22 IEEE power & energy magazine march/april 2003

EELECTRIC UTILITY DEREGULA-TION, economic pressures forcingdownsizing, and the marketplace pres-sures of potential takeovers have forcedutilities to examine their operational andorganizational practices. Utilities arerealizing that they must shift their focusto customer service. Customer servicerequirements all point to one key ele-ment: information, i.e., the right amountof information to the right person orcomputer within the right amount oftime. The flow of information requiresdata communication over extended net-works of systems and users. In fact, util-ities are becoming among the largestusers of data and are the largest users ofreal-time information.

The advent of industry deregulationhas placed greater emphasis on theavailability of information, the analysisof this information, and the subsequentdecision-making to optimize systemoperation in a competitive environ-ment. Intelligent electronic devices(IEDs) being implemented in substa-tions today contain valuable infor-mation, both operational andnonoperational, needed by many usergroups within the utility. The challengefacing utilities is determining a stan-dard integration architecture that meetsthe utility’s specific needs, can extractthe desired operational and nonopera-tional information, and deliver thisinformation to the users who haveapplications to analyze the information.

This issue of IEEE Power & EnergyMagazine focuses on substation inte-gration and automation. My Guest Edi-

torial provides an overview of substa-tion integration and automation funda-mentals and focuses on best practices. Italso includes a list of:

✔ further reading material for thosewho require more information onthe same subject

✔ acronyms and abbreviations forthose readers who are not famil-iar with the terminology.

Three feature articles follow withmore specific information on:

✔ a business case methodologyfor expanding the implementa-

John D. McDonald

gues

t edi

toria

l

substation automationIED integration and availability of information

1540-7977/03/$17.00©2003 IEEE

©D

IGIT

AL

VIS

ION

Utilities must determine a standard integration architecture that meets theirsecific needs in extracting desired opertaional and nonoperational data anddelivering it to the users.

march/april 2003 IEEE power & energy magazine

tion of substation automationtechnologies at MidAmericanEnergy Company

✔ a pilot project at Omaha PublicPower District to integrate datafrom various devices within twosubstations and a simulator

✔ a generic architecture thatapplies the multiagent systemsmethodology to the field of sub-station automation.

Open SystemsAn open system is a computer systemthat embodies supplier-independent stan-dards so that software may be applied onmany different platforms and can interop-erate with other applications on local andremote systems. An open system is anevolutionary means for a substation con-trol system that is based on the use ofnonproprietary, standard software andhardware interfaces. Open systemsenable future upgrades available frommultiple suppliers at lower cost to be inte-grated with relative ease and low risk.

The concept of open systems appliesto substation automation. It is importantto learn about the different de jure (legal)and de facto (actual) standards and thenapply them so as to eliminate proprietaryapproaches. An open systems approachallows the incremental upgrade of theautomation system without the need forcomplete replacement, as happened inthe past with proprietary systems. Thereis no longer the need to rely on one sup-plier for complete implementation. Sys-tems and IEDs from competing suppliersare able to interchange and share infor-mation. The benefits of open systemsinclude longer expected system life,investment protection, upgradeabilityand expandability, and readily availablethird-party components.

Levels of Integration and AutomationSubstation integration and automationcan be broken down into five levels, asshown in Figure 1. The lowest level isthe power system equipment, such astransformers and circuit breakers. Themiddle three levels are IED implemen-tation, IED integration, and substation

automation applications. All electricutilities are implementing IEDs in theirsubstations. The focus today is on theintegration of the IEDs. Once this isdone, the focus will shift to whatautomation applications should run atthe substation level. The highest level isthe utility enterprise, and there are mul-tiple functional data paths from the sub-station to the utility enterprise.

Since substation integration andautomation technology is fairly new,there are no industry standard defini-tions, except for the definition of anIED. The industry standard definition ofan IED is given below, as well as defi-nitions for substation integration andsubstation automation.

✔ IED: Any device incorporatingone or more processors with thecapability to receive or senddata/control from or to an exter-nal source (e.g., electronic multi-function meters, digital relays,controllers). An example of arelay IED is shown in Figure 2.

✔ Substation integration: Integra-tion of protection, control, anddata acquisition functions into aminimal number of platforms toreduce capital and operatingcosts, reduce panel and controlroom space, and eliminate redun-dant equipment and databases.

✔ Substation automation: Deploy-ment of substation and feederoperating functions and applica-tions ranging from supervisorycontrol and data acquisition(SCADA) and alarm processingto integrated volt/var control inorder to optimize the manage-ment of capital assets andenhance operation and mainte-nance (O&M) efficiencies withminimal human intervention.

Architecture Functional Data PathsThere are three primary functional datapaths from the substation to the utilityenterprise, as shown in Figure 3. Themost common data path is conveyingthe operational data (e.g., volts, amps)to the utility’s SCADA system every 2to 4 s. This information is critical forthe utility’s dispatchers to monitor andcontrol the power system. The mostchallenging data path is conveying thenonoperational data to the utility’s datawarehouse. The challenges associatedwith this data path include the charac-teristics of the data (waveforms ratherthan points), the periodicity of datatransfer (not continuous, on demand),and the protocols used to obtain thedata from the IEDs (not standard, IEDsupplier’s proprietary protocols).Another challenge is whether the data

23

figure 2. Example of a relay IED.

figure 1. Five levels of substation integration and automation.

is pushed from the substation into thedata warehouse, pulled from the datawarehouse, or both. The third data pathis remote access to an IED by passingthrough or looping through the substa-tion integration architecture and isolat-ing a particular IED in the substation.

Data WarehouseThe corporate data warehouse enablesusers to access substation data whilemaintaining a firewall to substation con-trol and operation functions. Both oper-ational and nonoperational data isneeded in the data warehouse. To sizethe data warehouse, the utility mustdetermine who the users of the substa-tion automation system data are, thenature of their application, the type ofdata needed, how often the data is need-ed, and the frequency of update requiredfor each user. Examples of user groupswithin a utility are substation designengineering, protective relay engineer-ing, protective relay technicians, substa-tion metering, substation operations,

control center operations, engineeringplanning, transmission and distributionengineering, power quality, substationtest, substation maintenance, predictivemaintenance, communications engi-neering, SCADA, feeder automation,and information technology.

SA System FunctionalArchitecture DiagramThe functional architecture diagram inFigure 4 shows the three functional datapaths from the substation to the utilityenterprise, as well as the SCADA sys-tem and the data warehouse. The opera-tional data path to the SCADA systemutilizes the communication protocolpresently supported by the SCADA sys-tem. The nonoperational data path tothe data warehouse conveys the IEDnonoperational data from the SA sys-tem to the data warehouse, either beingpulled by a data warehouse applicationfrom the SA system or being pushedfrom the SA system to the data ware-house based on an event trigger or time.The remote access path to the substa-tion utilizes a dial-in telephone connec-tion. The global positioning system(GPS) satellite clock time reference isshown, providing a time reference forthe SA system and IEDs in the substa-tion. The PC provides the graphical userinterface (GUI) and the historical infor-mation system for archiving operationaland nonoperational data. The SCADAinterface knows which SA systempoints are sent to the SCADA system,as well as the SCADA system protocol.The local area network (LAN) enabledIEDs can be directly connected to theSA LAN. The non-LAN enabled IEDsrequire a network interface module

(NIM) for protocol and physical inter-face conversion. The IEDs can havevarious applications, such as equipmentcondition monitoring (ECM) and relay-ing, as well as direct (or hardwired)input/output (I/O).

New Versus ExistingSubstationsThe design of new substations has theadvantage of starting with a blank sheetof paper. The new substation will typi-cally have many IEDs for differentfunctions, and the majority of opera-tional data for the SCADA system willcome from these IEDs. The IEDs willbe integrated with digital two-way com-munications. The small amount ofdirect input/output (hardwired) can beacquired using programmable logiccontrollers (PLCs). Typically, there areno conventional remote terminal units(RTUs) in new substations. The RTUfunctionality is addressed using IEDs,PLCs, and an integration network usingdigital communications.

In existing substations, there are sev-eral alternative approaches, dependingon whether or not the substation has aconventional RTU installed. The utilityhas three choices for their existing con-ventional substation RTUs:

✔ Integrate RTU with IEDs: Manyutilities have integrated IEDs withexisting conventional RTUs, pro-vided the RTUs support commu-nications with downstreamdevices and support IED commu-nication protocols. This integra-tion approach works well for theoperational data path but does notsupport the nonoperational andremote-access data paths. The lat-ter two data paths must be doneoutside of the conventional RTU.

✔ Integrate RTU as another substa-tion IED: If the utility desires tokeep its conventional RTU, thepreferred approach is to integratethe RTU in the substation integra-tion architecture as another IED.In this way, the RTU can be retiredeasily as the RTU hardwired directinput/output transitions to comeprimarily from the IEDs.

IEEE power & energy magazine march/april 2003

Utility Enterprise

Substation Automation Applications

IED Integration

IED Implementation

Power System Equipment (Transformers, Breakers)

Operational Data toSCADA System

Nonoperational Data toData Warehouse

Remote Access to IED

figure 3. Three functional data paths from substation to utility enterprise.

24

A corporate datawarehouse enablesusers to accesssubstation datawhile maintaininga firewall tosubstation controland operationfunctions.

march/april 2003 IEEE power & energy magazine

✔ Retire RTU and use IEDs andPLCs as with a new substation:The RTUs may be old and diffi-cult to support, and the substationautomation project may be a goodtime to retire these older RTUs.The hardwired direct input/outputfrom these RTUs would thencome from the IEDs and PLCs aswith a new substation.

Equipment ConditionMonitoringMany electric utilities have employedECM to maintain electric equipment intop operating condition while minimiz-ing the number of interruptions. WithECM, equipment-operating parametersare automatically tracked to detect theemergence of various abnormal operat-ing conditions. This allows substationoperations personnel to take timelyaction when needed to improve reliabil-ity and extend equipment life. Thisapproach is applied most frequently tosubstation transformers and high volt-age electric supply circuit breakers tominimize the maintenance costs ofthese devices, as well as improve theiravailability and extend their useful life.Figure 5 shows an ECM IED installedon a substation transformer.

Equipment availability and reliabili-ty may be improved by reducing theamount of offline maintenance and test-ing required, as well as reducing thenumber of equipment failures. To betruly effective, equipment conditionmonitoring should be part of an overallcondition-based maintenance strategythat is properly designed and integratedinto the regular maintenance program.

ECM IEDs are being implementedby many utilities. In most implementa-tions, the communication link to theIED is via a dial-up telephone line. Tofacilitate integrating these IEDs intothe substation architecture, the ECMIEDs must support at least one oftoday’s widely used IED protocols:Modbus, Modbus Plus, or DistributedNetwork Protocol version 3 (DNP3). Inaddition, a migration path to utilitycommunications architecture version 2(UCA2) manufacturing message speci-

fication (MMS) protocol is desired. Ifthe ECM IEDs can be integrated intothe substation architecture, the opera-tional data will have a path to theSCADA system, and the nonopera-tional data will have a path to the utili-ty’s data warehouse. In this way, theusers and systems throughout the utili-ty that need this information will haveaccess to it. Once the information isbrought out of thesubstation and intothe SCADA systemand data warehouse,users can share theinformation in theutility. The “private”databases that resultin islands of automa-tion will go away.Therefore, the goal ofevery utility is to inte-grate these ECMIEDs into a standard

substation integration architecture sothat both operational and nonopera-tional information from the IEDs canbe shared by utility users.

Substation Automation Training SimulatorOne of the challenges for electric utili-ties when implementing substationautomation for the first time is to create

25

figure 4. SA system functional architecture diagram.

figure 5. ECM IED installed on substation transformer.

“buy-in” for the new technology withinthe utility. The more people know abouta subject the more comfortable they feeland the better the chance they will usethe technology. It is much easier and lessstressful to learn about substationautomation technology in a trainingenvironment, away from the substation,than on a system installed in an ener-gized substation. For these reasons,many utilities purchase a substationautomation training simulator (SATS),which is an identical configuration tothat installed in substations. The maindifference is that the SATS includes atleast one of every kind of IED installedin all substations. In addition to training,SATS is used for application develop-ment and testing of new IEDs. An exam-ple of a SATS presently installed at anelectric utility is shown in Figure 6.

Protocol FundamentalsA communication protocol allows com-munication between two devices. Thedevices must have the same protocol(and version) implemented. Any proto-

col differenceswill result in com-munication errors.

If the commu-nication devicesand protocols arefrom the samesupplier, i.e.,where a supplierhas developed aunique protocol toutilize all thecapabilities of thetwo devices, it isunlikely thedevices will havetrouble communi-cating. By using aunique protocolof one supplier, autility can maxi-mize the device’sfunctionality andsee a greaterreturn on itsinvestment; how-ever, the uniqueprotocol will con-

strain the utility to one supplier for sup-port and purchase of future devices.

If the communication devices arefrom the same supplier but the protocolis an industry-standard protocol sup-ported by the device supplier, thedevices should not have trouble com-municating. The device supplier hasdesigned its devices to operate with thestandard protocol and communicatewith other devices using the same pro-tocol and version. By using a standardprotocol, the utility may purchaseequipment from any supplier that sup-ports the protocol and, therefore, cancomparison-shop for the best prices.

Industry-standard protocols typical-ly require more overhead than a sup-plier’s unique protocol. Standardprotocols often require a higher speedchannel than a supplier’s unique proto-col for the same efficiency or informa-tion throughput. However, high-speedcommunication channels are moreprevalent today and may provide ade-quate efficiency when using industry-standard protocols. UCA2 MMS is

designed to operate efficiently over 10Mb/s switched or 100 Mb/s shared orswitched Ethernet. If a utility is con-sidering UCA2 MMS as its protocol ofchoice, a prerequisite should be instal-lation of high-speed communications.If the utility’s plan is to continue witha communication infrastructure operat-ing at 1,200 to 9,600 b/s, the betterchoice for an industry-standard proto-col would be DNP3.

A utility may not be able to utilizeall of a device’s functionality using anindustry standard protocol. If a devicewas designed before the industry stan-dard protocol, the protocol may notthoroughly support the device’s func-tionality. If the device was designedafter the industry standard protocol wasdeveloped, the device should have beendesigned to work with the standard pro-tocol such that all of the device’s func-tionality is available.

The substation integration andautomation architecture must allowdevices from different suppliers tocommunicate (interoperate) using anindustry-standard protocol. The utilityhas the flexibility to choose the bestdevices for each application, providedthe suppliers have designed theirdevices to achieve full functionalitywith the protocol. Though devicesfrom different suppliers can operateand communicate under the standardprotocol, each device may have capa-bilities not supported by the otherdevice. There is also a risk that the pro-tocol implementations of the industry-standard protocol by the two suppliersin each device may have differences.Factory testing will verify that thefunctions of one device are supportedby the protocol of the other device andvice versa. If differences and/or incom-patibilities are found, they can be cor-rected during factory testing.

Protocol ConsiderationsThere are two capabilities a utility con-siders for an IED. The primary capabil-ity of an IED is its standalonecapabilities, such as protecting thepower system for a relay IED. The sec-ondary capability of an IED is its inte-

26 IEEE power & energy magazine march/april 2003

figure 6. Substation automation training simulator.

march/april 2003 IEEE power & energy magazine

gration capabilities, such as its physicalinterface (e.g., RS-232, RS-485, Ether-net) and its communication protocol(e.g., DNP3, Modbus, UCA2 MMS).

Today utilities typically specify theIEDs they want to use in the substationrather than giving a supplier a turnkeycontract to provide the supplier’s IEDsonly in the substation. However, utili-ties typically choose the IEDs basedon the IED’s standalone capabilitiesonly, without considering the IED’sintegration capabilities. Once theIEDs are installed, the utility may findin the future, when they want to inte-grate the IEDs, that the IEDs werepurchased with the IED supplier’s pro-prietary protocol and with a physicalinterface not desired (RS-485 pur-chased when Ethernet is desired).When purchasing IEDs, the utilitymust consider both the standalonecapabilities in the choice of the IEDand the integration capabilities whenordering the IED, even if the IEDs willnot be integrated in the near future.

Today, the most common IEDcommunication protocols are Mod-bus, Modbus Plus, and DNP3. TheUCA2 MMS protocol is becomingcommercially available from moreIED suppliers and being implementedin more utility substations. However,the implementations may not be opti-mal (adding a separate box for theUCA2 MMS protocol and Ethernetnetworking) and may result in poorperformance (data latency due to theadditional box) rather than the suppli-er incorporating the new functionalityinto the existing IED. The utility mustbe cautious when ordering an IEDwith other than the IED supplier’s tar-get protocol, often supplier propri-etary, used in the design of the IED.Some IED functionality may be lostwhen choosing other than the IEDsupplier’s target protocol.

The most common IED networkingtechnology today in substations is serialcommunications, either RS-232 or RS-485. As more and more IEDs becomeavailable with Ethernet ports, the IEDnetworking technology in the substationwill be primarily Ethernet.

UtilityCommunicationArchitectureThe use of internationalprotocol standards isnow recognized through-out the electric utilityindustry as a key to suc-cessful integration of thevarious parts of the elec-tric utility enterprise.One area addresses sub-station integration andautomation protocolstandardization efforts.These efforts have takenplace within the frame-work provided by theElectric Power ResearchInstitute’s (EPRI’s) UCA.

UCA is a standards-based approach to utilitydata communicationsthat provides for wide-scale integration from theutility enterprise level (aswell as between utilities)down to the customerinterface, including dis-tribution, transmission,power plant, control cen-ter, and corporate infor-mation systems. UCAversion 1.0 specificationwas issued in December1991 as part of EPRI Pro-ject RP2949, Integrationof Utility Communica-tion Systems. While thisspecification supplied agreat deal of functionali-ty, industry adoption waslimited, due in part to alack of detailed specifica-tions about how the spec-ified protocols wouldactually be used by appli-cations. For example, theMMS (ISO/IEC 9506)protocol was specifiedfor real-time data ex-change at many levelswithin a utility, but spe-cific mappings to MMSfor exchanging power

27

Acronyms and Abbreviations

DNP distributed network protocol

ECM equipment condition monitoring

EPRI Electric Power Research Institute

GOMSFE generic object models for substation and feeder equipment

GPS global positioning system

ICCP inter-control center communications protocol

IEC International Electrotechnical Commission

IED intelligent electronic device

IEEE Institute of Electrical and Electronics Engineers, Inc.

I/O input/output

ISO International Standards Organization

IT information technology

LAN local area network

Mb/s megabits per second

MMS manufacturing messaging specification

NIM network interface module

O&M operations and maintenance

PES IEEE Power Engineering Society

PLC programmable logic controller

PSRC IEEE PES Power Systems Relaying Committee

RF radio frequency

RFP request for proposal

RTU remote terminal unit

SA substation automation

SATS substation automation training simulator

SCADA supervisory control and data acquisition

TC technical committee

TCP/IP transmission control protocol and Internet protocol

UCA utility communication architecture

var volt ampere reactive

WAN wide area network

WG working group

system data and schedules or for commu-nicating directly with substation or distri-bution feeder devices was lacking,resulting in continuing interoperabilityproblems.

The UCA (MMS) Forum was startedin May 1992 to address these UCAapplication issues. Six working groupswere established to consider issues ofMMS application in power plants, con-trol centers, customer interface, substa-tion automation, distribution feederautomation, and profile issues. TheMMS Forum served as a mechanism forutilities and suppliers to build the techni-cal agreements necessary to achieve awide range of interoperability usingUCA MMS. Out of these efforts camethe notion of defining standard powersystem objects and mapping them ontothe services and data types supported byMMS and the other underlying standardprotocols. This heavily influenced thedefinition of the UCA2 specificationissued in late 1996, which endorses tendifferent protocol profiles, includingtransmission control protocol and Inter-net protocol (TCP/IP) and inter-controlcenter communications protocol (ICCP),as well as a new set of common applica-tion service models for real-time deviceaccess.

The EPRI UCA Substation Automa-tion Project began in the early 1990s toproduce industry consensus regardingsubstation integrated control, protec-tion, and data acquisition and to allowinteroperability of substation devicesfrom different manufacturers. The Sub-station Protocol Reference Specifica-tion recommended three of the tenUCA2 profiles for use in substationautomation. Future efforts in this proj-ect were integrated with the efforts inthe Utility Substations Initiative.

In mid-1996, American ElectricPower hosted the first Utility Substa-tions Initiative meeting, as a continua-

tion of the EPRI UCA SubstationAutomation Project. Approximately 40utilities and 25 suppliers are presentlyparticipating, having formed supplier/utility teams to define the supplier IEDfunctionality and to implement a stan-dard IED protocol (UCA2 profile) andLAN protocol (Ethernet).

Generic object models for substationand feeder equipment (GOMSFE) arebeing developed to facilitate suppliersin implementing the UCA SubstationAutomation Project substation andfeeder elements of the power systemobject model. New IED products withthis functionality are now commerciallyavailable. The Utility Substations Initia-tive meets three times each year, in Jan-uary, May, and September, immediatelyfollowing the IEEE PES Power SystemRelaying Committee (PSRC) meetingsand in conjunction with the UCA UsersGroup meetings. Every other meetingincludes a supplier interoperabilitydemonstration. The demonstration inSeptember 2002 involved approximate-ly 20 suppliers with products intercon-nected by a fiber Ethernet LANinteroperating with the UCA2 MMSprotocol, the GOMSFE device objectmodels, and Ethernet networks.

The UCA Users Group is a nonprof-it organization whose members are util-ities, suppliers, and users ofcommunications for utility automation.The mission of the UCA Users Group isto enable utility integration through thedeployment of open standards by pro-viding a forum in which the variousstakeholders in the utility industry canwork cooperatively together as mem-bers of a common organization to:

✔ influence, select, and/or endorseopen and public standards appro-priate to the utility market basedon the needs of the membership

✔ specify, develop, and/or accreditproduct/system-testing programs

that facilitate the field interoper-ability of products and systemsbased upon these standards

✔ implement educational and promo-tional activities that increaseawareness and deployment of thesestandards in the utility industry.

The UCA Users Group was firstformed in 2001 and presently has 34corporate members, including 17 sup-pliers, 14 electric utilities, and threeconsultants and other organizations.The UCA Users Group organizationconsists of a Board of Directors, withthe Executive Committee and Techni-cal Committee reporting to the board.The Executive Committee has threecommittees reporting to it: Marketing,Liaison, and Membership. The Techni-cal Committee has a number of com-mittees reporting to it, includingSubstation, Communications, Prod-ucts, Object Models (IEC61850/GOMSFE), and Test Proce-dures. The Web site for the UCA UsersGroup is www.ucausersgroup.org. Thegroup meets three times each year, inJanuary, May and September, immedi-ately following the IEEE PES PSRCmeetings and in conjunction with theUtility Substations Initiative meetings.In addition, the UCA Users Group willmeet at the IEEE PES SubstationsCommittee Annual Meeting 27-30April 2003 in Sun Valley, Idaho. Thismeeting will include a supplier inter-operability demonstration with 20 to25 suppliers demonstrating the imple-mentation of the UCA2 MMS protocoland Ethernet networking technologyinto their IEDs and products and inter-operating with the other suppliers’equipment.

IEC 61850The UCA2 substation automation workhas been brought to IEC TechnicalCommittee (TC) 57 Working Groups

28 IEEE power & energy magazine march/april 2003

Benefits of open systems include longer expected system life,investment protection, upgradeability and expandability, andreadily available third-party components.

march/april 2003 IEEE power & energy magazine

(WGs) 10, 11, and 12, who are devel-oping IEC 61850, the single worldwidestandard for substation automationcommunications. IEC 61850 is basedon UCA2 and European experience andprovides additional functions such assubstation configuration language and adigital interface to nonconventional cur-rent and potential transformers.

Distributed NetworkProtocolThe development of DNP was a com-prehensive effort to achieve open, stan-dards-based interoperability betweensubstation computers, RTUs, IEDs, andmaster stations (except inter-master-sta-tion communications) for the electricutility industry. DNP is based on thestandards of the IEC TC 57, WG 03.DNP has been designed to be as close tocompliant as possible to the standardsas they existed at the time of develop-ment with the addition of functionalitynot identified in Europe but needed forcurrent and future North Americanapplications (e.g., limited transportlayer functions to support 2K blocktransfers for IEDs, radio frequency(RF), and fiber support). The presentversion of DNP is DNP3, which isdefined in three distinct levels. Level 1has the least functionality, for simpleIEDs, and Level 3 has the most func-tionality, for SCADA master-stationcommunication front-end processors.

The short-term benefits of usingDNP are:

✔ interoperability between multi-supplier devices

✔ fewer protocols to support in thefield

✔ reduced software costs✔ no protocol translators needed✔ shorter delivery schedules✔ less testing, maintenance, and

training✔ improved documentation✔ independent conformance testing✔ support by independent user

group and third-party sources(e.g., test sets, source code).

In the long term, further benefits canbe derived from using DNP, including:

✔ easy system expansion✔ long product life✔ more value-added products from

suppliers✔ faster adoption of new technology✔ major operations savings.

DNP was developed by Harris, Dis-tributed Automation Products, in Cal-gary, Alberta, Canada. In November1993, responsibility for defining furtherDNP specifications and ownership ofthe DNP specifications was turned overto the DNP User Group, a group com-posed of utilities and suppliers who areutilizing the protocol. The DNP UserGroup is a forum of over 300 users andimplementers of the DNP3 protocolworldwide. The major objectives of thegroup are to:

✔ maintain control of the protocoland determine the direction inwhich the protocol will migrate

✔ review and add new features,functions, and enhancements tothe protocol

✔ encourage suppliers and utilitiesto adopt the DNP3 protocol as astandard

✔ define recommended protocolsubsets

✔ develop test procedures and veri-fication programs

✔ support implementer interactionand information exchange.

The DNP User Group has an annualgeneral meeting in North America, usu-ally in conjunction with the Distrib-uTECH Conference in February/March.The Web site for DNP and the DNPUser Group is www.dnp.org. The DNPUser Group Technical Committee is anopen volunteer organization of industryand technical experts from around theworld. This committee evaluates sug-gested modifications or additions to theprotocol and then amends the protocoldescription as directed by the UserGroup members.

Choosing the RightProtocolThere are several factors to considerwhen choosing the right protocol foryour application. First, determine thesystem area with which you are most

concerned, e.g., the protocol from aSCADA master station to the SCADARTUs, a protocol from substation IEDsto an RTU or a PLC, or a LAN in thesubstation. Second, determine the tim-ing of your installation, e.g., sixmonths, 18 to 24 months, or three tofive years. In some application areas,technology is changing so quickly thatthe timing of your installation can havea great impact on your protocol choice.If you are implementing new IEDs inthe substation and need them to be inservice in six months, you could nar-row your protocol choices to DNP3,Modbus, and Modbus Plus. These pro-tocols are used extensively in IEDstoday. If you choose an IED that iscommercially available with UCA2MMS capability today, then you maychoose UCA2 MMS as your protocol.

If your timeframe is one to twoyears, you should consider IC 61850and UCA2 MMS as the protocol.Monitor the results of the Utility Sub-station Communication Initiative utili-ty demonstration sites. These siteshave implemented new supplier IEDproducts that are using UCA2 MMSas the IED communication protocoland Ethernet as the substation localarea network.

If your timeframe is near term (sixto nine months), make protocol choic-es from suppliers who are participatingin the industry initiatives and are incor-porating this technology into theirproduct’s migration paths. This willhelp protect your investment frombecoming obsolete by allowing incre-mental upgrades to new technologies.

Communication Protocol Application AreasThere are various protocol choicesdepending on the protocol applicationarea of your system. Protocol choicesvary with the different applicationareas. Different application areas arein different stages of protocol develop-ment and industry efforts. The statusof development efforts for differentapplications will help determine real-istic plans and schedules for your spe-cific projects.

29

Within the SubstationThe need for a standard IED protocoldates back to the late 1980s. IED suppli-ers acknowledge that their expertise is inthe IED itself, not in two-way communi-cations capability, the communicationsprotocol, or added IED functionalityfrom a remote user. Though the industrymade some effort to add communicationscapability to the IEDs, each IED supplierwas concerned that any increased func-tionality would compromise performanceand drive the IED cost so high that noutility would buy it. Therefore, the indus-try vowed to keep costs competitive andperformance high as standardization wasincorporated into the IED.

The IED supplier’s lack of experi-ence in two-way communications andcommunication protocols resulted incrude, primitive protocols and, in somecases, no individual addressability andimproper error checking (no select-before-operate). Each IED required itsown communication channel, but onlylimited channels, if any, were availablefrom RTUs. SCADA system and RTUsuppliers were pressured to develop thecapability to communicate to IEDs pur-chased by the utilities. Each RTU andIED interface required not only a newprotocol but a proprietary protocol notused by any other IED.

It was at this point that the DataAcquisition, Processing and Control Sys-tems Subcommittee of the IEEE PowerEngineering Society (PES) SubstationsCommittee recognized the need for astandard IED protocol. The subcommit-tee formed a task force to examine exist-ing protocols and determine, based ontwo sets of screening criteria, the two bestcandidates. Trial Use RecommendedPractice for Data CommunicationsBetween Intelligent Electronic Devicesand Remote Terminal Units in a Substa-

tion (IEEE Standard 1379) was publishedin March 1998. This document did notestablish a new communication protocol.To quickly achieve industry acceptanceand use, it instead provided a specificimplementation of two existing commu-nication protocols in the public domain,DNP3 and IEC 870-5-101.

For IED communications, if yourimplementation timeframe is six to ninemonths, select from protocols thatalready exist: DNP3, Modbus, and Mod-bus Plus. However, if the implementationtimeframe is one year or more, considerUCA2 MMS as the communicationsprotocol. Regardless of your timeframe,evaluate each supplier’s product migra-tion plans. Try to determine if the systemwill allow migration from today’s IEDwith DNP3 to tomorrow’s IED withUCA2 MMS without replacing theentire IED. This will leave open theoption of migrating the IEDs in the sub-station to UCA2 in an incremental man-ner, without wholesale replacement. Ifyou choose an IED that is commerciallyavailable with UCA2 MMS capabilitytoday, then you may want to chooseUCA2 MMS as your IED protocol.

Substation to Utility EnterpriseThis is the area of traditional SCADAcommunication protocols. The DataAcquisition, Processing, and ControlSystems Subcommittee of the IEEEPES Substations Committee begandeveloping a recommended practice inthe early 1980s in an attempt to stan-dardize master/remote communicationspractices. At that time, each SCADAsystem supplier had developed a propri-etary protocol based on technology ofthe time. These proprietary protocolsexhibited varied message structures, ter-minal-to-data circuit terminating equip-

ment (DCE) and DCE-to-channel inter-faces, and error detection and recoveryschemes. The IEEE RecommendedPractice for Master/Remote SupervisoryControl and Data Acquisition (SCADA)Communications (IEEE Standard 999-1992) addressed this nonuniformityamong the protocols, provided defini-tions and terminology for protocols, andsimplified the interfacing of more thanone supplier’s RTUs to a master station.

The major standardization effort under-taken in this application area has takenplace in Europe as part of the IEC stan-dards-making process. The effort resultedin the development of the IEC 870-5 pro-tocol, which was slightly modified by GE(Canada) to create DNP. This protocolincorporated a pseudo transport layer,allowing it to support multiple master sta-tions. The goal of DNP was to define ageneric standards-based (IEC 870-5) pro-tocol for use between IEDs and data con-centrators within the substation, as well asbetween the substation and the SCADAsystem control center. Success led to thecreation of the supplier-sponsored DNPUser Group that currently maintains fullcontrol over the protocol and its futuredirection. DNP3 has become a de factostandard in the electric power industry andis widely supported by suppliers of testtools, protocol libraries, and services.

Cyber SecurityWhen today’s control systems weredesigned, information and system secu-rity was not a priority. SCADA andother control systems were designed asproprietary, stand-alone systems, andtheir security resulted from their physi-cal and logical isolation and controlledaccess to them. As information technol-ogy becomes increasingly advanced,substation automation continues tomove to open, standards-based net-

30 IEEE power & energy magazine march/april 2003

Selecting the right supplier ensures that you stay informed aboutindustry developments and trends and allows you to access newtechnologies with the least impact on your current operation.

march/april 2003 IEEE power & energy magazine

working technologies and/or the Inter-net to bring the benefits of informationsharing to operations. All suppliers havethe capability to implement Web-basedapplications to perform monitoring,control, and remote diagnostics. This,however, leads to control system cybervulnerabilities. Existing informationtechnology (IT) can protect substationcontrol systems from traditional IT vul-nerabilities, but they are not designed toprotect control systems against vulnera-bilities unique to control systems.

A security policy and a mechanismfor its enforcement should be developedfor the substation. A minimum list ofquestions to be addressed before attach-ing the SA system (or SCADA system)to the network include the following.

✔ Which network users and applica-tions require control system access?

✔ What do they need access to?✔ What type of remote access does the

user require (e.g., dial-up, telnet, ftp,X-sessions, PCAnywhere, etc.)?

✔ What are the security risks asso-ciated with each type of access?

✔ Is the information required worththe security risk?

✔ Is the password capable of beingchanged?

✔ How often should it be changed?✔ Who is the system administrator?

Make Decisions with the Future in MindAs we look to the future, it seems thetime between the present and thefuture is shrinking. When a PC boughttoday is made obsolete in six monthsby a new model with twice the per-formance at less cost, how can youprotect the investments in technologyyou make today? Obviously, there isno way you can keep up on a continu-ous basis with all the technologydevelopments in all areas. You mustrely on others to keep you informed,and who you select to keep youinformed is critical. With every pur-chase, you must evaluate not only thesupplier’s present products but also itsfuture product development plans.

✔ Does the supplier continuouslyenhance and upgrade products?

✔ Is the supplier developing newproducts to meet future needs?

✔ Do existing products have amigration path to enhanced andnew products?

Selecting the right supplier willensure you stay informed about newand future industry developments andtrends and will allow you to access newtechnologies with the least impact onyour current operation.

Further ReadingFundamentals of Supervisory Systems,IEEE Tutorial 94 EH0392-1 PWR, 1994.

IEEE Standard Definition, Specifi-cation, and Analysis of Systems Usedfor Supervisory Control, Data Acquisi-tion, and Automatic Control, IEEEStandard C37.1-1994.

IEEE Standard Electrical Power SystemDevice Function Numbers and ContactDesignations, IEEE Standard C37.2-1996.

Communication Protocols, IEEETutorial 95 TP 103, 1995.

Trial Use Recommended Practicefor Data Communications BetweenIntelligent Electronic Devices andRemote Terminal Units in a Substation,IEEE Standard 1379-1997.

Advancements in Microprocessor-Based Protection and Communication,IEEE Tutorial 97TP120-0, 1997.

C. Newton, “Keys to an automatedfuture: Decision maker series interviewof John McDonald,” T&D World, pp.68-71, Feb. 1999.

J.D. McDonald, “Substations,” inElectric Power Engineering Handbook.Boca Raton, FL: CRC Press, 2000, ch. 5.

J.D. McDonald and Southern Engi-neering, Automating a DistributionCooperative, from A to Z, NationalRural Electric Cooperative Association(NRECA) Cooperative Research Net-work (CRN), 1999.

J.D. McDonald and T.L. Saxton,“Understanding today’s protocol stan-dardization efforts,” Utility Automation,pp. 32-36, Sep./Oct. 1997.

J.D. McDonald, J.T. Robinson, andL.T. Swartz, “Substation communicationand protocols: Field trials and interna-tional standards,” presented at 1998CEPSI Conf., Pattaya, Thailand, 1998.

J.D. McDonald, D.G. Caceres, S.H.Borlase, and M.C. Janssen, “Standard-ized design of transmission substationautomation systems,” Congresso delCentro de Argentino de Ingenieros1998, Buenos Aires, Argentina, 1998.

J.D. McDonald, D.G. Caceres, S.H.Borlase, M.C. Janssen, and J.C. Olaya,“ISA embraces open architecture,”T&D World, Oct. 1999.

J.D. McDonald, “Industry activities insubstation protocol standardization,” EPRISubstation Equipment Diagnostics Conf.IX, New Orleans, LA, Feb. 2001.

J.D. McDonald, M. Doghman, andB. Dahl, “Present and future integrationof diagnostic equipment monitoring atOPPD,” EPRI Substation EquipmentDiagnostics Conf. IX, New Orleans,LA, Feb. 2001.

BiographyJohn D. McDonald received his B.S.and M.S. degrees in electrical engineer-ing from Purdue University and anMBA from the University of Californiaat Berkeley. As senior principal consult-ant and manager of Automation, Relia-bility, and Asset Management forKEMA Consulting, he assists electricutilities in substation integration andautomation, distribution managementsystems, distribution SCADA systems,and communication protocols. He is aFellow of the IEEE, secretary of theIEEE PES, past-chair of the IEEE PESSubstations Committee, and recipient ofthe IEEE Millennium Medal in 2000and the IEEE PES Award for Excellencein Power Distribution Engineering in2002. He gives tutorials and seminars insubstation automation, distributionSCADA, and communications for vari-ous IEEE PES local chapters as an IEEEPES Distinguished Lecturer. He waseditor of the “Substations” chapter and acoauthor for the book The ElectricPower Engineering Handbook, cospon-sored by the IEEE PES and published bythe CRC Press in 2000. He is editor-in-chief and author of the “Substation Inte-gration and Automation” chapter for thebook The Electric Power SubstationEngineering Handbook, to be publishedby the CRC Press in 2003.

31

p&e