56 IEEE power & energy magazine september/october 20051540-7977/05/$20.00©2005 IEEE

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september/october 2005 IEEE power & energy magazine 57

UNTIL THE 1990S, TECHNOLOGICAL BREAKTHROUGHS IN THE AUTOMATION OFelectric distribution systems were slow to materialize. Early SCADA (supervisory control anddata acquisition) systems promised to improve reliability. But many of the early systems werelittle more than an extension of SCADA beyond the substation fence. With their relatively lowcomputational and communication capabilities, these early systems required a high degree ofhuman intervention and offered little in the way of true automation. As a result, expectationswere not always met, leading to the termination or scaling back of many projects.

Nevertheless, many lessons were learned and technology has advanced, especially throughthe 1990s and to the present. More advanced automation applications have been developed thatare far more practical and manageable for utilities to implement.

Technology continues to create an environment of ever-increasing expectations for reliabilityon the part of electric system users. The advent of widespread Internet access allows people torealistically telecommute. They can live in more rural areas where power reliability is oftenlower than in urban settings. And the expanded use of sensitive computing technology, both inthe home and in industry, requires increasingly more reliable power.

Deregulation was a sea change for electric utilities. It resulted in rampant cost cutting,including early retirement programs, layoffs, cutbacks, hiring freezes, and other euphemismsfor reducing headcount. Along with the reduced headcount came a loss of experience in run-ning electric utility systems. The engineers who were left to run the system are now nearingretirement age, and utilities now face a crisis of experience. Although hiring is currently invogue, will it be enough?

Fortunately, the new generation of utility engineers and personnel were brought up on PCsand PDAs and are well poised to make full use of advancements in feeder automation (FA) tech-nology. They can consider the use of high-speed, small-scale computing and high bandwidth—the 1981 engineer could only dream of such sophisticated communication technology.

Why Automate?Before considering the “how,” a review of why onemight wish to automate their distribution feeder sys-tem is in order. The reasons cited for implementationof distribution automation are varied. Significant reli-ability improvement is the number one reason offered.Reduction of SAIDI (system average interruption dura-tion index) is a key driver. In some states, the publicutility commission has mandated performanceimprovements, either through direct mandate orthrough performance incentives (or penalties).

Most importantly, when a decision to improvereliability has been made, then the evaluation of relative costs to reduce SAIDI shows that feed-er automation is the least costly and almost always the quickest route to achieving that goal. Fig-ure 1 illustrates how a typical outage restoration scenario might progress both with and withoutadvanced feeder automation. The times shown will be extended even further during storm con-ditions when dispatchers are juggling multiple outage investigations.

When automation using distributed intelligence is applied on distribution feeders, restorationof unfaulted segments occurs in less than one minute. And the more the feeder is segmentedwith automated switches, the more SAIDI improvement can be realized.

It is easy to justify automation when the public utility commission is mandating reliabilityimprovements, especially when monetary penalties and rewards are in play. Plus, there is boundto be some savings in labor as shown above; however, other, softer costs and benefits also apply.Offering excellent service is an oft-cited reason. And energy users do take notice when the lightsgo out over and over. Maintaining a good reliability record is also cited as important when

A Look at theApplications forDistributionAutomation

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seeking rate relief; the theory is that “no news is good news,”and regulators who don’t hear negative comments from theirconstituents are more likely to be sympathetic to a request fora rate increase.

Still, other utilities see good reliability statistics as an element that can attract new business and new energy sales tothe territory. A key benefit of attracting new business is that italso tends to bring new jobs to the area, hence increased taxrevenue to the local government.

Advanced feeder automation is also a viable tool forwringing the maximum out of feeder assets. Many utilitiesalready have some sort of distribution automation schemeutilizing looped circuits to provide backup in the event of afault on a part of the loop. But the current allowed to flow ineach half of the loop is typically limited to 50% of itscapacity to allow the circuit to pick up faulted segments ofanother circuit.

If one measures load on various points along the feeder ona continuous basis, it is possible to compare real-time loadingprior to a fault against stored capacity values and decide,based on the result, whether to pick up load or not. Such aprocess permits the utility planner to allow the load to rise to75% or greater on a feeder, without risking costly feederdamage due to overloading. Also, ties to multiple circuits cansignificantly enhance the chances of getting the lights backon for any given situation. But, manually performing com-plex circuit-restoration switching without overloading theline takes time. The answer is to use distributed intelligenceand automated switching to accomplish the task quickly,accurately, and flexibly. In fact, circuits that the planner for-

merly could not tie can now be tied, resulting in higher relia-bility and greater asset utilization.

In the end, the justification will be unique to each utility,depending upon the balance of local reliability drivers, thecost to implement changes, and external influences.

Feeder Automation ToolsSome tools for feeder automation have been available formany years. S&C Electric Company introduced medium-voltage automatic source-transfer switchgear in the 1960s.Such gear is not typically considered “automation,” but itdoes restore power without human intervention, so technicallyit qualifies.

Reclosers and breakers have also been used on electricdistribution systems for many years and are yet another formof automated fault isolation. One could even say that fusesare an automated device. After all, they respond to specificcurrents and interrupt them to clear faults.

So it seems that virtually every electric distribution systemhas some form of automation implemented (if one stretchesthe common definition a bit). The move to more advancedforms of feeder automation only requires one to consider it animprovement of the existing technology rather than the adop-tion of a completely “new” technology.

The Future Is NowIn 2003, the IntelliTEAM II Automatic Restoration Systemwas introduced by S&C Electric Company. IntelliTEAM II isa patented automatic power restoration system that uses dis-tributed intelligence and peer-to-peer communication toswitch and isolate the faulted line section and restore powerto unfaulted line sections.

IntelliTEAM II utilizes ties to multiple circuits, enabling awide variety of circuit configurations to maximize therestoration potential. Distributed intelligence prevents lineoverloads. IntelliTEAM II can automate parts of a circuit inneed of attention or an entire distribution system consisting ofopen-loop feeders with multiple tie points to other feeders. Itcan be used both tactically and strategically, based on the reli-ability problems the utility needs to solve.

IntelliTEAM II Theory of OperationIntelliTEAM II dynamically tracks system conditions onoverhead and underground distribution systems and providesfully automatic fault isolation and service restoration.

“Team” and “coach” metaphors help to describe Intelli-TEAM II operation. Each team is defined as a line segmentbounded by two to eight automated switches, each of whichcan represent a different power source. Each team has a soft-ware coach.

If an outage or line fault occurs, local control logic deter-mines if a switch should open. The coach of each affectedteam then uses real-time data, including voltage and currentdata gathered prior to the system event to develop a restora-tion strategy for unfaulted sections. The coaches of adjacent

58 IEEE power & energy magazine september/october 2005

figure 1. Outage restoration without and with advancedfeeder automation.

Return to Normal

WithoutAutomation

CrewTravel Time20–30 min

Find the Fault15–25 min

ManualSwitching10–15 min

Fault Repair1–5 h

5–10 min50

–80

min

Fault OccursCustomerReportsOutageCrew

Dispatched

CrewDispatched

Customers on UnfaultedSegments Restored

Fault Repair1–5 h

Find the Fault5–10 min

CrewTravel Time20–30 min

2–5 min

WithAutomation< 1 min

september/october 2005 IEEE power & energy magazine

teams then work together through shared controls to imple-ment strategies that will maximize restoration of the circuitwithin the prioritization rules defined by the user.

Breakers and reclosers can also be incorporated as teammembers with the addition of a module that interfaces to theelectronic relay or control that operates the breaker or recloser.Figure 2 illustrates the team concept.

The coach distributes data and coordinates the operation ofautomated switches, reclosers, and breakers. In the event of aloss of communication, service restoration may be inhibited,but an automated switch, recloser, or breaker can still isolate afault based on local fault detection and isolation software logic.

At the beginning of a fault or outage event, any team mem-ber detecting the event will communicate to all the other teammembers and the coach, reporting the time, type of event,report identification, and so on. The coach also monitors thestatus of each device, ensuring that all are in the right open orclosed position to allow progress to the next restoration step.

In order to close a switch, the coaches of adjacent teamsmust grant permission based on circuit conditions, location offault, and an evaluation of loading conditions. When allappropriate conditions are met, the switch can be closed torestore service to a feeder segment. This process is repeatedfor each segment in turn. As switches close, the IntelliTEAM IIsystem updates available capacity on the feeders used torestore service, ensuring maximum service restoration even atmaximum peak load.

IntelliTEAM II distributed control algorithms can addressmultiple contingencies. If a team is in the reconfigured stateand the alternate source experiences a new event, the teamcan look for a new alternate source, if available, to supply itsline segment. As long as an alternate is availble, some amountof service can be restored.

A large IntelliTEAM II system may have reconfigurationsoccurring simultaneously at more than one location. To pre-vent circuit overloading, the restoration logic has an additionaloption to use contracts to ensure that it will not pick up moreline segments than the circuit can supply. Contracts are nego-tiated across several teams to safely secure resources neededto energize the line segment.

Following a reconfiguration event, and subsequent repairand restoration of the faulted line section, team members canreturn to their normal state. Once the “return to normal” isinitiated, the coaches begin the process of returning eachteam to its normal configuration. The return-to-normalprocess begins at the team closest to the normal source and

works outward, using either an open or closed transitionapproach as defined by the user.

To support the distributed control architecture of IntelliTEAM II, a peer-to-peer wide-area communication network is essential. There are only a few commerciallyavailable wide-area communication systems that readily sup-port such a network. Typically, communication for the IntelliTEAM II system is provided by 900-MHz UtiliNetspread-spectrum radios. The UtiliNet radio system transportsdata using a connectionless mesh architecture. This architec-ture allows each radio in the network to act as both a repeaterradio and a data transceiver for an automated switch. Theradio network is highly scalable and obviates the need toinvest in the tall master radio towers prevalent in point-to-multipoint radio networks.

Fiber-optic networks have also been utilized for high-speed peer-to-peer communication, typically in undergroundapplications where fiber is installed along with the under-ground cable infrastructure.

Is This Real?Since IntelliTEAM II was introduced in 2003, several utilitiesin North America have undertaken strategic implementationsto automate their entire distribution system. Others have

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figure 2. An example of IntelliTEAM II used to automatefour open-loop distribution circuits.

Sub 4Sub 1 Sub 2

Sub 3

S1

S2

S3

S5

S10

S4

S6S7

S8 S9

S10

S11

Team 1 Team 2

Team 3

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Team 8

Team 5

Team 6Team 4

N.O.

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N.O.

N.O. = Normally Open

It is easy to justify automation when the public utility commission ismandating reliability improvements, especially when monetarypenalties and rewards are in play.

taken a more tactical approach. All have reaped immediateand significant benefits.

The Need for SpeedENMAX Power Corporation (Calgary, Alberta, Canada) hasembarked on a multiyear project to improve the reliability of theirdistribution system. They are continuing the deployment of anadvanced FA system on their least-reliable circuits to automatically isolate faults and restore power to unfaulted segments and to provide restoration quickly, despite the com-plex nature of the circuit interconnections. Ultimately, ENMAXenvisions automating 80 circuits on their distribution system.

When integrating the IntelliTEAM II system into theexisting ENMAX SCADA network, efforts were made tomake use of the existing infrastructure where possible and tominimize the requirement for new infrastructure.

The ENMAX system utilizes a UtiliNet radio network toprovide both peer-to-peer interswitch communication as wellas remote SCADA functionality from the ENMAX controlcenter. SCADA information from the switch controllers iscollected by UtiliNet head-end radios located at the originat-ing substations of the automated feeders. From there, theSCADA information is transferred to the ENMAX broad-band fiber-optic network. At the control center, the data pass-es through a firewall and is concentrated in the S&C ProxyServer. The proxy server makes the data available simultane-

ously to the ENMAX EMS master station, the substationlogic module, and to engineering workstations for remoteconfiguration and monitoring of the IntelliTEAM II systemusing S&C WinMon Graphical User Interface Software.

The Human InterfaceNew operator screens were created for the ENMAX EMSmaster station to provide dispatcher visibility and control of theFA system. Key elements of the operator interface include anoverview showing the dispatchers, at a glance, which areas ofthe FA system are enabled. From here, the dispatcher can drilldown to screens of feeder maps with the automated switchesshown in their physical locations. Clicking on the individualswitch locations brings up a detail page of the switch, whichshows all pertinent information for each individual switch.

All alarms and events generated by the automated switchesare logged and available to the engineering staff. A smallersubset of these is presented to the operators and is limited toonly the essential points required to operate the system.

A Unique ChallengeENMAX had a unique challenge in accommodating electro-mechanical relays at the substation breakers into the automaticoperation, including the load-management aspects of theIntelliTEAM II system. These relays only provided a singlereclose operation in response to a fault on the feeder. This meant

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figure 3. A single-line diagram of Phase I substations and automated feeders.

xx

xx

xxxx

yyyy

xx 111

Sub 28 Sub 53

Sub 24 Sub 39

Sub 11Sub 14

Sub 36

Automated Pad-Mount Switch

Automated Overhead Switch

Substation Breaker

Legend Totals

14 Pad-Mount Switches

32 Overhead Switches

19 Feeders

32

26

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111

111

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111A

111B

IEEE power & energy magazine september/october 2005

that momentary faults would become permanent faults whencombined with the sectionalizing desired on the feeder switches.Further, the substation relays were not able to directly supplyfeeder loading data to the distributed controls, reducing the effec-tiveness of the load-management feature of IntelliTEAM II.

Overcoming this challenge meant that the first line seg-ment outside the substation would need to be restorable likeother feeder segments. A new algorithm was needed. TheENMAX EMS master station sends notice of a breakerlockout to the algorithm, which then interrogates the firstautomated switch on the feeder to determine the fault loca-tion. If the fault is beyond the first automated switch and theswitch is open, the logic module issues a close command tothe breaker and restores the first feeder segment.

The reclosing function of the substation breaker is blockedfor safety reasons when personnel are working on a feeder.Blocking of the reclosing function now also triggers the logicmodule to automatically issue “prohibit restoration” com-mands, which prohibit the closing of automated switches onthat feeder. Prohibit restoration commands are also sent bythe logic module to all automated switches during sys-temwide underfrequency or undervoltage events.

Project StatusPhase I of the project was completed in early 2004, automat-ing a total of 18 25-kV distribution feeders as shown in Figure

3. As of November 2004, there have been a total of 11 outageevents on the automated feeders. During these events, the FAsystem has averted an estimated 862,000 customer outage

figure 4. A single-line diagram of Phase II substations and planned automated feeders.

2120

11

13

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10

7

414 11 17 18

15 13 2

3

51512

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2

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Sub 20

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Ties to 8-30.15

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Ties to 8-23.19

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17

16

11

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16

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33

Sub 38

Sub 37

figure 5. A single-line diagram of the automated system:normal configuration.

CriticalLoad

T2

T4

T1T3

S2

S5

S4T6

T5

S3

S1

SecondAlternateSource

FirstAlternateSource

PrimarySource

LD3

LD2

LD1

C

A

B

september/october 2005 IEEE power & energy magazine 61

minutes and 6,800 customer outages. This represents an over-all reduction in SAIDI of 8.6% and a system average interrup-tion frequency index (SAIFI) reduction of 1.7%. These aresignificant numbers given that only 16% of ENMAX cus-tomers are currently benefiting from the FA system.

Phase II is now underway and includes an additional tenfeeders on the 13.2-kV system. Rather than deploying on a per-substation basis, as was done on the 25-kV system, individualfeeders with the worst reliability records are being targeted tomaximize the SAIDI and SAIFI benefits. A single-line repre-

sentation of the Phase II feeders is shown in Figure 4. In thefifth year of the project, full build-out will be an estimated 200automated switches on 80 distribution feeders.

ENMAX has already generated significant reliabilityimprovements through the implementation of this advancedfeeder automation system, and significant improvement isexpected as the program continues to roll out on the five-year plan.

Reliability and Optimizing Use of Existing AssetsA rural electric cooperative in the southeastern United Stateswas faced with a problem: dealing with the demands forhigher reliability by a large and influential retailer that hadbrought hundreds of jobs to the cooperative’s service area.The cooperative could not risk losing the load or its associat-ed jobs.

Several approaches were studied. System constraints ruledout the installation of stand-alone source-transfer gearbecause the available alternate circuit could not handle thepeak load. Upgrading the existing lines for higher reliabilitywas just too expensive. Instead, the cooperative chose toaddress the challenge with the installation of a system thatcould dramatically improve reliability and also effectivelymanage the loads in the area to prevent overloads during cir-cuit reconfiguration without expensive line upgrades.

Figure 5 shows the implementation of an IntelliTEAM IIsystem to maximize reliability for LD1 and the large retailstore and also to optimize the use of existing distribution cir-cuit assets. The system utilizes UtiliNet spread-spectrumradios to communicate within and between the teams.

Here’s a roadmap of the system:✔ Substation B serves Distribution Circuit B (Ckt B).✔ Substation C serves Distribution Circuit C (Ckt C).✔ Substation A serves Distribution Circuit A (Ckt A).✔ Teams are designated T1, T2, T3, T4, T5, and T6.✔ Automated switches are designated S1, S2, S3, S4, and

S5.✔ Circuit loads are designated LD1, LD2, and LD3.

BackgroundSubstation B, the primary source, is capable of supporting themaximum combined area load of 2.5 MVA. Before the addi-tion of the feeder automation system, the area loads were fedby Ckt B. Ckt A and Ckt C were running adjacent to the serv-ice area but not interconnected. Each of those circuits cansupport an additional 2 MVA of load but Ckt A is less reliablethan Ckt C.

The five switches were divided into three teams, eachdefined as a line section bounded by automated switches.Each team is responsible for restoring its load as well as iso-lating faults within its section.

Switch S3 was installed to isolate the primary sourcefrom the subject service area. Its principal responsibility is tosectionalize the area upon loss of the primary source. A sec-ond switch, S2 (shared between Teams T1 and T2), was

62 IEEE power & energy magazine september/october 2005

figure 6. A peak load example: ready for reconfiguration.

CriticalLoad

T2

T4

T1T3

S2

S5

S4T6

T5

S3

S1

1.5 MVA

0.25 MVA

0.75 MVASecondAlternateSource

FirstAlternateSource

PrimarySource

LD3

LD2

LD1

C

A

B

figure 7. The initial configuration of the system: peak loadexample.

CriticalLoad

T2

T4

T1T3

S2

S5

S4T6

T5

S3

S1

1.5 MVA

0.25 MVA

0.75 MVASecondAlternateSource

FirstAlternateSource

PrimarySource

LD3

LD2

LD1

C

A

B

september/october 2005 IEEE power & energy magazine

installed to isolate LD1 from the rest of the area loads, LD1and LD2. Switches S1 and S4 were added to tie their respec-tive alternate sources, Feeders A and C, to the service area.

Since Ckt A is less reliable than Ckt C, it was decided torely on Ckt C as the preferred alternate source for bothloads (unless the combined loads exceed the 2-MVA limit).If the loads are greater than 2 MVA before the loss ofSource B, they would be split and served separately: Ckt Aserving LD1 and Ckt C serving LD2 and LD3.

This was accomplished by configuring limits of 2 MVAon S1 and S4, forcing S2 to petition for supply from S1and/or S4 before determining whether it should close. Theamount of supply for which it petitions is based on the real-time, measured load at S2 at the time Substation B is lost.

To ensure Team T1 always seeks its supply from Ckt Cwhen the combined area load is below 2 MVA, the Team T1logic setting for S2 assigns this switch as the “prioritysource” for the load it serves, LD1.

Circuit Outage at Peak LoadA fault upstream of S3 has caused the loss of Substation Bwhen the area is operating at peak load. At the time of thefault, the combined load of the area is 2.5 MVA; LD1 is 1.5MVA, LD2 is 0.75 MVA, and LD3 is 0.25 MVA.

After sensing an extended loss of voltage, S3 opens toisolate the area from Substation B, and S2 and S5 open inpreparation for the intelligent load restoration. As shown inFigure 6, the entire load previously served by Substation Bis now de-energized.

Since each team has measured and recorded its pre-eventreal-time loads, the next step is to determine whether the firstalternate source Ckt C can accommodate the combined loadsof Teams T1, T2, and T6.

S4 closes after confirming the stability of Team T5 andS4’s ability to accommodate the 0.25 MVA of prefault load.The load on S4 is now 0.25 MVA.

Team T1 has also been attempting to restore its load, butbecause S2 is configured as the priority source for TeamT1—and Team T1 can’t seek an alternate source until firstnegotiating with Team T2—no action is taken.

Team T2’s coach negotiates with Team T6’s coachthrough S5. Since the total load on S4 will remain below itscontracted limit, S5 closes, restoring service to T2 and LD2.The load at S4 is now 1.0 MVA.

Now that Team T2 has been restored, Team T1’s coachattempts to negotiate to close S2. However, a contract has beenset to require that the prefault load on T1 be qualified not onlyagainst the configured limit for S2 but also against the contractedlimit at S4. When T1’s prefault load of 1.5 MVA is added to themeasured load at S4 of 1.0 MVA, it becomes clear that the 2.0MVA limit would be exceeded and the negotiation stops, prevent-ing S2 from closing. Since S2’s priority has now been satisfied,Team T1 is free to seek other sources.

Team T1’s coach now determines that its prefault load iswithin the configured capacity limit for S1 and that T3 is

energized. S1 is closed to restore service to critical load LD1;all operations occur in less than 60 seconds. See Figure 7 forthe final configuration.

ConclusionDistributed intelligence, as applied to distribution feedercircuits, makes it possible to consider application ofautomation to solve tactical problems, such as the largeretailer that requires better-than-available power reliability.The utility planner can use this new technology to not onlyaddress such tactical problems but to eliminate or reducethe need for costly system upgrades, thus providing opti-mal asset management.

While many consider automation in the distribution arenato be a corporatewide endeavor, it has, more likely than not,already surfaced as a spot solution to some difficult problems.Many companies have made good use of advanced feederautomation to gain a strategic leverage in serving their cus-tomers and meeting increasingly difficult expectations on thepart of the users of electric power.

All that remains is for those of us in the energy deliveryindustry to take advantage of the technological breakthroughsavailable to make our collective lives easier—and the lives ofenergy users brighter.

BiographiesDouglas M. Staszesky graduated from the Georgia Instituteof Technology in 1981. He joined S&C Electric Company in1989 and has held positions in sales, product management,research and development, and power systems services. Hecurrently is director of product management for all automa-tion systems products and is responsible for customer service,application support, and marketing. Before joining S&CElectric Company, Doug was with Public Service Electricand Gas Co. of New Jersey. Doug has experience in line con-struction, distribution engineering, operations, planning, andin the operation and maintenance of SCADA (supervisorycontrol and data acquisition) systems.

Dean Craig is a project specialist engineer at ENMAXPower Corporation. Dean joined ENMAX in 2003 and actsas project manager and technical lead on the ENMAX feederautomation project. Before joining ENMAX, Dean held engi-neering positions at GE Power Systems, U2 Systems, andUMA Engineering. Dean holds a B.Sc. in electrical engineer-ing from the University of Alberta, Canada.

Craig Befus is an application director for S&C Electric,providing application and technical consulting on automationtechnologies to customers in states west of Illinois as well aswestern Canadian provinces. Since joining S&C in 1999,Craig has helped several utilities deploy and manage new dis-tribution automation projects using S&C technology. Beforejoining S&C Electric, Craig held engineering positions atCooper Power Systems and Public Service Company of Colorado. Craig holds B.S.E.E. and M.S.E.E. degrees fromthe University of Colorado.

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