lines for the same powercapacity. The losses in the converter sta-tions have, of course, to be added, butsince they are only about 0.6% of thetransmitted power in each station, thetotal HVDC transmission losses comeout lower than the AC losses in practical-ly all cases. HVDC cables also havelower losses than AC cables.

4) Asynchronous connection. It issometimes difficult or impossible to con-nect two AC networks for stability rea-sons. In such cases, HVDC is the onlyway to make an exchange of powerbetween the two networks possible.There are also HVDC links between net-works with different nominal frequencies(50 and 60 Hz) in Japan and SouthAmerica.

5) Controllability. One of the funda-mental advantages with HVDC is that itis very easy to control the active power inthe link.

6) Limit short circuit currents. AHVDC transmission does not contributeto the short circuit current of the inter-connected AC system.

7) Environment. Improved energytransmission possibilities contribute to amore efficient utilization of existingpower plants. The land coverage and theassociated right-of-way cost for a HVDCoverhead transmission line is not as highas for an AC line. This reduces the visualimpact.

It is also possible to increase thepower transmission capacity for existingrights of way. There are, however, someenvironmental issues that must be con-sidered for converter stations, such as:audible noise, visual impact, electromag-netic compatibility and use of ground orsea return path in monopolar operation.

In general, it can be said that aHVDC system is highly compatible withany environment and can be integratedinto it without the need to compromiseon any environmentally important issuesof today.

POWER CARRYING CAPABILITY OFAC AND DC LINES

It is difficult to compare transmis-sion capacity of AC lines and DC lines.For AC the actual transmission capacityis a function of reactive power require-ments and security of operation (stabili-ty). For DC, it depends mainly on thethermal constraints of the line.

If, for a given insulation length, theratio of continuous-working withstandvoltage is as indicated in equation (1).

Various experiments on outdoor DCoverhead-line insulators have demon-strated that due to unfavourable effects,there is some precipitation of pollutionon one end of the insulators and a safefactor under such conditions is k=1.However if an overhead line is passingthrough a reasonably clean area, k maybe as high as √2, corresponding to thepeak value of rms alternating voltage.For cables, however, k equals at last 2.

A line has to be insulated for over-voltages expected during faults, switch-ing operations, etc. AC transmission linesare normally insulated against overvolt-ages of more than 4 times the normal rmsvoltage; this insulation requirement canbe met by insulation corresponding to anAC voltage of 2.5 to 3 times the normalrated voltage.

On the other hand, with suitable con-versor control, the corresponding HVDCtransmission ratio is shown in equation(3).

Thus, for a DC pole-to-earth voltage

OVERHEAD TRANSMISSION

POWER TRANSMISSION CAPACITY UPGRADEOF OVERHEAD LINES - PART II

By D.M. Larruskain, I. Zamora, O. Abarrategui, A. Iraolagoitia, M. D. Gutiérrez, E. Loroño and F. dela Bodega, Department of Electrical Engineering, E.U.I.T.I., University of the Basque Country


September 2007 15

Vd and AC phase-to-earth voltage Ep the relations (4) exist.

and substituting (1), (2) and (3) equations, we obtain equa-tion (5) for the insulation ratio.

DC transmission capacity of an existing three-phase dou-ble circuit AC line: the AC line can be converted to three DCcircuits, each having two conductors at ± Vd to earth respec-tively.

Power transmitted by AC:

Power transmitted by DC:

On the basis of equal current and insulation

The following relation shows the power ratio.

For the same values of k, k1 and k2 as above, the powertransmitted by overhead lines can be increased to 147%, withthe percentage line losses reduced to 68% and correspondingfigures for cables are 294% and 34% respectively.

Besides, if the AC line is converted, a more substantialpower upgrading is possible. There are several conversions ofAC lines to DC lines proposals, these conversions are carriedout as a simple reconstruction. The most feasible of them isDouble Circuit AC Conversion to Bipolar DC. It implies towermodifications that maintain all the conductors at a height aboveground of 1 to 2 meters below the original position of the low-est conductor during the whole construction phase. Two newcrossarms are inserted at the level of the old intermediatecrossarm.

No change is made to the conductors, the total rated cur-rent remains the same, which means that the transmitted powerincreases proportionally to the adopted new DC line-to-groundvoltage. The conversion of lines where an increase of phase-to-ground voltage can be higher than 3 is possible when all theconductors of one AC circuit are concentrated in one DC pole.

The line-to-line (LL) AC voltage is doubled for use withDC, thus the transmitted power will increase by 3.5 times.

CONCLUSIONSGiven the many changes in the way the power transmission

system is being planned and operated, there is a need to reachhigher current densities in existing transmission lines.

The different types of constraints that limit power transfercapability of the transmission system are discussed for analyz-ing the upgrade possibilities to increase the transmission capac-ity.


Electricity Today16

For decades, utilities have used polyeth-ylene-insulated cables for construction ofunderground electrical distribution and trans-mission lines. The high proliferation of thesetypes of cables is justified by their low cost,high availability and ease of installation.Improvements to the quality of the raw mate-rials as well as better manufacturing tech-niques have increased the life expectancy ofthese insulated conductors.

Earlier vintages (pre-1980) have experienced a higher thanexpected failure rate. Some of these failures are the conse-quence of inappropriate installation, dig-ins, power surges orother operating related incidents, but the degradation of thepolyethylene insulation used in most of these cables is by far,the single most important source of cable faults. This premature

aging process is caused by water treeing. Water trees start with imperfections (surface irregularities,

voids, contaminants, etc.) in the cable insulation. They grow inall solid dielectric materials in the presence of high AC stress(caused by imperfections) and water. These tree shaped struc-tures are diffuse clouds of microscopic unconnected micro-voids. They are conductive in presence of water (water that cancontain conductive particles or ions) and can be dielectric whendry. The presence of water in water trees can facilitate the initi-ation of electric trees. Water trees reduce the AC break down(ACBD) strength of polyethylene-insulated cables. In time theelectrical stress exceeds the ACBD and water trees evolve intoelectric trees.

This final state of degradation is irreversible and cable fail-ure is imminent. A fault will occur in a short period of time: theelectric trees are micro voids that are the final stage of watertrees. They are the consequence of surges, electrical impulsesor partial discharge that increase pressure on permeated watertrees and alter permanently the insulation. Routine procedures(such as snapping a capacitive charge, bad switching proce-dures or inappropriate cable testing) if not performed properlymay also produce electric trees. These micro-faults cannot berejuvenated.

Pre-1980 vintage cables suffer a rapid degradation in ACbreakdown performance during the first decade after the cableis installed. The cable then continues to degrade in perfor-mance, but at a much slower rate.

This data would indicate that today’s power system relia-bility is of great concern to all electrical utility managers withold underground power cables. The “Post-treat” line in Figure1 demonstrates how reliability can be rapidly increased usingthe silicone treatment technology. ACBD performance isimproved by .5 % per day reaching an increase of 350% over atwo-year period. Over the next 20 or 30 years the treated cable’sACBD maintains high levels that out-perform untreated cable.

Canadian Cable Injection Services (CCIS) is the Canadianleader in applying life-extension technologies to water-dam-aged power cables, using the patented CableCURE silicone-based injection fluids. CableCURE has restored over 70 millionfeet of cable world wide.

CABLES

GIVING NEWLIFE TO CABLE

UNDERGROUND

Figure 1. Typical performance of pre-1980 vintage PE cables and typical post injec-tion performance.


Electricity Today18

NEW DEMANDS ON THE TRANSMISSION GRIDThe core objective underlying electricity industry restruc-

turing is to provide consumers with a richer menu of potentialenergy providers while maintaining reliable delivery.Restructuring envisions the transmission grid as flexible, reli-able, and open to all exchanges no matter where the suppliersand consumers of energy are located.

However, neither the existing transmission grid nor its cur-rent management infrastructure can fully support such diverseand open exchange. Transactions that are highly desirable froma market standpoint may be quite different from the transac-tions for which the transmission grid was designed and maystress the limits of safe operation. The risks they pose may notbe recognized in time to avert major system emergencies, and,when emergencies occur, they may be of unexpected types thatare difficult to manage without loss of customer load.

The transmission system was originally constructed to

meet the needs of vertically integrated utilities, moving powerfrom a local utility’s generation to its customers.Interconnections between utilities were primarily to reduceoperating costs and enhance reliability. That is, if a utility unex-pectedly lost a generator, it could temporarily rely on its neigh-boring utilities, reducing the costs associated with having suffi-cient reserve generation readily available. The grid was notdesigned to accommodate large, long-distance transfers of elec-tric power.

One of the key problems in managing long-distance powertransfers is an effect known as “loop flow”. Loop flow arisesbecause of the transmission system’s uncontrollable nature. Aspower moves from seller to buyer, it does not follow any pre-arranged “contract path”. Rather, power spreads (or loops)throughout the network.

As an example, Figure 3 shows how a transmission ofpower from a utility in Wisconsin to the Tennessee Valley

TRANSMISSION

EXAMINING ADVANCED TRANSMISSIONTECHNOLOGIES - PART II

By Jeff Dagle, Steve Widergren, John Hauer, Pacific Northwest National LaboratoryTom Overbye, University of Illinois at Urbana-Champaign


remains becomes increasingly important. Both limits and mar-gins must be estimated through computer modeling and com-bined with operating experience that the models might not andoften cannot reflect.

The “edge” of safe operation is defined by numerousaspects of system behavior and is strongly dependent on sys-tem operating conditions. Some of these conditions are not

Authority (TVA) would affect lines through alarge portion of the Eastern Interconnection.

A color contour shows the percentage ofthe transfer that would flow on each line; linescarrying at least two percent of the transfer arecontoured. As this figure makes clear, a singletransaction can significantly impact the flowson hundreds of different lines.

The problem with loop flow is that, ashundreds or thousands of simultaneous trans-actions are imposed upon the transmission sys-tem, mutual interference develops, producingcongestion. Mitigating congestion is technical-ly difficult, and very complex problemsemerge when paths are long enough to spanseveral regions that have not had to coordinatesuch operations in the past. These problemsinclude (but are not limited to) the lack of:effective procedures, operating experience,computer models, and integrated dataresources. The sheer volume of data and infor-mation concerning system conditions, transac-tions, and events is overwhelming the existing grid manage-ment’s technology infrastructure.

Increasing the transfer capacity of the NTG will requirecombined application of hardware and information technolo-gies. On the hardware side, many technologies can be devel-oped, refined, or simply installed to directly reinforce currenttransmission capabilities. These technologies range from pas-sive reinforcements (such as new AC lines built on new rightsof way or better use of existing AC rights of way by means ofinnovative device configurations and materials) to super-con-ducting equipment to large-scale devices for routing gridpower flow. High-voltage direct current (HVDC) and FACTStechnologies appear especially attractive for flow control.Effectively deployed and operated, such technologies can be ofgreat value in extending grid capabilities and minimizing theneed for construction of new transmission.

The strategic imperative, however, is to develop betterinformation resources for all aspects of grid management —planning, development, and operation. Technologies such aslarge-scale FACTS generally require the support of a wide-areameasurement system (WAMS), which currently exists only asa prototype. Without a WAMS, a FACTS or any major controlsystem technology cannot be adjusted to deliver its full valueand, in extreme cases, may interact adversely with other equip-ment. FACTS technology can provide transmission “muscle”but not necessarily the “intelligence” for applying it.

An example of the information that a WAMS can provideis shown in Figure 4. Review of data collected on theBonneville Power Administration (BPA) WAMS system fol-lowing a grid disturbance in 1996, suggests that the informa-tion that system behavior was abnormal and that the powersystem was unusually vulnerable was buried within the mea-surements streaming into and stored at the control center.

Had better tools been available at the time, this informa-tion might have given system operators approximately six min-utes’ warning of the event that triggered the system breakup.

Better information is key to better grid management deci-sions.

INFORMATION GAPS IN GRID MANAGEMENTAs the grid is operated closer to safe limits, knowing

exactly where those limits are and how much operating margin

19September 2007

Figure 3: Loop Flow of Power Transfer from Wisconsin to TVA


well known to system operators,and even those that are knownmay change abruptly. Importantconditions include networkloading, operating status andbehavior of critical transmissionelements, behavior of electricalloads, operating status andbehavior of major control sys-tems, and interactions betweenthe grid and the generators con-nected to it. Full performance ofthe transmission grid requiresthat generators provide adequatevoltage support plus a variety ofdynamic support functions thatmaintain power quality duringnormal conditions and assist thesystem during disturbances.

All of these conditions havebecome more difficult to antici-pate, model, and measure direct-ly. Industry restructuring hasexacerbated these difficulties by requir-ing that transmission facilities be man-aged with a minimum of informationconcerning generation assets. To borrowa phrase from EPRI, this is one of manyareas where there is a “critical interactiverole” between “technology and policy.”

Many cases in recent years haverevealed that the “edge” of safe grid oper-ation is much closer than planning mod-els had suggested. The Western Systembreakups of 1996 are especially notablein this respect (see Figure 5), but therehave been less conspicuous warningsbefore and since. Uncertainties regardingactual system capability is a long-stand-ing problem, and it has counterparts

throughout the NTG.Developing and maintaining realistic

models for power system behavior istechnically and institutionally difficult,and it requires higher-level planningtechnology than has previously beenavailable. An infusion of enhanced plan-ning technology — plus knowledgeablestaff to mentor its development and use— is necessary to support timely, appro-priate, and cost effective responses tosystem needs. Better planning resourcesare the key to better operation of existingfacilities, to timely anticipation of systemproblems, and to full realization of thevalue offered by technology enhance-ments at all levels of the power system.

CHALLENGES ANDOPPORTUNITIES IN

NETWORK CONTROLAs noted earlier, the existingAC transmission systemcannot be directly con-trolled; electric flow spreadsthrough the network as dic-tated by the impedance ofthe system components. Fora given set of generator volt-ages and system loads, thepower-flow pattern in anelectrical network is deter-mined by network parame-ters.Control of network parame-ters in an AC system is usu-ally quite limited, so sched-uling of generators is theprimary means for adjustingpower flow for best use of

network capacity. When generator sched-uling fails, the only alternative is loadcontrol, either through voltage reductionsor suspension of service. Load controlcan be necessary even when some linesare not loaded to full capacity.

A preferred solution would be ahigher degree of control over power flowthan is currently possible, which wouldpermit more effective use of transmissionresources. Conventional devices forpower-flow control include series capaci-tors to reduce line impedance, phaseshifters, and fixed shunt devices that areattached to the ends of a line to adjustvoltages.

All of these devices employ mechan-

Electricity Today20

Figure 4. Possible warning signs of the Western Systems breakupof August 10, 1996 – an example of information available fromWAMS


ical switches which are rela-tively inexpensive and provenbut also slow to operate andvulnerable to wear, whichmeans that it is not desirable tooperate them frequently and/oruse a wide range of settings; inshort, mechanically switcheddevices are not very flexiblecontrollers. Nonetheless, theyare still the primary meansused for stepped control ofhigh power flows.

HVDC transmissionequipment offers a muchgreater degree of control. If thesupport of the surrounding ACsystem is sufficient, the powerflowing on an HVDC line canbe controlled accurately andrapidly by means of signalsapplied to the converter equip-ment that changes AC power to DC andthen back to AC. In special conditions,HVDC control may also be used to mod-ify AC voltages at one or more convert-ers. This flexibility derives from the useof solid-state electronic switches, which

are usually thyristors or gate turn-off(GTO) devices.

Although HVDC control can influ-ence overall power flow, it can rarely pro-vide full control of the power flowing onparticular AC transmission lines.

However, conventionalpower-flow controllers thatare upgraded to use elec-tronic rather than mechani-cal switches can achievethis control. This upgradeopens the way to a broadand growing class of newcontroller technologyknown as FACTS. Veryfew utilities are in a posi-tion to break this impasseas the management func-tions for which high-leveltechnologies like FACTSare of primary relevanceare passing from the utili-ties to a newly evolvinginfrastructure based uponRegional TransmissionOrganizations (RTOs),Independent System

Operators (ISOs), and other entities. This transition is far from complete

in most areas of the U.S., and as yet thereis no “design template” for the nature andthe technology needs of this new infra-structure.

21September 2007

Figure 5. Modeling failure for Western System breakup of August10, 1996. (MW on California-Oregon Interconnection)


Electricity Today22

In less than twoyears since the Ontariogovernment announcedan ambitious plan toinstall smart electricitymeters in all homes andsmall businesses by theend of 2010, theprovince has come along way.

In this short time,the project to build thebackbone of the provin-cial smart metering sys-tem is well advanced,over 680,000 smartmeters have been installed and several leading local distributioncompanies (LDC) are gearing up for the changes that smartmeters will bring to their businesses.

ONTARIO’S SMART METERING SYSTEM Ontario’s smart metering system has two key components

– the smart meters themselves, with their local supporting infra-structure, and the central infrastructure that will houseprovince-wide data. While LDCs have been purchasing andinstalling customers’ smart meters, the Independent ElectricitySystem Operator (IESO) has been developing the Meter DataManagement Repository (MDM/R), the data infrastructure thatwill be at the core of the system. The MDM/R is essentially alarge database that will receive, verify, store and manage elec-tricity consumption data from customers’ smart meters, andprovide that data to LDCs, appropriately processed, for cus-tomer billing.

Installing a centralized system like the MDM/R helps tocreate a number of efficiencies. First, it eliminates the burdenon each of the province’s 90 plus LDCs to build and managetheir own data storage and management systems. A commonsystem also ensures that uniform data collection and deliveryprocesses and standards are in place across the province – forthe first time will provide easily accessible, consistentprovince-wide information on electricity consumption.

The project has come a long way since the MDM/R speci-fications were developed last year. With the support of LDCsand IBM, the IESO’s contracted supplier, the MDM/R has beendesigned and developed and this Fall the first group of LDCswill be integrating their own smart meter systems into theprovincial MDM/R.

THE BENEFITS OF SMART METERS ARE FAR REACHINGAs Ontario moves toward a “conservation culture”, smart

meters will be key to informing and empowering consumers. InOntario today, four and a half million electricity consumers pay

a fixed price for electricity, regardless of theirtime of use. These consumers have littleincentive to shift their usage away from peri-ods when demand for electricity is high andthe system is strained. Smart meters have thepotential to change this.

Measuring electricity use on anhourly basis, smart meters provide consumerswith the knowledge they need to manage theirpersonal electricity use. This knowledge,coupled with time-of-use (TOU) electricityrates, provides consumers with the financialincentive to shift or reduce their consumption.Consumers who modify their electricityusage patterns will save money, contribute tomaintaining the reliability of the electricity

system and help lessen the impact on the environment.As the system operator, the IESO is also anticipating the

system reliability benefits smart meters can offer. The TOUrates established by the Ontario Energy Board (OEB) have beenset to reflect the cost to supply electricity at different times dur-ing the day, and accordingly are significantly higher whendemand for electricity is usually at its highest. If consumersrespond by shifting their electricity use away from the higherpriced periods, they will help reduce the strain on the electrici-ty grid during those peak times.

And with enough additional consumer demand responsethrough smart meters, there could be significant cost savingsacross the system. For instance, if Ontario consumers can helpto reduce or eliminate the peak demands that occur in so fewhours, the need to build expensive peaking generators could bedeferred. For instance, despite the fact that peak demandreached 27,005 megawatts (MW) last summer, it exceeded25,000 MW in only 32 hours for the entire year. Reducingdemand in these hours could lead to millions of dollars in sav-ings for Ontario consumers.

CONSUMER INFORMATION WILL BE CRITICALThe roll-out of smart meters across the province will

change the way consumers view electricity use and cost, butthese changes do not come without some challenges.

One of these is to ensure that electricity consumers are ade-quately informed about smart meters and how best to takeadvantage of the opportunities they offer. Unlike the May 1opening of Ontario’s electricity market in 2002, the switch tosmart meters will roll out over several years. This should facil-itate ongoing consumer education and feedback on how best toenhance the value provided by smart meters. And the variouspilots being conducted with LDCs provide a good opportunityfor LDCs to become familiar with new technology and con-sumers familiar with TOU rates. As always, delivering benefitsfor customers will be the true measure of success.

METERING

THE STATE OF ONTARIO’S SMART METERINGINITIATIVEBy Bruce B. Campbell, Vice President, Corporate Relations & Market

Development, Independent Electricity System Operator


Electricity Today24

The first significant injection oftechnology to the AMR industry was adrive-by system. Transmitters, mountedonto the meters themselves, send a signalto a meter-reading device located in theback of a utility van. As the van drivesthrough a neighborhood, the meter readswould be downloaded. This technologyrequires the orchestration of RF signalprocessors to transmit the data, databasesoftware to collect the meter reads, andinterface software to validate data andhold it for billing purposes. Itron hasbecome the clear champion for this tech-nology pathway.

The state-of-the-art rarely standsstill and AMR technology is no different.CellNet, now a division of Schlumberger,replaced the need for drivers to collectmeter reads with wireless networks thatspan entire utility service areas. Throughthe CellNet system, meter reads aretransmitted over a cellular network, vali-dated by CellNet software, and madeavailable to utility offices over a secureinternet connection. This type of systemprovides further cost savings but requiresa larger up-front investment and commit-ment.

Since then, two other technologieshave demonstrated significant value.First, powerline technologies champi-oned by Hunt and TWACS enable elec-tricity utilities to collect meter reads overtheir existing powerline transmission net-works. These systems transmit data sig-nals through electrical powerlines them-selves and have the advantage of beingdeployable to every location that an elec-tric utility serves. One cannot assume thesame reach of powerline technology forgas and water utilities. Second, advancesin two-way telemetry over public or pri-vate networks by firms such asSmartSynch and Tantalus have enabledutilities to deploy a meter reading systemthat gathers meter data in real time.

Given the variety of the technolo-gies, each with its own cost structure andvalue points, how should a utility select astandard to deploy throughout their ser-

vice area? An installation cost to perfor-mance roadmap for AMR is providedhere (above).

However, conversations with othersquickly highlighted the shifts within thisparadigm. For instance, the Tantaluswireless system, which uses public spec-trum over a private network for transmis-sion of meter data, provides the perfor-mance of two-way telemetry but with asignificantly lower cost structure.Elsewhere, MeterSmart has developed ameans to provide some of the functional-ity of two-way telemetry while using thepowerline communication system fortransporting signals. To further compli-cate the temporary clarity, the companyshould expect further industry evolution.With 86% of the market up for grabs,each technology provider has significantincentive to innovate and capture thefuture market.

TOUCH TECHNOLOGY AMRWith touch-based AMR, a meter

reader carries a handheld computer ordata collection device with a wand orprobe. The device automatically collectsthe readings from a meter by touching orplacing the read probe in close proximityto a reading coil enclosed in the touch-pad. When a button is pressed, the probesends an interrogate signal to the touch

module to collect the meter reading. Thesoftware in the device matches the serialnumber to one in the route database, andsaves the meter reading for later down-load to a billing or data collection com-puter. Since the meter reader still has togo to the site of the meter, this is some-times referred to as “on-site” AMR.

RADIO FREQUENCY AMRRadio frequency-based AMR can

take many forms. The more commonones are Handheld, Mobile, and Fixednetwork. There are both two-way RF sys-tems and one-way RF systems in use thatuse both licensed and unlicensed RFbands.

In a two-way system, a radio trans-ceiver normally sends a signal to a par-ticular transmitter serial number, tellingit to wake up from a resting state andtransmit its data. The Meter attachedtransceiver and the reading transceiverboth send and receive radio signals anddata. In a one-way “bubble-up” type sys-tem, the transmitter broadcasts readingscontinuously every few seconds. Thismeans the reading device can be a receiv-er only, and the meter AMR device atransmitter only. Data goes one way,from the meter AMR transmitter to the

METERING

EVOLVING TECHNOLOGIES IN AMR



meter-reading receiver. There are also hybrid systems that com-bine one-way and two-way technologies, using one-way com-munication for reading and two-way communication for pro-gramming functions.

RF-based meter reading usually eliminates the need for themeter reader to enter the property or home, or to locate andopen an underground meter pit. The utility saves money byincreased speed of reading, has lower liability from enteringprivate property, and has less chance of missing reads becauseof being locked out from meter access.

HANDHELD AMRHandheld AMR is where a meter reader carries a handheld

computer with a built-in or attached receiver/transceiver (radiofrequency or touch) to collect meter readings from an AMRcapable meter. This is sometimes referred to as “walk-by”meter reading since the meter reader walks by the locationswhere meters are installed as they go through their meter-read-ing route. Handheld computers may also be used to manuallyenter readings without the use of AMR technology.

Handheld AMR systems can be touch based. In this sys-tem, a meter reader physically touches the MIU with a probemaking contact with the device and automatically collecting itsdata. The probe sends out an interrogator signal and in returnreceives an answer from the MIU, matching the data to a pre-recorded serial number for the meter being read. This systemhas aspects of both old and new, with automatic readings butstill dependent on human meter readers.

MOBILE AMRMobile or “Drive-by” meter reading is where a reading

device is installed in a vehicle. The meter reader drives thevehicle while the reading device automatically collects themeter readings. Often for mobile meter reading, the readingequipment includes navigational and mapping features provid-ed by GPS and mapping software. With mobile meter reading,the reader does not normally have to read the meters in any par-ticular route order, but just drives the service area until allmeters are read. Components often consist of a laptop or pro-prietary computer, software, RF receiver/transceiver, and exter-nal vehicle antennas. Mobile units are mounted on vehicles orbackpacks and rely entirely on wireless radio frequency com-munication. These drive-by readings are conducted on amonthly basis with both the mobile units and the MIUs send-ing and receiving information.

FIXED NETWORK AMRFixed Network AMR is a method where a network is per-

manently installed to capture meter readings. This method canconsist of a series of antennas, towers, collectors, repeaters, orother permanently installed infrastructure to collect transmis-sions of meter readings from AMR capable meters and get thedata to a central computer without a person in the field to col-lect it. There are several types of network topologies in use toget the meter data back to a central computer.

Fixed relay systems can be either wireless or via cable,with the signal sometimes sent along the power lines them-selves. These can be interrogative, or “bubble up”, systems,where unprompted MIUs transmit continuous readings every

few minutes. In mobile systems, the human operator is nearlyeliminated, except for the driver of the vehicle whose inter-rogator unit is accessing multiple MIUs simultaneously. Infixed relay systems, the human operator is completely replaced.

RF technologies commonly used for AMR include:· Narrow Band (single fixed radio frequency);· Spread Spectrum;· Direct Sequence Spread Spectrum (DSSS);· Frequency Hopping Spread Spectrum (FHSS).

POWER LINE CARRIER AMRPower Line Carrier (PLC) AMR is a method where elec-

tronic data is transmitted over power lines back to the centralcomputer. This would be considered a fixed network type sys-tem, and is primarily used for electric meter reading. Someproviders have interfaced gas and water meters to feed into aPLC type system.

ADVANCED AMROriginally AMR devices just collected meter readings

electronically and matched them with accounts. As technologyhas advanced, additional data can now be captured, stored, andtransmitted to the main computer. This can include eventsalarms such as tamper, leak detection, low battery, or reverseflow. Many AMR devices can also do data logging. The loggeddata can be used to collect time of use data that can be used forwater or energy use profiling, time of use billing, demand fore-casting, rate of flow recording, leak detection, flow monitoring,etc.

COLORADO SPRINGS UTILITIES CASE STUDYColorado Springs Utilities is deploying an automated

meter reading (AMR) program, with full deployment takingplace from late 2006 through 2010.

Using wireless radio transmitters, AMR remotely readscustomer meters and then transfers the data into the billing sys-tem. AMR will reduce the need for meter readers to manuallygather utility meter readings each month. Many utilities areusing AMR as a way to improve customer service and controltheir meter reading costs, especially in areas with fenced yards,dogs, landscaping and other issues that make accessing metersdifficult or unsafe. Benefits include improved customer service,which includes:

· Minimizing the need to access customer property toread meters;

· Reducing customer complaints and damage claimsresulting from monthly visits to customer site;

· Call resolution improvement – billing complaint callswill be handled more quickly due to availability of more fre-quent meter readings;

· No need for customer to read their own meters due tometer access issues;

· Controlled meter reading costs;· Enhanced customer convenience;· Fewer employee injuries, especially in areas with

fenced yards, dogs and landscaping;· Improved billing accuracy;· A reduction in operational costs.

The AMR Technologies Report can be found atEnergyBusinessReports.com, an industry think tank andresearch report publisher.

Electricity Today26

Evolving TechnologiesContinued from Page 24


Electricity Today28

Raccoons, squirrels and the likemay be seen as cute by some, butquickly become less lovable whenthey get into power stations, interferewith equipment and cause disruptive,sometimes costly outages, not to men-tion their own unpleasant demise.

One back-to-basics solution tothe serious problem of animal intru-sion currently making a name on themarket is Kinectrics’ PowerKage non-electric fence, a passive defense sys-tem for transformers and other electri-cal systems that works 24/7 to protectclients’ equipment. The PowerKagenon-electric fence has quicklybecome established among animal barrier products available tothe industry, following the system’s successful installation at a

number of North American transmission stations. Kinectricshas just recently been awarded another contract to install thePowerKage at 3 large utility substations in Southern Ontario.

NON-ELECTRIC TECHNOLOGY A key feature of PowerKage is its simplified design, which

does not rely on electric power to operate. This offers numeroussafety benefits for station personnel, the public, and even anypotential 4-footed intruders that are effectively prevented fromconnecting with power equipment.

“Kinectrics developed PowerKage as a non-electric tech-nology because, during an experimental program to test barri-ers conducted over several years, it proved to be the most effec-tive option in preventing the ground passage of small animals— even when tested under worst case conditions,” says PaulPatrick, Ph. D., of the PowerKage system design team.

DESIGN SIMPLICITY Kinectrics’ PowerKage non-electric fence is modular in

design and easy to install, disassemble or reconfigure. Themodular design of the fence system allows authorized person-nel to easily remove or take down sections where required toallow access to work locations if needed. The basic fence com-ponents consist of 6-foot units, 26” units, inside corner unitsand outside corner units. Gates, for both vehicle and personnelaccess, are easily accessed by one person in less than a minute,and are identified by signage to distinguish their location on thefence line.

Personnel gates are constructed in six-foot panel sectionsmounted with robust heavy-duty double hinges that provide afour-foot opening (180-degree swing) for entry with both leftand right hinge options. Personnel gates are also supplied witha hinged, fold-down panel at the bottom of the gate to allow theupper gate portion to swing freely above accumulated snow

SECURITY

A SIMPLE ANSWER TO ANIMAL INTRUSIONON POWER SITES

By Margaret Bennett, Kinectrics Inc.


29September 2007

drifts. The vehicle gate is designed to provide an access opening

of 12 feet within an 18-foot unit. Vehicle gates are built withrobust heavy duty double hinges that allow operators to foldboth gates up to180 degrees. Gates come with bolt-action locksthat can be padlocked if necessary.

The PowerKage non-electric fence (and associateddeterrent technologies) does not require special technical workinstructions, work protection practices, monitoring, or indica-tors for maintenance and general operation. The PowerKagenon-electric fence is grounded to the transformer stationgrounding grid to provide continuous ground fault protectionwhen gates are opened, or when panels and sections of thefence have been removed. PowerKage poses no hazard togrounds maintenance crews or inadvertent intruders.Components are engineered for durability and minimal mainte-nance.

The PowerKage system offers unique flexibility — fencelayouts can be focused to contain specific problem areas (i.e.using one or more, smaller fence enclosures within a utility’spremises). If required, PowerKage can also be combined withsecurity fencing, an option not typically available with electricfencing.

Specific PowerKage system details are designed to meet tothe requirements of individual station sites. For example, thePowerKage system has additional features that are designed to

prevent animals from gaining access by digging, or usingbranches, lines and other objects to gain entry to power sites.

OPERABILITY The PowerKage system layout is designed to minimize

interference with the operation of substation equipment. Thefence is either kept very close to fuses and switches that needto be operated such that they can be accessed from outside thefence, or far enough away that they will not interfere with oper-ator’s switch pole. One person can remove the necessary boltsor pins to remove any fence panel as necessary. Any groundingwires installed are connected to the structure’s feet and not thepanels.

MINIMAL MAINTENANCE Kinectrics PowerKage non-electric animal control fence is

designed to be maintenance free. Barring exceptional circum-stances, no spare parts should be required for the system’s 25-year life cycle. There are no controllers to be damaged by light-ning or weather. The only tools required for a PowerKageinstallation are a level, rake, shovel, and wrench set.

Preventing animal intrusion is important for utilities. AsChristine McLeod, an Edison regional manager in the U.S. hasobserved, “Outages caused by animals may not always bemajor, but when they happen at regular intervals they drive peo-ple crazy.”


Electricity Today30

American Electric Power, workingat the request of, and in partnership with,the American Wind Energy Association(AWEA), presents a high-level, concep-tual interstate transmission plan thatcould provide a basis for discussion toexpand industry infrastructure needs inthe future. AEP believes that expansionof Extra High Voltage (EHV) interstatetransmission systems provides increasedreliability, market efficiency, environ-mental optimizationand national securityfor the benefit ofelectric customersacross the UnitedStates.

AEP currentlyowns two wind farmsin Texas with a totalcapacity of 310 MWand has long-termagreements to pur-chase 467 MW ofoutput from windfarms in Oklahomaand Texas. We sup-port federal and statepolicies that reduceelectricity productioncosts by facilitating deployment of thesetechnologies, such as production taxcredits and assurances from state regula-tors for recovery of investments.However, AEP does not support a nation-al mandate that stipulates a RenewablePortfolio Standard (RPS) in the overallelectric generation resource mix.

The nation’s transmission system isat a critical crossroads. The United Statescontinues to experience transmission bot-tlenecks that compel the excessive use ofolder, less efficient power plants.Transmission grid capacity constraintsmust be eliminated to ensure a fair,vibrant and open market that gives us theflexibility to deliver economic and envi-ronmentally friendly energy to con-sumers.

AEP believes the nation’s transmis-sion system must be developed as a

robust interstate system, much like thenation’s highways, to connect regions,states and communities. Our highly effi-cient and reliable 765 kilovolt (kV) net-work provides a strong foundation forthis system because it is the most effi-cient, proven transmission technologyavailable in United States.

The hope is that this article will pro-mote discussion and set the stage foraction.

EXECUTIVE SUMMARYSome experts believe the U.S. offers

quantities of wind energy resources wellin excess of future projected electricityneeds. One of the biggest long-term bar-riers in the adoption of wind energy tomeet this growing demand is the physicallimitations on the nation’s current elec-tric transmission system. The nation’sbulk transmission system is currentlyinadequate to deliver energy from remotewind resource areas to electrical loadcenters; located mainly on the East andWest coasts. AEP believes that this barri-er can be overcome by building transmis-sion infrastructure that will enable windpower to become a larger part of thenation’s power generation resource mix.This transmission system expansion willbring many additional societal benefits,including increased reliability and

greater access to lower cost and environ-mentally friendly resources.

This conceptual transmission plan isillustrative and should be treated as such.AEP and other power industry leadersbelieve 765 kV in particular has manybenefits over other options. There are,however, many possible configurationsthat could be leveraged to integrate windand other resources. The goal is merelyto present this proposal as one possible

scenario to illustratethe potential thatexists. Additionally,the intent of thisvisionary plan is toprovide an examplethat encourages thetype of thinking and,most importantly, con-sensus and action nec-essary to bring trans-mission and wind gen-eration together on anational scale.

The result ofthis effort, shown inExhibit 1, is a theoret-ical interstate 765 kVelectricity transporta-

tion system that encompasses major por-tions of the United States connectingareas of high wind resource potentialwith major load centers. It is projectedthat an interstate EHV transmission sys-tem could enable significantly greaterwind energy penetration levels by pro-viding an additional 200-400 GW of bulktransmission capacity. The total capitalinvestment is estimated at approximately$60 billion (2007 dollars). While it is byno means the total solution, this initiativeillustrates the opportunities that exist,and what might be possible with ade-quate cooperation, collaboration, andcoordination – “3Cs”.

This article describes the data andmethodology used in developing thisplan, costs, benefits and wind deploy-

TRANSMISSION

INTERSTATE TRANSMISSION VISION FOR WINDINTEGRATION


Some experts believe the U.S. offersquantities of wind energy resources wellin excess of future projected electricityneeds. One of the biggest long-term bar-riers in the adoption of wind energy tomeet this growing demand is the physicallimitations on the nation’s current electrictransmission system.


ment potential from the plan, and the efforts that will need tobe undertaken to make the visionary concept a reality.

BACKGROUNDThis endeavor is a derivative effort associated with a joint

study involving AWEA, U.S. Department of Energy (DOE),and National Renewable Energy Laboratory (NREL). Thisstudy is committed to developing an implementation plan thatwould enable AWEA’s proposal to provide up to 20% (approx-imately 350 GW) of the nation’s electricity from wind energy.

AEP, along with members of several other wind, electricutility, RTO, and governmental organizations, was invited as aconsultant to provide guidance and insight in regard to trans-mission. Though AEP does not support RPS mandates orpenalties for not achieving mandates, AEP does supportenabling renewable generation through transmission develop-ment and goals toward that end. Transmission infrastructure isa critical component in the development of wind generation, in

particular on a national scale with such aggressive goals. It isthis relationship that compelled these organizations to collec-tively develop an illustrative vision for the bulk transmissionsystem to satisfy this target.

EXPANDING 765 KV TECHNOLOGYThe power grid in much of the U.S. today is characterized

by mature, heavily-loaded transmission systems. Both thermaland voltage-related constraints affecting regional power deliv-eries have been well documented on systems operating at volt-ages up to, and including, 500 kV. While various mitigatingmeasures are being proposed and/or implemented, they arelargely incremental in scope and aimed at addressing specific,localized network constraints. Incremental measures are adeliberate means of shoring up an existing system in the near-term, but certainly do not facilitate the incorporation of renew-able energy and other generation resources on the scalerequired to meet the proposed goal. In the longer term, a maturesystem facing growing demands is most effectively strength-ened by introducing a new, higher voltage class that can pro-vide the transmission capacity and operating flexibility neces-sary to achieve the goal of a competitive electricity marketplacewith wind power as a major contributor. In addition, a new

Electricity Today32

Exhibit 1: Conceptual 765 kV backbone system for wind resource integration (edited by AEP).

Interstate TransmissionContinued from page 30


33September 2007

high-voltage infrastructure would facilitate the use of the latesttransmission technologies - maximizing the performance, relia-bility, and efficiency of the system.

The existing AEP 765 kV system provides an excellentplatform for a national robust transmission infrastructure. Theuse of 765 kV AC technology would enable an expansion into anew high-capacity bulk transmission grid overlaying the exist-ing lower voltage system, with both systems easily integratedwhere so required. By contrast, traditional DC technology isgenerally limited in its application to point-to-point transmis-sion. Wind generation resources often cover a wide geographicarea, and the cost to create multiple connections to a DC linecould be substantially higher. A 765 kV AC network wouldallow for less complicated future connections of resources andintegration into the underlying system. This type of integratedAC grid with ample capacity for future growth provides a solidfoundation for reliable service and ease of access to all users.Furthermore, this network frees up capacity on lower voltagesystems such as 500kV, 345 kV, and 230 kV. This is particular-ly important as this additional capacity allows operational andmaintenance flexibility, as well as the ability to connect newgeneration resources onto the underlying system.

To assess the load carrying ability, or loadability of a high-voltage transmission line, the concept of Surge ImpedanceLoading (SIL) is commonly used. SIL is a convenient yardstickfor measuring relative loadabilities of transmission lines oper-ating at different voltages, and is that loading level at which theline attains reactive power self-sufficiency. For example, an

uncompensated 765 kV line has a SIL of approximately 2,400MW. By contrast, a typical 500 kV line of the same length hasa SIL of approximately 910 MW and a 345 kV line approxi-mately 390 MW. The relative loadabilities of 765 kV, 500 kV,and 345 kV considering 150 miles line length (from the St.Clair Curve), are 3,840 MW, 1,460 MW, and 620 MW, respec-tively. It is apparent that a 765 kV line, 150 miles in length, cancarry substantially more power than a similarly situated 500 kVor 345 kV line. Generally, about six single-circuit (or three dou-ble-circuit) 345 kV lines would be required to achieve the loadcarrying ability of a single 765 kV line. Relative loadabilities ofthe transmission lines also can be viewed in terms of transmis-sion distances over which a certain amount of power, say 1,500MW can be delivered. For a 765 kV line, this loading representsapproximately 0.62 SIL (1,500/2,400 = 0.625) which, accord-ing to the St. Clair Curve, can be transported reliably over a dis-tance of up to 550 miles. By contrast, a 345 kV line carrying thesame amount of power can transport reliably only up to 50miles; this distance would increase to about 110 miles for adouble-circuit 345 kV line.

Additionally, a line’s capability can be increased furtherwith adequate voltage compensation through the use of devicessuch as Static Var Compensators (SVC). High Surge ImpedanceLoading (HSIL) technology at 765 kV could also be consid-ered. While HSIL lines have not been employed in the UnitedStates, studies indicate these lines could provide additionalcapacity with a relatively modest increase in cost. Furtherresearch and development into these and other promising tech-


Electricity Today34

meant to preclude or replace any pro-posed projects. Rather, it is meant to sug-gest one possibility that is believed tosatisfy the goal of connecting areas ofhigh wind potential with load centersacross the country.

Our analysis relied on input fromthe on-going study, wind resource mapsdeveloped by the NREL, and individualcontributions from other participants.

From this information, areasof high wind potential aswell as cost-effective trans-mission corridors to majorload centers were identified.

Other existing trans-mission studies were alsorelied upon as pertinentsources. In many cases,these existing proposalsinclude more detailedanalyses and provided

sound technical supporting information.For example, in the case of MidwestISO’s MTEP06 report and the proposalfor the Texas Competitive RenewableEnergy Zone (CREZ) initiative producedby Electric Transmission Texas (ETT-AEP joint venture with MidAmericanEnergy Holdings Company), actual

only reduce overall energy consumptionacross the system, but also the need forgenerating capacity additions, resultingin a significant reduction in capitalrequirements, fuel consumption, andemissions.

METHODOLOGYIn developing this conceptual 765

kV overlay, it is necessary to make a

number of significant assumptions.While the routes and connections arederived based upon engineering judg-ment, the impact of the proposed overlaywould require significant additionalstudy by a number of different stake-holders. In addition, the transmissioncorridors shown on this diagram are not

nologies is particularly important inorder to create the most advanced andreliable future transmission system.

A further benefit of the use of 765kV lines is the reduced impact on theenvironment. As stated above, one 765kV line can carry a substantially higheramount of power than transmission linesoperating at lower voltages. Forinstance, a single 765 kV line can carryas much power as three 500kV lines or six 345 kVlines. The result is thatfewer lines need to be con-structed and less right-of-way clearing necessarycompared to lower voltagesfor the same power deliverycapability. Use of highervoltages also results in amore efficient system. Bymoving power off the lowervoltage systems having higher resistanceand onto the 765 kV, real and reactivepower losses are reduced. It can also bedemonstrated that a 765 kV line incursonly about one-half of the power lossesof a six-circuit 345 kV alternative, bothcarrying the same amount of power. Thisreduction in transmission losses will not

By moving power off the lower volt-age systems having higher resis-tance and onto the 765 kV, real andreactive power losses are reduced.


35September 2007

study of wind integration using 765 kVwas performed. These reports offeredqualified information to help formulatethe overall plan. Furthermore, a numberof other projects have been proposed inother areas of the country, including sev-eral west of the Rocky Mountains. Whilethese projects do not necessarily consid-er use of 765 kV, they do identify corri-dors where additional transmission isneeded.

The vision map was creat-ed using the following process:

1. Identify and plot theexisting 765 kV system andother 765 kV proposals to useas a foundation for expansion.

2. Using other proposals,determine corridors that havebeen identified as lackingtransmission capacity but maynot have been considered for765 kV.

3. Identify major load centers andareas of high wind potential. Create linksbetween areas without proposed trans-mission development that are determinedto be cost-effective.

4. Connect the proposed 765 kVsegments at strategic locations to forman integrated 765 kV network overlaythat makes sense from a high level trans-mission planning and operations per-spective. These locations would be sub-stations, existing or new, that best allowdispersion of power into localized areas.

It is expected that this 765 kV over-lay could provide enough capacity to

connect up to 400 GW of generation.This was calculated by dividing the 765kV network into loops and nodes wherepotential wind generation connectionsare expected. Each of these connectionswould be required to have two or more

outlets on the 765 kV, and thereforewould permit a level of generation equalto the capability of a single 765 kV line(allows outage of the other outlet). Forthe proposed system as shown in Exhibit1, there are approximately 55 suchpotential connections (of course, in real-ity there would likely be many more con-nections in smaller incremental sizes).Since the length of these lines varies,

assigning a specific SIL valueto the overall system can becomplicated.

However, a typical765 kV line has physicalequipment limitationsupwards of 4,000 MVA andconductor limitations upwardsof 10,000 MVA. A loadabilityrange of 3,600-7,200 MW(1.5-3 times base SIL) can becredibly assumed for a given

line. This equates to a total generationconnection potential of approximately200-400 GW, with even higher levelsachievable by utilizing proper technolo-gies. This also does not account for dis-placed generation and additional capaci-

It is expected that this 765 kVoverlay could provide enoughcapacity to connect up to 400GW of generation.


Electricity Today36

ery of the resources to load centers, it isexpected that the 500 kV system in thisarea could be enhanced for power deliv-ery. Although it still may be worthwhileto extend 765 kV into these areas, it wasdecided that the added line mileage andcost associated with delivering the windresources should be the subject of addi-tional study.

The scenario present-ed consists of approximately19,000 miles of new 765 kVtransmission lines. Thismileage includes existing765 kV project proposals,such as ETT’s CREZ projectin the ERCOT region andothers in MISO and PJM.The rough cost of this plan is

estimated to be $60 billion in 2007 dol-lars. This figure assumes a $2.6 millionper mile 765 kV line cost, as well as anadditional 20% for station integration,DC connections, and other related costs.These costs are ballpark estimates creat-ed without the benefit of detailed engi-neering and should be considered assuch. Variations in labor, material, andright-of-way costs can cause these fig-ures to fluctuate significantly.

There are considerable benefits

From a high level, this visionaryconcept would provide maximum accessto wind resources throughout the countrywith cost and transmission reliabilitygiven appropriate consideration as well.Notably, connecting the study’s targetgoal of 350 GW could be attainable withthis plan, over time. While this is simplyone of any number of designs that could

be considered, it is believed that anational 765 kV plan of this approachwould create a robust platform increas-ing access to renewable energy as well asfacilitating a competitive energy market-place.

Because the southeastern UnitedStates is deficient in significant, devel-opable wind resources, no 765 kV lineshave been proposed for that region.While transmission is needed both forconnection of wind resources and deliv-

ty available on the lower voltage sys-tems, which may augment this potential.

THE CONCEPTUAL PLANThe result of this process is a 765

kV backbone system that provides cost-effective connections from areas of highwind potential to major load centers.Furthermore, the overlay would providesignificant reliability benefits tothe overall transmission systemin these areas. Exhibit 1 showsthe theoretical 765 kV backbonetransmission system as devel-oped in this effort. The basegraphic on the map is theComposite Wind Resource Mapdeveloped by the NREL. Thecolor contours on the map showthe wind power density and subsequentresource potential across the country.Transmission lines 345 kV and aboveare shown with the existing 765 kV sys-tem highlighted in red. The conceptual765 kV overlay expansion is shown ingreen. DC connections between theregional interconnections are main-tained, though optimal integration ofthese resources as proposed in thisvision may dictate future synchroniza-tion of these areas.

The result of this process is a 765 kVbackbone system that provides cost-effective connections from areas of highwind potential to major load centers.


from a plan of this scale. First, it provides themost efficient method of interconnectingremotely located wind generation resourceswith a system that is capable of deliveringsuch resources to the areas that need them.Today’s aging and heavily loaded transmis-sion system is inadequate for this purpose,especially on the scale that is required tomeet new renewable energy goals. An addedbenefit is a significantly higher capacity anddependable transmission grid. Problemsincluding congestion, aging infrastructure,and reliability that plague the existing trans-mission system will be alleviated. A 765 kVoverlay adds considerable stability to theoverall transmission system and reduces theburden on the lower voltage system. In addi-tion, operational flexibility is enhanced to alarge extent, especially when outages arerequired for maintenance on parallel orunderlying facilities. This may also permitsome obsolete portions of the system to beretired, upgraded, or replaced. Finally, thissystem provides access to a broader range ofgeneration, facilitating competition that willultimately reduce costs to consumers.

FROM VISION TO REALITYWhen much of the existing transmission

infrastructure was developed in the mid-20thcentury, predictions of today’s electricitydemand were a fraction of what has beenrealized. In addition, few at the time wouldhave foreseen a carbon-constrained future.

There are undoubtedly significant chal-lenges to overcome before such an aggres-sive plan could become a reality.Transmission expansion requires certainty ofcost recovery for investors, which is oftennot the case, especially when crossing state,company, and operational boundaries. Aswith most transmission development, thesignificant right-of-way requirements of thisvision may certainly delay and obstruct itsformation. It is also difficult to advance fromincremental transmission planning to a larg-er long-term, multi-purpose strategic planthat crosses jurisdictional and corporateboundaries. One of the singular difficultieswith wind generation is the remote locationof the resources.

Because of this, transmission and gener-ation planning cannot be divorced from eachother and limited to only few years in to thefuture, yet joint coordination of suchrequests is difficult and sometimes prohibit-ed by regulatory edict. Steps in such a direc-tion have been taken, but there is much moreto be done.

Courtesy of the American Energy Producers(AEP)

September 2007


Monitoring power cables is crucial to maintaining a clean,stable power supply – and keeping that stream of informationconcise and useful can be likened to separating the wheat fromthe chaff.

Many hundreds of miles of cable need to be constantlymonitored by the utility every day; but that doesn’t mean bury-ing the monitoring operator with an avalanche of raw data.

Based out of Austin, Texas, SensorTran Inc. has come upwith the Distributed Temperature Sensing (DTS) CalibrationModule, providing oil and gas and electrical power companieswith the first truly auto-correcting calibration for DTS.

“Auto-corrective calibration has always been seen asunachievable in the DTS industry, and we’re proud to be thefirst to offer this critical capability,” said Kent Kalar, CEO ofSensorTran. “Our Calibration Module creates an auto-correct-ing DTS solution that requires minimal human intervention,even with portable systems that are connected to new probesall the time. This creates tremendous time and cost savings forour customers.”

The module offers continuous verification of calibrationand automatically adjusts itself when discrepancies are identi-fied. It is the auto-correcting capability that provides huge costsavings by ensuring crews are free to concentrate on mission-critical tasks instead of resource intensive DTS deployments.

“We can take temperature measurements of up to 36 kilo-metres in half-metre increments, deploying the fiber in or nearthe transmission cable,” says Kalar. “By getting these kind ofaccurate measurements, we can help the utility derate theirpower factor, allowing them to utilize their cables more effi-ciently.”

The module creates a unique thermal profile with high andlow temperature reference points that DTS units automaticallyrecognize as being generated by the Calibration Module. TheDTS unit uses these temperature reference points for accuracy

Electricity Today38

CABLES

A COOL WAY TOMONITOR HEAT

By Don Horne


verification and auto-correcting the calibra-tion of the DTS.

The origins of theDTS CalibrationModule can be tracedto space.

“It began whenLockheed Martin need-ed us to develop sen-sors to monitor thecryogenic fuel tanksinside the X-33 (thereusable space shuttleproject that was can-celled by NASA in2001),” says Kalar.“We took this technolo-gy and looked aroundto see where it could beapplied elsewhere, andthe electrical T&Dmarket was a naturalfit.”

Providing 40,000discrete temperaturemeasurement pointsalong the completelength of optical fiber, the DTS monitor-ing system provides real-time dynamictemperature data with high accuracy, fineresolution and fast measurement speeds.

“The fiber optic DTS method usedthe Raman-effect, which was developedat the beginning of the 1980s inEngland,” says Kalar. “This is a proventechnology in Europe, and it is only nowbeing adopted in North America, withthe Puerto Rico Power Authority, inBoston and with BC Hydro and inEdmonton, Alberta.”

The fiber optic-based DTS methodmeasures temperature using optical fiberinstead of thermocouples or thermistors,as has typically been the case in the past.

Applications for the technologyinclude:

Power Transmission Cables –dynamic temperature and health moni-toring of long-range power transmissioncables and joints including direct buriedcable, cable tunnels and cable ducts.Additionally, provides installed data forinput into real-time cable rating andampacity calculation software.

Power Distribution Networks – real-time temperature and health monitoringfor the optimization and health monitor-ing of entire power distribution net-works. Ideally suited for direct buried,cable tunnels and cables installed withinmultiple cable ducts.

“The benefits for monitoring power

cables are that it provides real-timedynamic temperature information along

the full length of transmission cables andcomplete networks for load maximiza-

39September 2007


tion and health moni-toring, while identify-ing small hot spotlocations and tempera-tures (joint healthmonitoring for exam-ple) with no need ofprior knowledge,” saysKalar.

“It provides accu-rate and actual temper-ature data for inputinto dynamic cable rating systems or cal-culations based on installed conditions,establishes cable thermal profiles andfootprints and additional early fire detec-tion in cable tunnels and ducts.”

Fiber optic-based distributed tem-perature monitoring is of a particularadvantage in several common situations:

• When there are a large number ofsensors to be placed. If it is necessary toplace a lot of temperature sensors forcomplete monitoring, then the ease ofinstallation of fiber optic DTS becomesapparent. A single optical fiber canreplace many point sensors, so all that isnecessary is to route the fiber so that itprovides the necessary measurement

coverage and density.• When there is no prior knowledge

of sensor placement. When the prelimi-nary engineering is performed on a pro-ject, it is not always possible to deter-mine the correct location for temperaturesensors. The high spatial resolution andlong range of a fiber optic sensor allowsthe operator to select which parts of thefiber to monitor after the project is com-plete.

• When electrical temperature moni-toring is impractical. In a situation wherethere is a large amount of electromagnet-ic noise, the data being read from ther-mocouples and thermistors can be cor-rupted. However, the data being read by

the DTS is purely optical and thusimmune to contamination in this kind ofenvironment.

• When electrical temperature moni-toring is unsafe. There is a risk of spark-ing inherent in all electrical systems. Ifthe atmosphere in the area being moni-tored is in danger of becoming volatile,then the fact that a fiber optic DTS doesnot present a spark hazard can be a sig-nificant safety advantage.

But the true benefit of DTS technol-ogy is its ability to fit into the overallSCADA and smart technologies operatedby the utility.

“We are simplifying the DTS hard-ware so you don’t need specializedexpertise to operate it within the substa-tion and distribution monitoring sys-tems,” says Kalar.

And for smaller utilities, compatibleand simple mean greater savings.

“For a big utility, it is easy – one sys-tem and one circuit. But for small utili-ties, they need one system that is portableand can monitor multiple circuits. It iscrucial that we can work as a node with-in the SmartGrid. It needs to be an activeplug-and-play technology.”

Electricity Today40


AEP’s Operating Companies areoccasionally asked to place sections oftheir transmission lines underground.(Transmission lines differ from distribu-tion lines by virtue of their much highervoltage capacity – generally above40,000 volts.) The reason given for suchrequests relates to aesthetics in mostinstances.

This article outlines the various fac-tors that govern decisions about theplacement of transmission lines andwhether they are built overhead or under-ground.

BACKGROUNDElectric transmission facilities form

the backbone of the bulk electric powernetwork. Generally, power lines of 69kilovolts (kV) to 765 kV are consideredto be transmission level voltage.Underground transmission involves aconstruction technique that encapsulatesthe conductor in an insulating materialbefore burying it beneath the ground sur-face.

Due to the different electrical char-acteristics of underground construction,the actual amount of power a buried linecan carry is significantly lower than theamount of power an overhead line candeliver. Underground lines physicallystore a significant amount of electricalcharge, which means that a larger portionof the line is required to carry the powerflow. As a result, underground transmis-sion lines must be relatively short or useexpensive methods, like shunt compen-sation, to improve the flow of power.

Generally, underground transmis-sion is used in urban areas due to the lackof usable rights of way for overheadtransmission. Construction in this envi-ronment usually entails installationsunder sidewalks or under roadbeds. Thisincreases the amount of labor needed tocut roads/sidewalks, trench, refill thetrench and repair the surface.

To date, 500kV has been the highestvoltage transmission cable successfullyplaced in underground operation world-wide. The highest in the U.S. is 400kV. Aprototype PPP-insulated 765 kV HPFF

(High Pressure Fluid Filled) cable sys-tem successfully completed long termqualification tests at the Electric PowerResearch Institute Waltz Mill TestFacility, but has not been commerciallydeployed as yet.

COST ISSUESUnderground cable system costs

depend strongly upon the specific designand installation conditions. It is notappropriate to simply state a “standard”cost ratio of underground to overhead.Cost ratios have ranged from 1/1(because of very expensive overheadconstruction in urban area, with manyangle structures) to more than 20/1 (ruralareas, inexpensive overhead construc-tion).

Note that the ratio often depends

more on the denominator (overheadcosts, such as line construction) than thenumerator. Underground cables arealways going to be more expensivebecause every foot of the route must beexcavated and restored. In some caseswhere the ratio has been low, the utilityhas been faced with acquiring extremelyexpensive right-of-way for the potentialoverhead line.

EVALUATING THE PROS AND CONSOF UNDERGROUND TRANSMISSIONBeyond the aesthetic value of under-

ground transmission lines, typical forcedoutage rates are lower than those foroverhead lines. This is because under-ground lines are not exposed to storms

41September 2007

TRANSMISSION

FACTORS AFFECTING UNDERGROUNDPLACEMENT OF TRANSMISSION FACILITIES



and trees.However, the combined effects of

forced outage rates and repair times mustbe taken into account when comparingthe overall reliability or availability ofboth types of transmission. When this isdone, the availability of overhead lines istypically higher than those for under-ground lines (see Table 1).

Although a narrower right of way istypically needed for underground trans-mission, the entire right of waymust be cleared to allow accessand visibility. Short growingvegetation is sometimes allowedin overhead rights of way.

Material lead times, espe-cially the underground cable andsplices, are significant. This isdue generally to the low amountof demand and the ability of themanufacturer to gear up to a par-ticular cable. This causes theutility to keep a significant amount ofinventory in case of emergency or risk amulti-month circuit outage. Due to thisfact, multiple redundancy is often builtinto underground circuits by laying par-allel circuits for emergency, therefore,increasing cost.

RELIABILITY ISSUESOutages on underground transmis-

sion cables are primarily caused by dig-ins (i.e. cable damage due to excavationin the vicinity of the underground line).Consequently, the damaged cables mustbe located, and then exposed and time-consuming repairs must be completedbefore the cables can be returned to ser-vice. Typical repair times for under-ground transmission forced outages areone to three weeks or longer, months, insome cases.

Outside of physical damage due toexcavations, underground splice failureis the leading source of transmissionunderground cable failures. Splicing is alabor intensive, manual process that joinssegments of underground transmissioncables. Besides introducing a source ofelectrical resistance, this connectionpoint also increases the chance for mois-ture to migrate into the conductor allow-ing for an electrical short to occur.

Protecting underground systems isalso a challenge. Because most cablefaults are direct shorts (not induced bytransients, i.e., lightning), reclosing on

cables is rarely done automatically. Thismeans that any protective equipmentoperation will lead to a sustained outageon the cable circuit until a comprehen-sive inspection is done of the visibleparts of the cable or a non-destructiveelectrical test is done on the cable priorto returning power to the line.

As a result of the much longer repairtimes for underground transmissionlines, it is relatively common practice todesign cable circuits with 100 percentredundancy. That is, two parallel cablecircuits are often installed with each of

the two cables having sufficient capacityto carry the rated load of the circuit forthe duration of contingency (typicallythe mean repair time). This obviouslyincreases the cost of new transmissionconstruction.

INSULATING UNDERGROUNDCABLES

All power cables must be insulatedfrom the ground to achieve meaningfulpower flow.

This is achieved by encapsulatingthe aluminum or copper power line withan insulator.

This insulator can take severalforms; from fluids (most common, i.e.,insulating oil) to solids (non-conductingdielectric polymer) to gas (sulfur hexa-fluoride - SF6). Each has characteristicbenefits and flaws.

There are significant differences inthe maximum ampacity (current-carry-ing capacity in amperes) and powertransfer ratings of the different types oftransmission cables.

OIL/GAS-COOLED UNDERGROUNDCABLES

High Pressure Fluid Filled (HPFF)underground transmission systems withsystem voltages of 69kV to 345kV havebeen in commercial operation for over70 years. HPFF cable systems with rated

September 2007

Table 1 – Typical Reliability Statistics for 138 kV HPFFCable and 138 kV Overhead Lines


43

Underground transmissionContinued from Page 41


Electricity Today44

This article describes the design,implementation, and commissioning of acomplete protection and control systemretrofit project at a large transmissionsubstation. Fort Thompson Substation,located in South Dakota, has two345/230 kV step-down transformers withtwo 345 kV lines and twelve 230 kVlines. Western Area PowerAdministration (Western) undertook aproject several years ago to completelyrenovate all the protection and controlsystems at this substation. They used theautomation practices that Western haddeveloped to reduce costs of new substa-tion construction.

While it is easy to cost justify inte-grating and automating systems whenbuilding a new substation, it is tradition-ally more difficult to justify automationsystem upgrade schemes when doing arenovation project. However, recentinnovations in the integration capabilitiesof microprocessor-based protectiverelays, and other substation IEDs, make acomplete integration system upgrade,including automation, cost effectivecompared to selective replacement ofindividual IEDs, wiring, and testing.

This article describes the justifica-tion and special challenges of automatingan existing substation.

It also discusses the overall systemdesign concept of the integration andautomation schemes that were employed.Topics covered in the article include:

• Extensive use of fiber-optic cablesto replace all control wiring in the yard;

• Extensive use of multifunctionalprotection devices to eliminate wiringand equipment that would be required ina traditional design;

• Replacement of hardwired lockoutrelays with “soft” logic;

• Elimination of hardwired I/O to theRTU;

• Project management tools used toensure completion dates and to maintainbudget;

• Challenges of designing operatorinterface screens;

• Impact on the workforce in migrat-ing to a completely automated substa-tion;

• Insights gained in testing and com-missioning the substation.

INTRODUCTIONWestern Area Power Administration

markets and delivers reliable, cost-basedhydroelectric power and related serviceswithin a 15-state region of the central andwestern U.S. and is one of four powermarketing administrations within theU.S. Department of Energy whose role itis to market and transmit electricity frommulti-use water projects. Western’s trans-mission system carries electricity from55 hydropower plants operated by theBureau of Reclamation, U.S. ArmyCorps of Engineers, and the InternationalBoundary and Water Commission.Together, these plants have a capacity of10,600 megawatts.

Western started its automation pro-jects with the goal of reducing the con-struction cost of new substations.Western estimated it could save 40 per-cent in building size and cost alone.Western also estimated similar savingscould be realized in control panel costswith integrated digital controls.

Western began deploying program-mable logic controller (PLC) control sys-tems in 1996 with a pilot project at theFort Thompson 230 kV yard. The pilotsubstation consisted of four 230 kV lineswith a breaker-and-a-half bus arrange-ment. These initial designs replaced onlythe substation control wiring — noaspect of protection was included in theproject. The PLC designs included anindustrial computer running aWonderware InTouch software applica-tion as the local operator’s monitoringand control system human-machineinterface (HMI). After modifications tothe original design, the PLC design

became the standard and was deployed in20 substations across Western’s serviceterritory.

Western started looking at alterna-tives to the PLC design soon after theseinstallations, and in 1998 they attendedthe open house and demonstration of thePhiladelphia Electric Company (PECO)integrated system design. Meter andrelay (M&R) mechanics at Western werenot comfortable or confident with work-ing on the PLCs and associated ladderlogic, but they were comfortable workingwith microprocessor relays. Western alsoexperienced PLC control failure associat-ed with the use of the protocol interfaceto SCADA. Western felt that movingcontrol functionality from the PLCs to amicroprocessor relay and communica-tions processor would address the relia-bility and comfort issues that the M&Remployees had with PLCs. Eventually,Western chose the highly reliable combi-nation of microprocessor relays and com-munications processors as their new dig-ital control system (DCS) design toreplace the PLC-based platform andchose to make Fort Thompson a pilotproject. Once again, as was done with thePLC project years earlier, the pilot sub-station consisted of four 230 kV lineswith a breaker-and-a-half bus arrange-ment.

In the conversion from the PLC con-trol system to the DCS design, Westernalso decided to include protective ele-ments, or lockouts, in the DCS design.One lesson learned from the PLC designwas that mixing digital and hardwiredlogic adds complexity to both portions.Because of the design and manufacturingprocesses, typical MTBF, and environ-mental ratings of PLCs, Western was notcomfortable placing any protective func-tions in the PLC. Because the DCSwould use protective relays for control, itseemed natural to have the lockout func-

CONTROL SYSTEMS

DIGITAL CONTROL SYSTEMS FORHIGH-VOLTAGE SUBSTATIONS - PART I

By James Propst, Western Area Power Administration (WAPA) and Mike Dood, Schweitzer EngineeringLaboratories, Inc.



system voltages up to and including765kV are commercially available andhave passed long-term qualification tests.

High Pressure Gas filled (HPGF), issimilar in construction but the dielectricfluid is replaced by 200 psig nitrogen.HPGF cable systems are not commer-cially available for system voltagesabove 138kV.

Gas Insulated Transmission Lines(GIL) have been used in applicationswhere high power transfer capabilitiesare required, such as short dips in over-head lines or relatively short substationconnections to overhead lines. GIL gen-erally utilizes SF6 gas as the insulatingmedium.

Compressed-Gas transmissioncables have significantly higher ampaci-ty ratings (5 kA and higher) than theother cable system types because:

1. The relatively low insulatingstrength of gases (compared to solid andlaminar fluid filled electrical insulations)means that the diameters of the high volt-age conductor and aluminum enclosuremust be large. Therefore, the current rat-ings are also large because of the largecross section of the high voltage conduc-tor and enclosure.

2. Dielectric losses, which are lossesof energy that cause a rise in the temper-ature of the gases (nitrogen and SF6), areextremely low compared to most solidand laminar insulating materials. As aresult, compressed-gas cables haveincreased ampacity ratings.

Self-cooled HPFF and HPGF trans-mission cable systems with very largeconductors (3,500 thousand circularmills - kcmil) typically have power trans-fer capabilities of 1,200 amperes or less,which is significantly less than self-con-tained, fluid-filled (SCFF) cable systems.This is due to the following reasons:

1. Magnetic losses in the magneticsteel pipe, like eddy current and hystere-sis, are comparable to the losses causedby heat in the high-voltage conductors.The pipe losses significantly decrease theampacity rating of the cables inside ofthe pipe.

2. Losses of energy, resulting in therise in heat of laminar, fluid-impregnatedinsulation are significantly higher thanfor XLPE extruded dielectric insulation.

DIELECTRIC (NON-CONDUCTING)POLYMERS

The first major domestic 345kVsolid dielectric transmission systemswere installed in Connecticut, LongIsland and Chicago in the past severalyears. Elsewhere, hundreds of miles of230 kV solid dielectric cable systemshave been installed in numerous coun-tries around the world and tens of milesof 400 kV solid dielectric cables havebeen installed in Europe. Japan complet-ed installation of the first sizeable (twocircuits, 25 miles long) 500 kV cross-linked polyethylene (XLPE) transmis-sion cable system in late 2000.

XLPE-insulated cables have a sig-nificantly higher power transfer capabil-ity than pipetype systems because of thelower dielectric losses, absence of pipelosses, and greater separation amongphases. Large conductor size cables canhave ratings greater than 2000 amperes.

The ampacity rating of XLPE trans-mission cables are higher compared tothe same conductor size SCFF cable sys-tem because of the lower dielectric loss-es and charging current of the XLPEcables.

SUMMARY CONCLUSIONS• The cost to place transmission

facilities underground is, at a minimum,

2-3 times more than the comparableoverhead option. In some situations, thecost difference can be 10 times more.

• Utility commissions typicallyallow electric utilities to include in therates charged to all its customers, onlythe reasonable costs of facilities neces-sary to provide safe and reliable service.In most cases, this would be the cost ofoverhead lines. Thus, unless there areextenuating circumstances that dictatethe use of underground facilities in lieuof overhead facilities, AEP would not beable to recover the premium paid toplace facilities underground.

• The time and cost required to iso-late and repair a problem with under-ground transmission lines is normallymuch greater than for overhead lines.Circuit outage times will almost alwaysbe greater, too, thus raising the reliabili-ty risk of operating the system withoutall lines in service, and raising the poten-tial for customer dissatisfaction withlengthy outages.

• Underground transmission linespose a significant safety hazard to non-electric utility construction personnelwho do not follow proper protocols/laws/rules and accidentally dig into theselines.

45September 2007

Underground transmissionContinued from Page 43


With the continued commitment of the Ontario govern-ment to eventually phase out the coal plants as part of theirgreen energy plan, and with climate change moving to the topof the political agenda worldwide, carbon free options, includ-ing nuclear energy, will become even more important for meet-ing the growing energy demands of the province.

In Canada, nuclear power accounts for 15.5 per cent of theelectricity mix, and provides 54 per cent of Ontario’s electrici-ty sources. However, Ontario’s nuclear plants are aging, andmany will be in need of refurbishment over the next decade. Ifthese aging nuclear plants are not refurbished, Ontario will beleft with only 5,900 MW of nuclear capacity by 2015 – only asmall fraction of what will be needed; and with large scaleoptions, such as gas fired plants, subject to price volatility, thefuel required for this will likely be in scarce supply.

In October 2005, Bruce Power, Ontario’s second largestutility, awarded AMEC a contract to project manage the restart

of two of its nuclear reactors, Units 1 and 2, at its Bruce Apower station. Bruce Power, which is located on the shore ofLake Huron, is home to eight CANDU pressurized heavy waterreactors. Units 1 and 2 were shutdown in the mid-1990s whenthe then owner Ontario Hydro decided to concentrate resourceson operating its other reactors. The enormous significance ofthis project can be seen in the investment required to bring theUnits on line again. The project is estimated to cost C$2.75 bil-lion (US$2.43 billion), funded by the private sector, and isexpected to be complete in 2009.

AMEC is providing project, contract and constructionmanagement for this highly complex project, as well as engi-neering acceptance, and the health, safety and environmentalprograms and oversight. Currently, the project has over 2,000staff, working both on and offsite, which is near the peak ofworkers expected during the project.

The restart project is one of the largest and most challeng-

Electricity Today46

NUCLEAR

ADDRESSING CLIMATE CHANGE CHALLENGESTHROUGH NUCLEAR TECHNOLOGY

By Kevin Routledge, President of AMEC NCL


ing engineering projects to take placein North America. The projectrequires a series of refurbishments,upgrades and enhancements to thetwo reactors. The work includes:

The replacement of reactor’spressure tubes and calandria tubes(480 in each reactor);

Replacements of half the lengthof feeder pipes, which provide waterto the fuel channels;

Steam generator replacements (8-110 t vessels in each unit);

Electrical systems upgrades;Main condenser refurbishment;Turbine refurbishment;Feed water heater refurbishment;Shutdown system 2 (SDS2)

enhancement; andSignificant other maintenance on

both nuclear and other plant equip-ment.

For the remainder of the plant, the opportunity is beingtaken to upgrade and enhance other nuclear and non-nuclearsystems. For example, 30 transformers in the two units containpolychlorinated biphenyls (PCBs). These will be removed andreplaced with non-PCB transformers.

After both nuclear and non-nuclear systems have beenrefurbished and upgraded, Bruce Power will request permis-sion to refuel Units 1 and 2 from the Canadian Nuclear SafetyCommission. During refueling, the reactor will be loaded withnatural uranium fuel, except for a small number of depleteduranium fuel bundles, used to fine-tune reactivity in the freshcore, at specific locations. Each reactor will require 576 22.5kg fuel bundles or approximately 260 t of fuel for the initialrefueling.

From a physical standpoint, this project is extremely chal-lenging, but this project is also demanding from a regulatorystandpoint. Refueling will require a license amendmentenabling Bruce Power to move the reactors from a safely-laidup state to a guaranteed shutdown state. Refueling and associ-ated operations such as refilling the primary heat transport sys-tem, final system integration, and commissioning will precedesynchronization to the power grid by approximately fivemonths.

The overall aim is to improve the safety of the reactors,and to increase potential generation capacity and reliability.Completion of the project will enable each Unit to producesafe, economical power for an additional 25 years.

Since the project commenced on October 31, 2005, theproject continues to schedule, and has achieved the followingmilestones:

The environmental assessment was approved, without anynegative interventions;

An offsite training facility has been set up and operated,with, to date, over 3500 workers trained in project processes,prior to them starting work on site;

Major offices and warehousing facilities are in place;A construction island has been created around Units 1 and

2, with separate processes and procedures from the operatingunits;

Both Units has been fully isolated from the other units, anddecontaminated; with work at the reactor face in Unit 2 already

able to be undertaken in “civvies”;Feeders in Unit 2 have been removed and progress is well

in hand for removal of the fuel channels; and, Ten of the 16 new stream generators have arrived on site

and four are now installed.Safety is of paramount importance on this project, and, to

date, over 5 million hours have been worked on site without alost time incident. In addition doses to workers are well belowbudgets, as is the radioactive waste being dealt with on the pro-ject. Environmental impacts from the construction work havebeen minimal.

In addition to AMEC, there are other well known Canadiancompanies involved with this project including Atomic Energyof Canada Limited (AECL) , who is replacing the fuel channelsof the reactors; Babcock and Wilcox, who is supplying thesteam generators and installed bulkhead plates to isolate theunits; SNC Lavalin, who is removing and installing the newsteam generators; Siemens Canada, who is responsible forrefurbishing the turbines and the electrical systems; andAcres/Sargent Lundy, E S Fox, RCM Technologies, GeneralElectric of Canada, and Ontario Power Generation, on the bal-ance of the work.

Though refurbishments can be completed faster, and thecosts are less than building a new nuclear power station, legacyissues and proximity to the operating Units, make it more com-plex. The task of removing steam generators, as well as pres-sure tubes, calandria tubes and feeder pipes at the same timesignificantly increases the challenge, particularly as a numberof these evolutions are first of a kind in the industry.

The Bruce A restart is just the first stage of a much broad-er C$4.25 billion (US$3.76 billion) program to extend the lifeof the station planned by Bruce Power. With increasingdemand, and aging assets, the success of the Bruce A restart iscritical to securing Ontario’s energy future.

With the Bruce A restart project now well advanced and onschedule, this project will ensure nuclear power continues toplay a key role in a diverse energy strategy for Ontario.

Kevin Routledge is President of AMEC NCL, the nuclear divi-sion of AMEC in North America, and was until very recently theProject Director for the Bruce Restart project. For more infocontact [email protected]

47September 2007


Electricity Today48

tion reside there as well. Western chose asingle dedicated microprocessor breakerfailure relay as the “input” point to theDCS system. The outputs from the DCSsystem used contacts from the breakerfailure relay and one of the line relays toprovide a redundant control path for thepower circuit breakers. Communicationsprocessors were used in the design toprovide the interface to SCADA and thelocal HMI.

Although this initial DCS designwas a step in the right direction, it wasapparent that an additional iteration inthe design would be required to provideenhanced economy and simplicity.

The next iteration was the use offiber-optic cable to replace copper com-munications and the relocation of theDCS system inputs to be field I/Odevices mounted near the station appara-tus rather than duplicate the inputs withparallel copper wiring to the centralizedIED. Thus, integrated digital communi-cations allowed the I/O of the IEDs to beused for several functions within theDCS. A single 52a contact from thebreaker auxiliary stack, wired to a remoteI/O device, was used to provide this sta-tus for the entire system, including theprotective functions.

Alarm points were wired only intothe I/O device at the equipment, insteadof also being separately wired to the con-trol building and connected to an RTU.

PROJECT DEFINITIONFort Thompson 345 kV Yard

Operations determined that the345/230 kV transformers in the 345 kVyard should be separated from a commonbus, creating a four-position ring busconfiguration. This work required theaddition of a 345 kV breaker andrequired modifying the bus work. Thesubstation controls and relaying werelargely original equipment from the1960s. Western decided to replace thecontrol panels because extensive wiringchanges were needed to bring the substa-tion up to current Western standards forSCADA.

The substation was built on expan-sive soils, which tend to move consider-ably, and which caused the foundationfor the control building to crack in half.As the two halves settled, a three-inchcrack developed in the wall, which had

been covered with a steel plate to keepthe birds out.

These problems made fixing thebuilding impractical, so it was replacedwith a modular, energy efficient, low-maintenance building. The design of aDCS using integrated relays allowed thebuilding to be over 40 percent smallerbecause integrated systems are muchsmaller than conventional PLC and RTUcontrol designs.

The expansive soils over the yearshad created shifting in the control cabletrays, causing the covers to have gaps.These gaps allowed rodents to enter thecable tray, causing substantial damage tocontrol cable jackets. Unjacketed cablewas eaten bare in many spots. The jointowner of the substation equipmentagreed the control cable should also bereplaced.

Fiber-Optic CableFort Thompson, like most 345 kV

substations, is a large substation. Cablelengths up to 1,000 feet were to bereplaced. At the time of this project, 12/C#10 shielded cable cost about $2/foot.

Because the project would requireabout 17,000 feet of 12/C cable, the use

of fiber-optic cable was considered as anoption. Western determined that theycould replace the 17,000 feet of 12/Ccopper with 2,700 feet of fiber-opticcable. The cost of 24-fiber cable at thetime of the project was $1.84/foot. Thisrepresented an upfront savings of$29,000, which would be spent on addi-tional hardware requirements for the useof fiber-optic cable. The concept up frontwas to show fiber was competitive withcopper in the substation.

The fiber-optic cable would beinstalled to each circuit breaker, trans-former, and reactor. Motoroperated dis-connect (MOD) controls and inputswould be wired over copper cable fromthe MOD to the associated circuit break-er where a remote I/O device would beinstalled to accommodate both MODsassociated with the circuit breaker. At thetransformers, alarms and trips from sud-den pressure, winding temperature, andlow oil would be connected to the remoteI/O device and brought to the controlhouse over fiber. Coupling the MOD andMOI controls with the major equipmentwould save fiber terminations.Considerable amount of copper cablewould be saved because the MODs were

High-Voltage SubstationsContinued from Page 44

Figure 1. Fort Thompson 345 kV yard bus arrangement after Stage 06 modifications werecompleted. Four 345 kV circuit breakers, three 13.8 kV reactor breakers, eleven 345 kVMODs, and two 345 kV interrupters are under DCS control.


close to the circuit breaker, elimi-nating up to a 1,000 feet of 12/Cfor each MOD from the controlhouse.

The use of fiber-optic cablewould allow the digital inputs tobe input into the DCS at theequipment. Western estimatedthat at least 75 percent of the DCwire terminations were eliminat-ed. Consider that a cable must beterminated on each end, in thiscase to a terminal block in thebuilding, then to a terminal blockin the RTU, and finally to theRTU. This would all be replacedwith a single switchboard wire atthe individual piece of equipment.

About this same time, thelogic processor became availableon the market. This device allowsthe digital inputs to be distributedin real time among the relays andprovides SOE (sequence-ofevent)information for the RTU. Thelogic processor allowed a single52a contact from the breaker to be distributed digitally overcommunications links to the primary relay, secondary relay,breaker failure relay, and the RTU. This further diminished therequired wiring terminations.

The logic processor would also be used to create anextended digital protection system that tied all the individualpieces of equipment together to create an extended integratedprotection system.

Because the logic processor would be used for SOE infor-mation, it needed to receive the digital relay operate event. Thissame piece of information would be sent to the breaker failurerelay to initiate breaker failure. The use of the logic processorwould eliminate the long block closing strings and breaker fail-ure initiate wiring. All of this hardwired logic would bereplaced with EIA-232 cables and settings.

Past FunctionalityFrom the very first pilot project, Western had a high level

of information flow with operations personnel, and they pro-vided the manufacturer with feedback on their operationalrequirements.

Redundant controls were established as a requirement, asthere was a concern about the ability to respond to and correctequipment failures with the new design. For the same reason,redundant HMI computers with redundant power supplies andhard drives running (Redundant Array of Independent Drives)RAID 1 controllers were used. The new center of the system,the communications processor, had Modbus Plus protocolavailable, so Western’s previous HMI design modules, alsobased on this protocol in the PLC, were used with very littlemodification.

Good SiteFort Thompson was deemed a good site for this project,

because it was relatively small. A total of 7 breakers and 13switches would be placed under DCS control. This wouldrequire fiber to be installed to 11 pieces of equipment — a very

manageable number. The physical size of the yard made thefiber attractive, because a lot of copper cable could be elimi-nated. And, finally, the project had strong support fromWestern’s Communications division, which installed and termi-nated the fiber-optic cable.

THE DCS DESIGNControls

Western operations personnel wanted the ability to trip andclose a circuit breaker in the event of equipment failure.Therefore, Western designed redundant controls as a standardpart of the automation design to eliminate single points of fail-ure. The redundant control paths were accomplished using atwo-tiered communications processor approach. The top-tiercommunications processor receives the SCADA command anddistributes it via global data over the Modbus Plus network tothe lower-tier communications processor. This creates a singlepoint of failure for SCADA with the top-tier communicationsprocessor, but with an MTBF of greater than 200 years, this riskwas accepted and is far better than single or redundant RTUs.

From the lower-tier communications processors, controlswere passed to the individual protective relays. From the pro-tective relays, positive, negative, trip 1, trip 2, and close werehardwired with a 5/C to the circuit breaker. Most circuit break-er protective trips were hardwired from the protective relays.Some of the bus protection trips were accomplished with relay-to-relay communication via the logic processor. In this design,the Set A protective relay and individual breaker failure relayprovided the redundant control paths for the 345 kV circuitbreakers. The individual breaker failure relay also directly con-trolled operation for the MODs adjacent to the circuit breakervia fiber-optic cable.

Eleven MODs and two motor-operated interrupter (MOI)controls were included in the design.

Only DC power was run to the MODs; control is accom-plished using the remote I/O devices connected to the fiber-

49September 2007

Figure 2. Communications Processor Architecture


optic cable. Open/close commands are sent via fiber from theindividual breaker failure relays to the remote I/O devices.

Reclosing, hot-line orders (HLO), synchronizing, andlocal/supervisory statuses for the individual power circuitbreakers are maintained with latch bits in the individual relays.The latch bits are used in the internal logic of the protectiverelays to obtain the control functionality.

The HMI control actions are sent to the lower-tier com-munications processor via the Modbus Plus network. Thisdesign allowed for the failure of any one box while still main-taining local control.

SUBSTATION COMPUTERHardware Design

Western has used Wonderware as the HMI in their digitaldesigns for several years. Due to the very limited knowledge ofthis software and computers in general in the workforce and theassociated concern over the ability to respond to equipmentfailure, Western chose an industrial PC. Western purchasedredundant PCs with hot-swappable redundant power suppliesand hotswappable redundant hard drives. The hard drives use aSCSI RAID 1 controller to mirror the drives. The PCs are rackmounted in the control panel. To provide isolation to transientsand to power the PCs, Western installed redundant DC-ACinverters that are normally fed from AC but switch to DC uponloss of AC. The inverters served as a universal power supply,because they switch supply sources without causing any dis-ruption in the PC. A keyboard, video, mouse (KVM) deviceswitches the PCs to a single set of LCD displays, keyboard, andmouse.

HMI Application DesignWestern uses a dual display for the HMI. The left screen

displays the station one-line with status.They also use the buttons on the left screen to fill in the

variables in the right screen template used for PCB control. Thebuttons rise when the cursor is placed over them. The 43LS, 79,and 85 statuses are shown directly on the screen. The 43LR,52a, and 52b drive the color of the breaker status. When the43LR is in the local position in the circuit breaker, the breakerstatus box is gray, with an M for “Maintenance” indicationindependent of the breaker position. The circuit breaker closedindication is red — open is green.

Western’s Power System Clearance procedures detail twoprimary tagging procedures — one for HLO and one for clear-ances. Western does not tag equipment controls under clearancewith power system clearance tags. The only tag included in theHMI was for hot-line orders. The HLO tag indicates reclosinghas been turned off and the circuit breaker close path has beeninterrupted.

Within the HMI, the HLO tag cannot be turned on whenreclosing is in place. The HLO is represented on the one-linescreen by a yellow HLO tag and flashing indication on the PCBcontrol screen. If the close function is selected, an HLOWARNING screen is displayed, and closing is prevented.

The PCB control screen has a representation of a physicalswitch for each function. The switch representation was chosento make the HMI intuitive. The PCB control screen is the samefor all equipment, with only the appropriate functions visibleand active. For example, the 85 function is disabled for dedi-cated transformer breaker, or reclosing for a reactor breaker isdisabled. The HMI works by sending the command to the pro-tective relays and then reading the status back via the commu-nications processor to effect changes on the HMI displays. Theswitch handles rotate and lights change to indicate the appro-priate status on the PCB control screen.

See the October issue of Electricity Today for Part II

Electricity Today50

Figure 3. The I/O device on the right provides open and closecommands for the MODs. It also provides the 43LR, 52a, and 52bstatus to the DCS. The I/O device on the left provides inputs intothe DCS for the individual power circuit breakers. Note the extrafiber-optic cable, which allowed terminations to be completed ina mobile van and provided additional cable for when the powercircuit breaker is replaced.

Figure 4. Left Fort Thompson 345 kV yard HMI display. The powerflow indication and quantity for the transformers is obtained fromadding the individual breaker failure relays.Note the HLO tag on 2996.


Electricity Today52

Operational Cyber SecuritySolutions for Substations,

SCADA, and AMI.

NERC Compliancy Reports

Handling Cyber Security for theSmart Grid

Peter D. VickeryExecutive Vice President of Sales,Marketing & Business Development9030 Leslie Street, Unit 300Richmond Hill, ON L4B 1G2Phone: (905)-707-8884 ext 223Cell: (416)-951-8811Fax: (905)[email protected]

PRODUCTS AND SERVICES SHOWCASE


53September 2007

PRODUCTS AND SERVICES SHOWCASE / ADVERTISERS INDEX

ADVERTISER PAGE CONTACT INFO

3M 7 www.3m.com

http://www.electricityforum.com/products/3M_Canada_Company.html

American Polywater 35 www.polywater.com

APPrO 23 http://conference.appro.org

Bulwark 13 www.vfc.com

Critter Gurad Inc. 10 www.critterguard.org

Dupont 11 www.dupont.ca

http://www.electricityforum.com/ici/dupont.htm

E-Dist 51 http://www.edist.ca/

Elster Integrated Solution 55 www.elster-eis.com

http://www.electricityforum.com/products/elster.htm

Enercom 42 http://www.enercom.to/

ETAP 37 www.etap.ca

FLIR Systems Ltd. 28, 52, 56 www.flir.com

www.electricityforum.com/products/flir.htm

Fluke Electronics 25, 27, 33, 40 www.flukecanada.ca

http://www.electricityforum.com/products/fluke.htm

Golder & Associates 34 www.golder.com

www.electricityforum.com/ici/GolderAssociates.htm

Hercules Industries Inc. 52 www.herculock.ca

http://www.electricityforum.com/products/hercules.htm

Power Cable Rejuvenation TechnologyCableCURE®/XL

CableCURE®/XL isinjected into the strandsof medium and highvoltage power agedcables. It providessubstantial dielectricenhancement andextends the cable lifefor an additional 20years.

The silicone fluid diffuses out of the strandswhere it is injected into the insulation. The fluidthen polymerizes with water and the smallsilicone molecule grows up to seven times itsoriginal size and fills all existing water trees andvoids. The cable rejuvenation molecules areanchored within the insulation material. Excessfluid works as a tree retardant far into the future.

CCIS Services:CableCURE/XL Dielectric EnhancementCableCURE/CB Cable BlockCharacterize / Test / Treat or ReplaceNeutral Corrosion Detection (TDR)Splice Locating (TDR/RD 4000)

CableCURE Applications:URD & Feeder cablesNetwork cablesTransmission cablesSubmarine cablesHMWPE, XLPE, TR-XLPE, EPR, butyl-rubber

(514) 378-7836 or [email protected]


http://www.electricityforum.com/t&d/company.htm







Electricity Today54

ADERTISERS INDEX / PRODUCT SERVICES AND SHOWCASE

ADVERTISER PAGE CONTACT INFO

High Voltage, Inc. 18 www.hvinc.com

http://www.electricityforum.com/products/highvolt.htm

Hubbell Power Systems 17 [email protected]

http://www.electricityforum.com/products/hubbell.htm

I.C.M.I. 54 www.icmiinc.com

Inductive Components Manufacturing Inc. http://www.electricityforum.com/products/icmi.htm

IEEE/PES T&D 31 http://www.ieeet-d.org/

Incon 36 www.incon.com

http://www.electricityforum.com/products/incon.htm

Joslyn Hi-Voltage 39 www.joslynhivoltage.com

http://www.electricityforum.com/ici/joslynhv.htm

Kinectrics Inc. 21 www.kinectrics.com

http://www.electricityforum.com/products/Kinectrics_Inc..html

LaPrairie 2, 52 www.laprairieinc.com

http://www.electricityforum.com/ici/LaPrairie.htm

Lineal 12 www.lineal.com

Lizco 52 Sales www.lizcosales.com

http://www.electricityforum.com/products/lizco.htm

MIDAS Metering Services 8 www.midasmetering.com

N-Dimension Solutions Inc. 52 www.n-dimension.ca

NovaTech 5 www.novatechweb.com

http://www.electricityforum.com/products/NovaTech.htm

P & R Technologies Inc. 16 www.pr-tech.com

Phenix Technologies, Inc. 15 www.phenixtech.com

Power Survey International Inc. 20 www.powersurvey.com

http://www.electricityforum.com/products/powersurvey.htm

Power Tech Labs Inc. 29 www.powertechlabs.com

http://www.electricityforum.com/products/powtech.htm

R3&A 52 www.r3alimited.com

TAEHWATRANS CO. LTD 54 www.taehwatrans.com

Tech Products, Inc. 53 www.techproducts.com

TechniCAL Systems 2002 Inc. 38 www.technical-sys.com

http://www.electricityforum.com/products/technical_systems2002.htm

Timberland Equipment Limited 53 www.timberland.on.ca

Transelec 53 http://www.transelec.com/fr

Transformer Protector Corp. 19 www.trasproco.com

Underground Devices 41 www.udevices.ca

http://www.electricityforum.com/products/underground.htm

Velcon Filters Inc. 46 www.velcon.com

The Von Corporation 43 www.voncorp.com

http://www.electricityforum.com/products/von.htm

Wire Services 45 www.wireservices.ca

http://www.electricityforum.com/products/wire_services.htm

Clamp-on Current TransformerWhere you don't want to cut the power linefor measuring or monitoring AC currents.-Portable power measuring device-Sub-metering-Easy open/lock mechanism-Compact size-High accuracy of 1class

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Web: www.taehwatrans.comE-mail: [email protected]: 82 31 315 8161 Fax: 82 31 315 8165

















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