Smart Feeder Switching

8/9/2019 Smart Feeder Switching

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Smart Feeder SwitchingBY JIM WEIKERT , AUTOMATION CONSULTANT, POWER SYSTEM ENGINEERING, INC. JUNE 2013

Current utility automation techniques can greatly reduce restoration time and improvereliability and member satisfaction. This article discusses fundamental design optionsfor implementing a successful Smart Feeder Switching program at your cooperative.

INTRODUCTIONAutomating switches and reclosers on feeders can reduce fault restoration time andenable load balancing schemes. While some utilities have limited redundancy of feeder coverage in an area, some have the benefit of substations located geographically closeto each other, enabling the implementation of feeder switching schemes. Although rural

cooperatives often primarily have radial feeders, which are not as conducive to switchingprograms, they sometimes have additional feeders supplying industrial parks or criticalcustomers, such as large manufacturers or hospitals. These areas, because of the greater density of feeders, enable switching programs more easily.

Most power interruptions are momentary and are caused by vegetation that temporarilyshorts one phase to another. Reclosers, even hydraulic reclosers, handle interruptionand restoration of these types of faults well. The customers serviced by the affectedfeeder experience a blink of one to two seconds, followed by immediate restoration.

However, the faults that cause the most problems in terms of reliability and member

satisfaction are those that aren’t momentarily resolved and require intervention to repair them before power can be restored.

Smart Feeder Switching is often referred to as Fault Detection, Isolation, and Restoration(FDIR) or Fault Location, Isolation and Service Restoration (FLISR). Through this article,we will use FDIR as a general term referring to smart feeder switching programs.

Smart Feeder Switching is often

referred to as FaultDetection, Isolation,

and Restoration (FDIR)

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Within the electricalsystems, substations

tend to be the thieves’target

of choice.

Smart Feeder Switching |

Restoration vs. Direct Transfer TripFirst, it is important to distinguish FDIR, whichis a form of distribution protection and restora-tion, from other types of protection systems

such as, for example, Direct-Transfer Trip (DTT).There is a conceptual difference between anFDIR system and a DTT system. Both systemsinvolve coordination of protection devices atdifferent locations to adapt to outages and fail-ures. However, they have very different objec-tives and requirements and, therefore, shouldnot be confused.

The purpose of an FDIR system is to restorepower to undamaged sections of a feeder whenanother section of feeder has an outage due tolightning or some other fault. FDIR systems at-tempt to restore power to the undamagedfeeder sections in less than 5 minutes in order to classify the outage as “momentary” and ex-clude it from being counted toward a perma-nent outage in System Average InterruptionDuration Index (SAIDI) calculations. While lessthan 5 minute restoration distinguishes theoutage as momentary for SAIDI calculations,implementations aim to minimize the outagetime and often perform restoration within 15seconds to 2 minutes.

The purpose of a DTT system is to coordinate 2relays such that if one relay fails to trip when itshould, the second relay can be tripped imme-diately before damage occurs. Often these tworelays are at different locations, possibly onebeing at a distribution substation and the other as part of a transmission system. The DTT scheme is a point-to-point coordination thatoperates very quickly, typically within several60 Hz cycles (<10 ms). This article discussestechnologies and mechanisms for FDIR whichwould not be applicable to DTT.

Outage DetectionThe traditional method of distribution outagemanagement has been to rely on a trouble-call

system in which the customer calls to report anoutage (interactive voice response (IVR) sys-tems are often used). After receiving the outagereport, the distribution utility dispatches field

crews to drive to the location of the fault. Thecrew then investigates the source and manuallyperforms a switching operation to isolate thefault while it is repaired. The manual switchingcan also restore service to customers on unaf-fected sections of the feeder while the crewrepairs the faulted section. Unfortunately, thismethod of fault isolation can take hours.

Having a smart feeder switching scheme inplace, by contrast, can restore power auto -

matically and more quickly while the faultedsection of feeder is being repaired. But,restoration is only as effective as the meansof outage detection and location.

While an outage management system (OMS)can estimate the likely source of an outagebased on calls from customers, supplementingthe OMS with information coming in from fielddevices can help a utility better home in on theoutage location. Switching schemes can obtain

this beneficial information directly from intelli-gent electronic devices (IEDs) such as relays,recloser controllers, and switch controllers.These IEDs are often already in place andactively monitoring the system in order toperform their protection function. But, theyalso have a shortcoming: because they are onlylocated in a few key sites along the feeders,IEDs have limited visibility of the whole system.

Advanced metering infrastructure (AMI) meters

located on customer premises can assist withdetermining the extent of an outage by sendinga “last gasp” of data to the utility’s control center when power is lost. Utilities can also attempt tocommunicate with (or “ping”) meters to deter-mine the extent of an outage or to confirm thatpower has been restored. However, it should

The purpose of anFDIR system is torestore power to

undamaged sectionsof a feeder when

another section of feeder has an outage

due to lightning or some other fault.

The purpose of a DTT ystem is to coordinate

2 relays such that ifone relay fails to tripwhen it should, thesecond relay can betripped immediately

before damage occurs.

Restoration isonly as effectiveas the means of

outage detectionand location .





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be noted that using AMI for outage detectionshould be done with care. If all meters attemptto report outages simultaneously, or if manymeters are pinged to investigate an outage, the

AMI system can easily be overloaded. It is muchmore effective to rely on select meters in strate-gic locations, referred to as “bellwether” meters,in order to obtain information quickly and with-out straining the system.

In addition, utilities can deploy faulted circuitindicators (FCIs) whose sole purpose is toreport faults to the control center. FCIs aremost effective when a utility does not havesmart meters in place. Using IEDs, AMI, and

FCIs together, a utility can get a better pictureof the cause of the outage more rapidly thanby waiting for customer calls.

Restoration ExampleGiven good information aboutoutages, the utility can imple-ment a fault detection, isolationand restoration (FDIR) programas illustrated in the diagramsshown in Figure 1. The initialoutage diagram shows an out-age in which all customers onfeeders one and two have lostpower due to a lightning strike.The second diagram illustratespower restored to partial sec-tions of the feeder while thedamaged section is repaired.

If we assume that each sectionof a feeder represents 250households, 750 customerswould be without power initially.If it takes four hours for the linesection to be repaired, thatcould result in up to 180,000customer minutes of outage.

However, if automation is used to restore 2 of the 3 sections as quickly as 15 minutes fromthe time of the lightning strike, the outage timeis reduced to only 67,500 customer minutes.

This represents a 63 percent reduction.

ARCHITECTURAL CONCEPTSThere are two architectural concepts to under-stand when designing an FDIR system. The firstis the topology of the feeder and loads on thefeeder that are to be protected. The secondis the method by which the switches will bemanaged in making their decision to performrestoration.

Feeder and Load TopologyThere are essential differences i n how an FDIRsystem is implemented depending on the load

Two architecturalconcepts to

understand are thetopology of the

feeder and loads tobe protected, and

the method for managing switches

that decide aboutrestoration.

FIGURE 1: Fault Detection, Isolation and Restoration (FDIR) Program

Feeder 1

Feeder 2

Initial Outage

Feeder 1

Feeder 2

Restoration

Source: Power System Engineering, Inc. 2012





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and feeders a utility is trying torestore and protect. The scopeof a switching scheme dependsprimarily on the amount of

redundancy provided by feedersin a utility’s service area and theamount of territory that the util-ity wishes to cover. The diagramsbelow illustrate several differenttopologies.

Some utilities have a single criti-cal customer or feeder sectionthey are loo king to protect. Thissingle load topology is fairly

straight forward and can be pro-tected by an automatic transfer scheme at a tie point betweentwo feeders. (Figure 2)

Alinear topology focuses onrestoring power to larger sec-tions of the distribution system.The topology is simply an expan-sion of the single load topologyin which there are two substa-tion sources for a feeder and thelength of the feed er is divided bya series of automated switchesand reclosers. (Figure 3)

The linear topology can be fur-ther expanded on if there aremore possible source substa-tions and multiple feeders tocover. This can be referred to as a meshtopology . (Figure 4)

While there is some complexity in implement-ing restoration for a single load topology, thispaper focuses on linear and mesh topologies.

Switch Management MethodsModern switches and reclosers are capableof being controlled through several differentmethods. Although there are differencesamong products from vendor to vendor, switchesand reclosers are generally operated in one of

FIGURE 2: Single Load Topology Source: Power System Engineering, Inc. 2012

A critical load (either a single customer or area) is serviced by two feeders.

FIGURE 3: Linear/Loop Topology Source: Power System Engineering, Inc. 2012

A single feeder is connected to two substationsand service is segmented along the feeder.

FIGURE 4: Mesh Topology Source: Power System Engineering, Inc. 2012

A series of feeders and substations provide redundantservice to an area. Switches and reclosers communicate todetermine where a permanent fault exists, where power isavailable, and how best to restore it.





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the modes listed below. Some devices have theflexibility to operate in any of these modes.

• Independent Operation: Each device makesdecisions on its own regarding whether toopen or close.

• Distributed Management: Devices commu-nicate amongst themselves to determine theproper configuration and how best to per-form restoration and load balancing.

• Centralized Management: A super visorycontrol and data acquisition (SCADA) orDistribution Management System (DMS)system coordinates operation of switches.This process can be fully automated orcontrolled by operator actions.

Independent operation is most applicable torestoration for a single load topology.

FDIR systems that are used to restore power tolinear and mesh topologies rely on distributedor centralized management. Each method has itsadvantages, and the distinction between the twois fundamental to the final system performance.

A distributed system has the advantage of nosingle point of failure. Switches and recloserscommunicate amongst themselves in order todetermine locations of viable sources, currentdemand, and preferred methods of restoration.The level of coordination between the individualswitches impacts how restoration is performed.Some methods of distributed managementsupport the ability for the switches to gainsystem-wide knowledge, so that every switchdevelops a picture of all available sources andwhole system demand. This allows the switchesto act as a whole, even through there is no

single system that is coordinating them.

In less complex methods of distributed manage -ment, each switch has only local informationand communicates with neighboring switches

in an attempt to make the best restorationdecision in a smaller section of the feeder.Without full system visibility, an outage canresult in each switch in the system opening in

order to perform isolation, followed by individ-ual switches making decisions to restore their own sections based on availability of load.

The second method of distributed manage-ment has lower requirements on the communi-cation infrastructure, because of the reducedcoordination between each of the switches inthe system. However, lengths of outages canbe longer, while individual switches are work-ing to determine how best to restore power.

A centralized system has a server that commu-nicates with each of the field devices and coor-dinates the restoration decision-making itself.The fact that all the system knowledge is con-tained in a single location allows restorationdecisions to be made based on a completepicture of system status. Obviously, this centralserver becomes critical to system operation, andutilities should consider whether it is importantto have a redundant server to account for hard-ware failure or disaster recovery situations.

Both distributed and centralized systems areable to interface with a DMS SCADA, so that op-erators have visibility to the distribution feedersand the ability to override the automation.

It is critical to understand that regardless of themethod used, the speed of restoration is greatlyaffected by communication between the devicesin the field. Fiber communications and protocolssuch as DNP 3.0 Ethernet or IEC-61850 with

GOOSE messaging allow for very rapid commu-nications and restoration. On the other end of the spectrum, Modbus or DNP 3.0 Serial vialicensed 220 MHz wireless communications isnot nearly as fast. Communicating with remote

...regardless of themethod used, the

speed of restorationis greatly affected by

communicationbetween the devices

in the field.





of choice.


devices often requires use of wireless technolo-gies that provide long range and coverage over a large territory at the expense of high band-width. It’s important to design the system and

set expectations for restoration time with aclear understanding of the capability of thecommunication infrastructure.

Selection of the switch management method andhow it works in conjunction with the communi-cation system should be given careful consider-ation during the design and Request for Proposal (RFP) process.

RESTORATION LOGICWhen a fault occurs, several methods can beused to locate the fault and determine the ap-propriate or optimal topology to restore power.The system can then coordinate restorationbased on real-time decisions and recent loadhistory. The logic that decides how systemr estoration is to be performed is key to thesuccess of an FDIR system. This sectionprovides an example of logic used by acentrally managed system.

Care must be taken when attempting to locate

the source of a fault, because it is easy toincorrectly identify its location. Fault “targets”are flags within a relayor recloser that indicatethat it has identified afault. Sometimes, thedevice that reacted tothe fault by trippingmay not be the devicethat is actually closestto the fault. Most often,

this would be the resultof improper coordina-tion of settings in therelays and reclosers onthe feeder. Regardless,when determining thesource of the fault and

an appropriate resolution, it is important not torely only on the fault targets, but to also queryeach device individually to determine whether it identified the fault current, even if that device

has not tripped.

An example can be helpful in understandingthis. In the “initial fault” diagram shown inFigure 5, the Feeder 1 substation relay trippeddue to a fault between devices 4 and 5. Thefault targe ts in the substation relay would betripped, but these are obviously not the devicesthat are closest to the fault. Logic within thecentralized system would examine device 5and look for targets set for instantaneous over-

current. Even though the time-overcurrent tar-get may not be set, the instantaneous target isa good indication of the fault.

This is an example of mis-coordination in thesettings within the protection devices andillustrates that the restoration logic shouldnot assume that the fault targets indicate whichdevice should be selected for isolation.

A centralized FDIR management system cancontinue to monitor and adapt loading evenafter the initial restoration, continuing to look

FIGURE 5: Initial FaultSource: Power System Engineering, Inc. 2012

Storm during a weekend evening causes an outage.

Feeder 1Capacity:

400A

Feeder 2Capacity:

400A

75 Amps

5 4

3

1 2

75 Amps 75 Amps

50 Amps

50 Amps

previous view





of choice.


at load and determine bestconfiguration. These nexttwo diagrams illustrate aninitial restoration followed

logic that adapts the solu-tion in time.

When the initial fault occurs,as shown in Figure 5, theloading was light. Feeder 2was able to pick up all of the non-faulted sectionsand restore power, asshown in the Figure 6. Fig-ure 7 illustrates that, as the

fault persisted, the loadincreased due to industrialactivity and an increase inresidential demand. Rather than losing the entire cir-cuit, recloser 3 was openedto keep the load within ac-ceptable limits.

In addition to logic-baseddecision making, central-ized FDIR automation soft-ware can also take intoconsideration the distribu-tion system’s electricalmodel. The electrical modeladds information on the ca-pacity and impedance of each element in the distri-bution feeders. In doing so, the smart feeder switching software can work in conjunctionwith Volt/VAr optimization software modules to

model the voltage profile and adjust regulator and capacitor bank settings appropriately.

Centralized systems can also handle situationsin which multiple sources can be used to pickup portions of the load during an outage. In

these instances, a preferred topology can beadded to the logic to drive which sour ce isused during restorati on. Figure 8shows an

example of multiple sources being used topick up the remaining load when one source isnot sufficient. Here, feeder 3 picks up the 75Amp load that could not be covered by feeder2 previously.

FIGURE 6: Initial SolutionSource: Power System Engineering, Inc. 2012

On the weekend evening feeder 2 is able to supportfull restoration to all but the faulted area.

Feeder 1Capacity:400A

Feeder 2Capacity:

400A

75 Amps

5 4

3

1 2

75 Amps 75 Amps

50 Amps

50 Amps

FIGURE 7: Revised SolutionSource: Power System Engineering, Inc. 2012

By mid-day Monday, the load has increased significantly withthe factory and additional residential loads, and the solutionmust be revised to stay within capacity.

Feeder 1Capacity:

400A

Feeder 2Capacity:

400A

100 Amps

5 4

3

1 2

100 Amps 100 Amps

75 Amps

125 Amps





of choice.


UPDATING PROTECTION COORDINATIONWhen implementing a switching program, it isimportant to understand how to properly coor-dinate your system protection devices duringthe restoration. As feeders are made to pick upadditional load, it must be done in a manner that accounts for and adjusts protection set-tings in substation and feeder devices.

Modification of protection settings can includeincreasing allowable current levels by selectingan alternate time-current curve (TCC). Thiswould be necessary for the initial solution dis-cussed above in reclosers 1 and 2, if recloser 3were closed. Additionally, current flow maychange direction through a recloser, if it isbeing fed from a different substation.

Beyond current settings, reclosers can often beprogrammed to act simply as switches or sec-tionalizers. If programmed to act as a switch,the recloser would no longer attempt to tripand reclose on its own when its fault targetswere triggered. The fault targets would still be

reported to SCADA, but the systemwould make independent deci-sions regarding whether to openor close the device. Similarly, if the

device is acting as a sectionalizer,it will not interrupt fault current,but simply open when it detectsthat an upstream device hastripped.

In general, proper coordination of protection settings is necessaryfor success when changing howloads are supplied.

BENEFITSSome have investigated theeconomic cost-benefit model for switching. When doing so, theyoften look at the cost of outagesto customers, including loss of

business to manufacturing and commercialcompanies. Some of the data discussed herei nis derived from a 2004 study from BerkeleyNational Laboratory. This study found that thetype of customer and frequency o f outage had

the biggest impact on cost, as sh own in Figure 9.

• Type: The majority of outage costs are borneby the commercial and industrial sectors.

• Frequency: Costs tend to be driven bythe frequency rather than the duration ofreliability events.

Many utilities have tried to estimate the cost of interruptions by customer and industry type.This report found that many variables and un-certainties make estimates highly inconsistent.For example, the total cost of power interrup-tions in the US could be as low as $23 billion,if it is assumed that utilities provide fewer andshorter interruptions to commercial and indus-trial customers by focusing more heavily on re-liability for these customers. Conversely, thecost could be estimated as high as $119 billion,

FIGURE 8: Multiple Sources Used to Pick Up Portions of LoadDuring Outage

Source: Power System Engineering, Inc. 2012

Feeder 1Capacity:

400A

Feeder 2Capacity:

400A

Feeder 3Capacity: 200A

100 Amps

100 Amps

5 4

3

6

1 2

100 Amps 100 Amps

75 Amps

125 Amps

previous view

http://emp.lbl.gov/sites/all/files/REPORT%20lbnl%20-%2055718.pdf









if it is assumed that most outages occur insummer afternoon hours when the cost of power is highest.

In general, the report did offer some nationwideestimates of reliability across all customer types, as shown in Table 1.

For cost of outages, the report provided theestimates in Table 2. Although the outage per customer is estimated to be very low for

residential customers, the larger number of customers balances the overall impact. Thesenumbers do not reflect loss of revenue to theutility, rather only the cost to the customer for the outage.

As described so far, the primary benefit of smart feeder switching is reliability. Imple-menting a smart switching program canreduce outage times to well below the 106minute per year SAIDI average.

An additional benefit ofintelligent switches andreclosers is the ability toretrieve feeder performanceinformation automaticallyand easily. Typically, the de-vices can provide voltage andcurrent for each phase, aswell as event recording andharmonic measurements.This information can be verybeneficial in load analysisand engineering.

Cost by Customer Type2% Residential $ 2 Billion

72% Commercial $ 57 Billion26% Industrial $ 20 Billion

Cost by Duration67% Momentary Interruptions $ 52 Billion33% Sustained Interruptions $ 26 Billion

SAIDI SAIFI MAIFI

Mean Reliability 106 min/yr. 1.2 occurrences/yr. 4.3 occurrences/yr.

TABLE 1: Estimates of Reliability Across all Customer Types

Number of Momentary 1 Hour SustainedCustomers Outage Outage Outage

Residential 114.3 million $ 2.18 $ 2.70 $ 2.99

Commercial 14.9 million $ 605 $ 886 $ 1,067

Industrial 1.6 million $ 1,893 $ 3,253 $ 4,227

TABLE 2: Estimated Cost of Outages

U.S. Total: $79 Billion

FIGURE 9: Cost of Outages to Customers

previous view

...the primarybenefit of smart

feeder switching isreliability

http://goback/

http://goback/





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IMPLEMENTING A SMART FEEDERSWITCHING PROGRAMWhen implementing a Smart Feeder Switching(or FDIR) program, it is important to touch upon

each of the areas described below.Operational GoalsThe desired outcome covers both the targetedreliability improvement and the territories inwhich that improvement is targeted to occur, aswell as how you would like the new system toperform operationally.

Operationally, it is important to determine thelevel of automation you are comfortable withand how this ties into your current proceduresfor outages and restoration. Frequently, utilitiesopt for a staged approach to implementingrestoration automation, in which the operator or dispatcher is initially heavily involved butover time, the system is allowed to implementmore decisions automatically once everyoneunderstands the logic and the impact it has onthe system.

Performance GoalsObviously it is important to understand which

feeders are impacting your reliability metricsthe most, what types of outages are beingseen, and whether an FDIR program wouldlikely yield improvements. If customers aremost frustrated by blinks or other momentaryoutages, for example, an FDIR program wouldnot improve customer satisfaction.

It is likely that a couple of areas within your sys-tem are most heavily responsible for outagesor would most benefit from an FDIR system.

Perhaps there is an area in which power deliv-ery is less reliable. Or, perhaps feeders in onearea are more frequently out due to downedtrees or other issues. Recognizing this will allowyou to invest in the areas with the most ben efit.

It is often beneficial to deploy a limited systemas a pilot in a particular area, as this will allowyou to learn and adapt more easily during thedeployment.

SCADAA SCADA system allows your operators to moni-tor and control your automation system. Beforedeploying a distribution feeder automation pro-gram such as FDIR, it is important that you havea solid SCADA system with connectivity to sub-station reclosers, regulators, and transformer monitors.

Not only does the SCADA system act as thefoundation for the FDIR system, it also allowsyou to monitor the substations closely duringrestoration. This allows you to monitor trans-former loading and verify there are no issues asload is rebalanced throughout your system.

Commonly, the SCADA interface then remainsthe primary interface through which theoperators monitor and control FDIR behavior.Regardless of whether you implement acentrally controlled or distributed FDIR system,it is helpful for operators to primarily interfacethose systems through the SCADA screenswhich provide visibility to the whole system.

Communication SystemBefore deploying an FDIR system, it is importantto evaluate your current communication systemto substations and Distribution Auto mation (DA)devices. The communication system perform-ance sets the operational performance of theFDIR system. While it is likely that the additionof the FDIR system will introduce additional re-

quirements, such as reaching distant switchesand reclosers, understanding your current com-munications system well and having a strong in-frastructure will allow you to build more easilyas you de ploy the FDIR system.

Before deploying anFDIR system, it is

important toevaluate your current

communicationsystem to

substations andDA devices.

Not only does theSCADA system act

as the foundation for the FDIR system, italso allows you to

monitor thesubstations closelyduring restoration.





of choice.


RFP and Vendor Solution EvaluationIssue an RFP that clearly outlines the itemsdiscussed above, and evaluate the solutionsoffered by different vendors. It is very helpful to

talk with similar utilities that have implementedthe vendor’s solution. Discuss what they learnedduring deployment and whether they haveseen the anticipated reliability improvements.

Test Pilot and EvaluationIt is recommended to implement an FDIRsolution in a pilot area and evaluate theperformance to determine whether you aregetting the operation you had hoped beforemoving forward to a larger deployment.

SUMMARY

Smart feeder switching provides the potentialfor significantly reduced SAIDI and improvedcustomer satisfaction. Today’s technology

provides the necessary tools for utilities toimplement these systems. However, carefulplanning and understanding of the technology’scapabilities are necessary for the FDIR systemto ultimately provide improved performance.By selecting the appropriate technology andimplementing it well, utilities can achieve theimprovements discussed within this report.

TESTING SMART FEEDER SWITCHING IN THE SMART GRID DEMO

CRN is testing deployment of smart feeder switching technologies in the field and using softwaresimulations at nine of the 23 member cooperatives who are participating in CRN’s Smart GridDemonstration Project. The co-ops are gathering data and information on the impact of thistechnology on reliability, efficiency and cost-control.

Three approaches to smart feeder switching techniques are being studied. Listed in ascending

order of deployment cost, they are: 1) switch automation, 2) recloser automation (with additionaltelemetry), and 3) pulse closing (with telemetry and automatic limits on the energy used to resolvefaults). Benefits of smart feeder switching programs that will be quantified as part of the studiesinclude: improved reliability of the power supply, easier implementation of post-fault servicerestoration schemes, extended asset life, reduced technical losses through improved loadbalancing, peak demand reduction, and increased situational awareness.

Funded through a $33.9 million matching grant to CRN from the U.S. Department of Energy (DOE)in 2010, the Smart Grid Demonstration Project is designed to study the benefits of an array ofnew technologies for more than 700,000 consumers in 12 states. As part of the program, CRNis examining the risks and benefits of technology upgrades for electric cooperatives and their

members, and developing a modeling program that will enable co-ops to evaluate the systemimpact and costs/benefits of a variety of technologies prior to purchase. At the same time, CRNis developing specific solutions that will help make these new applications viable. Final resultsof the Smart Grid Demonstration are anticipated in early 2014.

More information on the Smart Grid Demo may be found at:http://www.nreca.coop/programs/CRN/SmarterGrid/smartgriddemo/Pages/default.aspx



Legal NoticeThis work contains findings that are general in nature. Readers are reminded to perform due diligence in applying these findings totheir specific needs, as it is not possible for NRECA to have sufficient understanding of any specific situation to ensure applicabilityof the findings in all cases. Neither the authors nor NRECA assume liability for how readers may use, interpret, or apply theinformation, analysis, templates, and guidance herein or with respect to the use of, or damages resulting from the use of, anyinformation, apparatus, method, or process contained herein. In addition, the authors and NRECA make no warranty or representation that the use of these contents does not infringe on privately held rights. This work product constitutes theintellectual property of NRECA and its suppliers, as the case may be, and contains Confidential Information. As such, this workproduct must be handled in accordance with the CRN Policy Statement on Confidential Information. Copyright © 2013 by theNational Rural Electric Cooperative Association.


About the Author

Jim Weikert has a Bachelor of Science Degree in Electrical Engineering from Milwaukee

School of Engineering, Milwaukee, WI and Master’s Degree in Business from EdgewoodCollege, Madison, WI. He leads the SCADA, Substation Modernization and DA focus areasfor PSE. Jim assists with design and deployment of FDIR and Volt/VAR systems includingprograming of IEDs, RTUs and data concentrators. He leads procurement, design anddeployment of SCADA systems. He assists with design to address security based on NERCCIP requirements. In addition, he has a strong background in communications systemsfor monitoring and control based on spread-spectrum, licensed, cellular, and Wi-Fitechnologies.

Questions or Comments

Brian Sloboda, CRN Senior Program Manager, [email protected]

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