research article towards the smart grid: substation...

Research ArticleTowards the Smart Grid: Substation AutomationArchitecture and Technologies

A. Leonardi, K. Mathioudakis, A. Wiesmaier, and F. Zeiger

AGT International, Hilpertstraße 35, 64295 Darmstadt, Germany

Correspondence should be addressed to A. Leonardi; [email protected]

Received 29 April 2014; Accepted 29 June 2014; Published 20 August 2014

Academic Editor: Sarod Yatawatta

Copyright © 2014 A. Leonardi et al. This is an open access article distributed under the Creative Commons Attribution License,which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

This paper deals with Industrial Control Systems (ICS) of the electrical sector and especially on the Smart Grid. This sectorhas been particularly active at establishing new standards to improve interoperability between all sector players, driven by theliberalization of the market and the introduction of distributed generation of energy. The paper provides a state-of-the-art analysison architectures, technologies, communication protocols, applications, and information standards mainly focusing on substationautomation in the transmission and distribution domain.The analysis shows that there is tremendous effort from the SmartGrid keystakeholders to improve interoperability across the different componentsmanaging an electrical grid, fromfield processes tomarketexchanges, allowing the information flowing more and more freely across applications and domains and creating opportunity fornew applications that are not any more constraint to a single domain.

1. Introduction

The electrical grid undergoes a fundamental change with theintroduction of the Smart Grid. Installation of end consumersmart meters, deployment of distributed renewable energygeneration, and interconnection of operation and informa-tion systems require new solutions that can intelligentlymonitor and manage the infrastructure.

The Smart Grid aims on raising operational efficienciesof operators by increasing the flow of information and auto-mation in order to enable better and faster decisions, hencereducing operational cost. In order to achieve this, utilitiesare facing some challenges to improve the power deliverymethods and utilization, including the integration of controlroom systems for better workflow, new consumer demands,and security of supply.

Additionally, future trends and developments in oper-ations centers, for example, Supervisory Control and DataAcquisition (SCADA) systems, can be observed.

(i) Integration of operations’ centers for smart distri-bution grids includes the advanced integration ofexisting IT infrastructure as well as the developmentof new applications.

(ii) SCADA systems are becoming increasingly ubiqui-tous. Thin clients, web portals, and web based prod-ucts are gaining popularity with most major vendorsbut also introduce additional security aspects.

(iii) SCADA systems become more integrated and con-nected with existing Enterprise Resource Planning(ERP) systems and other non-SCADA or externalapplications but require new, tailored architecturalapproaches to guarantee continuous operation ofcritical resources.

(iv) Information Technology (IT) and Operational Tech-nology (OT) vendors must prove that their analyticstools have real value at scale in order to integratetheir capabilities with new solutions that help utilitiesextract more value from smart meter data [1].

(v) Current trends in security are related to providingcomprehensive protection in order to address securitypolicies, manage user access to critical resources, andthe ability to detect andmitigate possible cyberattacksacross the entire grid infrastructure, mainly follow-ing National Institute of Standards and Technology(NIST) and International Electrotechnical Commis-sion (IEC) recommendations.

Hindawi Publishing CorporationAdvances in Electrical EngineeringVolume 2014, Article ID 896296, 13 pageshttp://dx.doi.org/10.1155/2014/896296

2 Advances in Electrical Engineering

Beyond a specific, stakeholder-driven definition (e.g.,the Smart Grids European Technology Platform), SmartGrids should refer to the entire power grid from generation,through transmission and distribution infrastructure all theway down to a wide array of electricity consumers. A wellthought-out Smart Grid initiative builds on the existinginfrastructure, provides a greater level of integration at theenterprise level, and has a long-term focus. It is not aonetime solution but a change in how utilities look at a setof technologies that can enable both strategic and operationalprocesses. Smart Grid is the means to leverage benefits acrossapplications and remove the barrier of silos of organizationalthinking.

From a high-level system perspective, the Smart Grid canbe considered to contain the following major components:

(i) smart sensing and metering technologies providingfaster and more accurate response for the consumer(e.g., remote monitoring, time-of-use pricing, anddemand-side management) [2];

(ii) integrated, standard-based, two-way communicationinfrastructure that provides an open architecture forreal-time information and control to every end pointon the grid [2];

(iii) advanced control methods monitoring criticalcomponents, enabling rapid diagnosis, and preciseresponses appropriate to any event [2];

(iv) a software system architecture with improved inter-faces, decision support, analytics, and advanced visu-alization enhancing human decision making, effec-tively transforming grid operators and managers intoknowledge workers [2].

The Smart Grid Architectural Model (SGAM) Frame-work [3] aims at offering a support for the design of smartgrid use cases with an architectural approach allowing for arepresentation of interoperability viewpoints in a technologyneutral manner, both for current implementation of the elec-trical grid and future implementations of the smart grid (c.f.,Figure 1). It is a three-dimensional model that is merging thedimension of five interoperability layers (business, function,information, communication, and component) with the twodimensions of the Smart Grid Plane, that is, zones (repre-senting the hierarchical levels of power system management:process, field, station, operation, enterprise, and market)and domains (covering the complete electrical energy con-version chain: bulk generation, transmission, distribution,distributed energy resources, and customers premises).

This work will provide a state of the art of the relevantparts of the Smart Grid, mainly focusing on substationautomation in the transmission and distribution domains(c.f., semitransparent cube in Figure 1), as well as relevantprotocols, applications, and regulations concerning the con-trol center.

2. Electrical Substation Automation

This section presents the substation types and roles, theelectric substation automation (SA) system components, the

information flow between different levels of SA, and the SAsystem architecture.

2.1. Substation Types and Roles. The electrical substation isof paramount importance to the electrical generation, trans-mission, and distribution system. According to [2] there arefour major types of electric substations.

(i) Switchyard substation at a generating station connectsthe generators to the utility grid and also provides off-site power to the plant. Generator switchyards tendto be large installations that are typically engineeredand constructed by the power plant designers and aresubject to planning, finance, and construction effortsdifferent from those of routine substation projects.

(ii) Customer substation functions as the main source ofelectric power supply for one particular business cus-tomer. The technical requirements and the businesscase for this type of facility depend more on thecustomer’s requirements than on utility needs.

(iii) System substation involves the transfer of bulk poweracross the network. Some of these stations provideonly switching facilities (no power transformers),whereas others perform voltage conversion as well.These large stations typically serve as the end pointsfor transmission lines originating from generatorswitchyards and provide the electrical power forcircuits that feed transformer stations. They are inte-gral to the long-term reliability and integrity of theelectric system and enable large amounts of energyto be moved from the generators to the load centers.System stations are strategic facilities and usually veryexpensive to construct and maintain.

(iv) Distribution substations are the most common facili-ties in electric power systems and provide the distri-bution circuits that directly supply most customers.They are typically located close to the load centers,meaning that they are usually located in or near theneighborhoods that they supply, and are the stationsmost likely to be encountered by the customers.

A visual representation of how the electrical substationsare used within the electric grid is presented in Figure 2. Thesubstation is depicted as a grey box.

The substation roles clearly indicate that it can be consid-ered as critical infrastructure, especially for substations in thetransmission grid, interconnecting many systems. As such,it requires proper physical and cyber protection to ensureuninterrupted and smooth operation.

2.2. SA System Components. The SA system uses any numberof devices integrated into a functional array for the purposeof monitoring, controlling, and configuring the substation.

The components of the SA system are as illustrated inFigure 3 where VT, CT, and PT stand for voltage, current, andpower transformer, accordingly. In the following section, wedescribe the remote substation components and the operationscenter components.

Advances in Electrical Engineering 3

GenerationTransmission

DistributionDER

Customerpremises

Market

Enterprise

Operation

Station

Field

Process

Domains

Zones

Interoperabilitylayers

Business layer

Function layer

Information layer

Communication layer

Component layer

Protocol

Protocol

Business objectives polit./regulat. framework

Functions

Data model

Data model

Outline of usecase

Figure 1: CEN-CENELEC-ETSI Smart Grid plane of domains and hierarchical zones [3].

2.2.1. Remote Substation Components. The SA componentspresent in the substation are as follows.

(i) Microprocessor-based intelligent electronic devices(IEDs), which provide inputs and outputs to the sys-tem while performing some primary control or pro-cessing service. Common IEDs are protective relays,load survey and/or operator indicating meters, rev-enue meters, programmable logic controllers (PLCs),and power equipment controllers of various descrip-tions [2].

(ii) Devices dedicated to specific functions for the SAsystem like transducers, position sensors, and clustersof interposing relays may also be present [2].

(iii) Dedicated devices often use a controller (SA con-troller) or interface equipment like a conventionalremote terminal unit (RTU) as a means to connectinto the SA system [2].

(iv) A substation display or users station (local HMI),connected to or part of a substation host computer(local server), may also be present [2].

(v) Common communication connections to the outerworld like utility operations centers, maintenanceoffices, and/or engineering centers. Most SA systemsconnect to a traditional supervisory control and dataacquisition (SCADA) system master station servingthe real-time needs for operating the utility networkfrom one or more operations centers. SA systemsmay also incorporate a variation of SCADA remoteterminal unit (RTU) for this purpose or the RTUfunctionmay appear in an SA controller or substationhost computer [2].

Other utility users/services usually connect to the systemthrough a firewalledDMZ, which is connected to the SCADAsystem.


Coal plantHydroelectric plant

Medium sizedpower plant

Industrial power plant

Factory

City network≈3 MW

substations

Rural network

Wind farm

Solar farm

Industrialcustomers

Up to ≈150 MW

≈400 kW

Citypower plant

Nuclear plantExtra high voltage

265 to 275 kV(mostly AC, some HVDC)

High voltage

Transmission grid

Distribution grid

Farm

Low voltage

600–1700MW

110 kV and up

≈30MW

50kV

≈2MW

≈200MW

≈600MW

≈150MW

Figure 2: Substations in the electric grid [4].

2.2.2. Operations Center (SCADA Master Station) Com-ponents. In electric substation automation, the operationscenter (or master control center or SCADA master station)receives and processes data from several substations and takeappropriate remote substation control actions [5].Themasterstation system may sometime use an open and distributedarchitecture. There can also be multiple master stations andaccordingly different topologies can be used to interconnectthem for synchronizing the grid operational data. Each mas-ter station (manned) is supported with a backup/emergencymaster station (unmanned) and is continuously synchronizedwith a primary master station database.

The main elements of the SCADA master station (orSCADA master) are Human Machine Interface (HMI),application servers, firewall, communication front-end (to

communicate with RTU’s/data concentrators), and externalcommunication server/M2M gateway (to communicate withother control centers). These elements are networked withinthe SCADA master via real-time dedicated LAN. The appli-cation servers include servers that support all energy man-agement system (EMS) or distributed management system(DMS) applications.

Redundancy is provided for the hardware and softwareelements of SCADA master (e.g., redundant LAN) andsubstations (e.g., redundant critical computer) as well as forthe M2M communication network.

2.3. SA Information Flow. Substation automation can be bro-ken down into five levels according to [6]. Starting from thebottom we have power system equipment (e.g., transformers,


Billing

Operations

Revenuemeters

Revenue CTs and PTs

Troubledispatchers

Protection analysts

Planning analysts

Maintenance scheduler

SA controller

Protective relays

Equipment controller or PLC

Announciator and SOE recorder

Disturbance recorder

X’ducersInterposer

InterfacePower equipment controls

Indicating and recording

meters

Substation CTs and PTs

Communication technology

center (SCADA)

and/or RTU

Serv

er/h

ost

Figure 3: Power station substation automation system functional diagram [2].

circuit breakers); three middle levels: IED implementation,IED integration, and SAapplications (usually they aremergedas bay level); and finally at the top, the utility enterprise.

In order to interconnect these layers, three functionalcommunication data paths exist from the substation to theutility enterprise.

(i) The operational data (e.g., volts, amps) path toSCADA is the most critical and utilizes one of thecommunication protocols supported by the SCADAsystem.

(ii) The nonoperational data path to utility’s data ware-house conveys the IED nonoperational data, likeevent logs, from the SA to a warehouse.

(iii) Finally, the remote access path to IEDs utilizes a two-way network connection.

Figure 4 shows the three functional communication datapaths as well as the basic components of SA system. Althoughit is shown for the energy management system (EMS) case,the data flow is similar for distribution management orSCADA systems.

2.4. SA System Architecture. Figure 5 shows the SA systemarchitecture for remote monitoring, management, security,and maintenance of unmanned energy substations andrelated sites. As expected, it takes full advantage of the net-work-based architecture.

The subsystems at remote substation and operation centercan be networked via M2M broadband communication net-work service (fixed and wireless broadband network, satellitelinks, and secured IP network), a platform to remotelymonitor and manage devices and machines [7].

Note that the physical access control system is integratedwithin the same architecture, providing video surveillance,site monitoring, and access management for the substations.

3. Smart Grid Control Center Applications

The smart electric transmission and distribution grid func-tionalities are centrally performed at the control center byseveral control centers or electric utility applications thatinclude SCADA, DMS, EMS, Automated Meter Reading(AMR), Network Integration System (NIS), and GeographicInformation System (GIS).

3.1. Concept of Operations. The typical roles of personsinvolved with SCADA based monitoring and control oper-ations are SCADA Manager, SCADA Information securityofficer, SCADA system administrator, SCADA operator,SCADA engineer/developer, field maintenance worker, andexternal user (via remote access). The external users arecontractors, consultants, SCADA vendors (maintenance andemergency access), and Managed Security Solution Provider(MSSP). The latter usually performs the SCADA cyber secu-rity monitoring which is outsourced to them by the utility. Incase of not outsourcing this task, cyber security monitoringis done by the Security Incident Manager.

The SCADAmanager is responsible for ensuring that cor-porate policies are followed. The information security officeris responsible for ensuring that the security policy is fol-lowed and performs audits. The administrator is responsiblefor system activities like maintenance, expandability, andperformance. The control center operator is responsible forperforming operational functions like electric substation


Historian

IT systems

Energymanagement Authorized

user PC

Substation server

Remote accessNonoperational dataOperational data

rgy

Secure remote access

Figure 4: Substation data flow [2].

Substation

DMZ LANCorporate LAN

Authorizeduser PC

Authorizeduser PC

FirewallFirewall

Firewall FirewallFirewall

Cyber accessmanagementsystem

Outagemanagementsystem

Assetmanagement system

Control LAN

Distributionmanagementsystem

Energymanagement system

Videosurveillanceserver

Videosurveillanceserver

Physical security LAN

Physical accesscontrol system

Substation LAN

Network router/firewall

Network switch

IEDIED

Substationoperatorinterface

Protective relay

Protective relay

Substationserver

Serial IED Serial IED

Serial connectionNetwork connection

Historianserver

Figure 5: Smart integrated substation [2].


monitoring and control. The maintenance workers performthe fieldwork assigned to themby the control center operator,the scheduler, or the dispatcher.

3.2. System Activities and Performance. In addition to theelectric network management system activities, the SCADAalso serves as a source of important operating data requiredfor effectivemanagement of the utility’s business.The SCADAsystem performance is based on its availability, maintenance,response time, security and expandability. The high avail-ability of the SCADA system and the continuous operationassurance are attained by introducing reliability as well asredundancy of the hardware and software. In case of damageto the primary master station, for example, due to eventslike natural disasters, the back-up/emergency, master stationtakes over the system operation.

The system is in normal state when the load and operatingconstraints are satisfied. In such occasions the main systemperformances are met. It switches to the emergency statewhen the operation conditions are not completely satisfied.In the emergency state the response time might be slow andthe system performance is allowed to degrade but the basicfunctionalities (e.g., alarm and status change operations) areretained.

The system’s access level is restricted for different group ofworkers (Access Authorization). For example, the operatorsare generally provided with complete access to display andcontrol functions for specific Areas of Responsibility (AoR),while the maintenance staff may only have access to displayfunctions.

The system maintenance involves hardware/softwarerepair using diagnostic tools (debugging, corrections),updates (patch management, antivirus protection), tests andpreventive maintenance. It can be expanded with new points,functions and equipment depending on the functional andstandardization needs. The limitations (e.g., physical space)and downtime are considered important factors duringexpansion.

3.3. Operational Functions. The main operational functionsof the real-time SCADA system includes: data acquisition andprocessing, basic network monitoring, device and sequencecontrol, network and device tagging, and alarms and eventsmanagement [8].

Particularly, the DMS includes applications (tools) thatperform the following functions: network topology monitor-ing, demand response and load management, load and gen-eration forecasting, switching procedures, fault management,outage management, trouble call management, work man-agement, crewmanagement, customer information, and assetmanagement [9]. Moreover, the Energy Management System(EMS) performs remote and local control and supervision oftransmission systems.

4. Communication Layer

The communication layer in smart grids serves as the coreof the entire remote monitoring system. It not only collectsoperational data from the field devices and sends the data

to the SCADA servers, but also transmits commands fromthe control center to the control units in order to actuatethe equipment. The emphasis of the communication layer isto describe appropriate protocols and mechanisms for theinteroperable exchange of data between the components ofthe smart grid.

Key requirements of a fast, robust and reliable communi-cation system include.

(i) Identification of communication traffic flows:source/destination/quantity.

(ii) System topology (e.g., star, mesh, ring, bus).(iii) Device addressing schemes.(iv) Communication network traffic characteristics

(bandwidth, delay, latency, jitter, reliability, and errorhandling).

(v) Performance requirements.(vi) Timing issues.(vii) Reliability/backup/failover.(viii) Operational requirements (e.g., security, andmanage-

ment of the network).(ix) Quantification of electromagnetic interference with-

stand requirements.

Another critical requirement and recent trend in substa-tion integration and automation architecture is the use ofstandard communication interfaces to ensure interoperabilitybetween different vendors’ components as well as with legacyequipment. The lack of standard protocols may lead to com-munication errors or to incompatibility between differentdevices. Industries that have invested in proprietary andvendor oriented SCADA communication systems addressserious scalability issues, as they are restricted to limitedchoice of equipment when requirements change.

To mitigate such problems, open communicationprotocols (e.g., IEC 60870-5-101/104 and DNP 3.0) andcontrol-center-to-control-center communication (e.g., ICCPIEC60870-6/TASE.2) became increasingly popular amongSCADA equipment manufacturers and solution providersalike (see Section 4.2).

4.1. Communication Technologies. In conventional substa-tions, serial communication buses or proprietary protocolsare used for local HMI, as well as for remote SCADAcommunication. Modern communication in substation isdata transmission inside and between station, bay andprocesslevel. Communication between these 3 levels is called verticalcommunication and is conducted by high-speed Ethernetstation bus and process bus. Station bus facilitates commu-nication between station level and bay level. Communicationwithin one level is considered horizontal. Communicationnetworks within the substations often have lower-level datalink, physical layer protocols and multiple application layerprotocols running on top of TCP/IP.

Traditional SCADA systems had a master-slave com-munication model. Nowadays, with the availability of net-workable communication protocols, such as IEC 61850, it is


Historian

Operationsapplications

OpenIEC61970(EMS-API) interfaces

Operationsintranet

Substations/field equipment

Networked communications

Corporateintranet

Firewall

CorporateEnvironment

DB serversExternalfirewall

Figure 6: Networked SCADA communications [2].

possible to simultaneously support multiple clients located atdifferent remote locations, although it complicates who hasthe control of the equipment. Figure 6 shows an example ofsuch a network.These networks allow the integration of bothcontrol center and enterprise information systems.

Based on the topology of the distribution network, theappropriate technology has to be chosen among differentsolutions. Utility communication networks comprise bothwireless and wired technologies [2]. Copper wires (e.g., low-rate or broadband DSL signals), fiber optics (e.g., Ethernetsignals for broadband MANs), leased phone lines or cellularand satellite communications may be employed for theinterconnection of the substation with the control center orbetween the components of the substation. New developmenttrend is the spread spectrum radio technologies which canoperate in unlicensed ISM bands in the 900MHz, 2.4GHz,and 5.6GHz bands or licensed in other nearby bands.

Criteria for the selection of the most appropriate technol-ogy are bandwidth and delay requirements for the commu-nication link, and whether a global or a regional solution istargeted or not. Additionally, wireless and satellite systemsare subject to eavesdropping, so the use of appropriatesecurity measures is indicated to avoid loss of confidentialinformation.

SCADA communication networks tend to come in linewith standard networking technologies in future. Ethernetand TCP/IP based protocols are replacing the older pro-prietary standards. Migration strategies that are availabletoday have to be identified, in order to move from legacy

technology to the standard protocols. It is unlikely that onetechnology alone will ever provide a complete solution forall communications, thus interoperability and compatibilityof different technologies will be the key requirement for allfuture generations of systems.

4.2. Communication Protocols. One recent effort on commu-nication interfaces of a control center is the OPC protocol[10]. In general, it enables the overall data exchange betweenautomation and control applications, field systems/devicesas well as business and office applications. It was developedby the automation industry to standardize the commu-nication of real-time plant data between control devicesfrom different manufacturers. Specifically, OPC is a set ofindustrial standards for systems interconnectivity, providinga common interface for communications between multi-vendor software applications that is applicable in a widerange of industries spanning from process industries tosubstation automation and many others. More recently, theOPCUA protocol [11] was introduced in order to support theinteroperability and the platform independence.

Communication between control centers is provided viathe Inter Control Center Communication Protocol (ICCP)or ELCOM [12], and is based on TCP/IP. The ICCP is anopen and standardized protocol based on IEC 60870-6 andTelecontrol Application Service Element Two (TASE.2). Theexchanged data is primarily real-time system information likeanalog values, digital values and accumulator values, alongwith supervisory control commands [13]. The data transfer


Transmission Distribution

Field

Station

Operation

Process

Enterprise/marketCIM

IEC 61850

MultiSpeak

Figure 7: Information model domains.

can take place in both directions between two control centers.Both control centers can initiate interactions/data transfers.The protocol supports spontaneous data transfer, periodicdata transfer, and data transfer on request.

For the communication within the substation the IEC61850 [14] developed by WG 10 [15] is broadly used. It isa standard for electric utility automation, defining commu-nication between IEDs within a substation. It is developedwithin IECTC 57 [16] and is composed of 10 parts. It providescommunication protocols, data models, security standards,and so forth. Although the scope of IEC 61850 was originallyfocused on substation automation and the correspondingcommunication, discussions are underway to look at definingIEC 61850 for the Substation to Master communicationprotocol. In addition, applications are available using variouscomponents of IEC 61850 for wide area substation-to-sub-station communication.

The DNP3 [17] is a serial communication protocol andspecifies the data link layer, the application layer and atransport pseudo-layer. It is used primarily in electric utilitiesin North America, and offers similar features as IEC 60870-5-104 [18] which is more popular in Europe. Its scopeis to enable interoperability among compatible telecontrolequipment.

Modbus [19] is another serial communication protocolwhich is commonly available for interconnecting electronicdevices. Modbus is very well known, easy to implement andwidely used in all industries. Nevertheless, as most serialprotocols Modbus offers no security and no standard way toprovide information about the data it transports.

5. Information Layer

In this Section we present different information models forthe power industry, each of them covering specific domainsand levels of the SGAM [3]. Figure 7 shows how they fit intoour scope.

Note that CIM and IEC-61850 cover further domainssuch as generation and Distributed Energy Resources (DER)which are out of scope of the paper at hand.

5.1. CIM. The Common Information Model (CIM) enablessoftware applications to exchange configuration and statusinformation of an electric network. It comprises of threestandards that are all developed within the IEC TechnicalCommittee 57 (TC 57) [16]: IEC 61970 [20] (transmission)developed by WG 13 [21], IEC 61968 [22] (distribution)developed by WG 14 [23], and IEC 62325 [24] (market)developed by WG 16 [25].

CIM is described using Unified Modeling Language(UML) and is organized in packages, each containing aset of classes along with their inheritance structure, theirattributes, and their associations. IEC 69170 further specifiesa mapping from UML to Resource Description Framework(RDF), as well as how messages should be serialized in XML(CIM XML).

CIM supports profiles which apply for specific applica-tions only. Profiles are subsets of usually a few dozen classesof the more than 700 CIM classes. IEC 61970 defines a fewprofiles such as “Schematic Layout Profile” or “TopologyProfile”.

Currently, CIM is mainly used by EMS applications inorder to exchange information about the current transmis-sion states. However, the potential of CIM is much higher asit can be used to describe and exchange data about almostanything related to power systems and its management,including workforce and energy markets.

5.2. MultiSpeak. MultiSpeak [26] defines standardized inter-faces among electric utility software applications for distribu-tion only. It offers definitions in the following areas: commondata semantics, message structure, andmessages required forspecific business process steps.

MultiSpeak supports two communication transferoptions: file based (batch processing) and web services (real-time data). Further, it offers three different communicationmodes: batch, request/response, and publish/subscribe.

Currently, MultiSpeak is the most widely applied defacto standard in North America pertaining to distributionutilities. Nearly 70 vendors are using the specification in theirproducts and more than 600 electric cooperatives (from 15


different countries) use MultiSpeak supported products intheir daily operations [27].

5.3. IEC 61850. As described before, IEC 61850 provides bothan abstract data model and an abstract communication inter-face.The standard consists of 10 parts.The ones regarding theinformation layer are

(i) part 61850-6 [28] which defines an XML languagecalled Substation Configuration Language (SCL) andfour file formats for describing the configuration ofsubstation equipment and IEDs configurations;

(ii) part 61850-7 [29] which defines the basic commu-nication structure and has multiple parts itself andspecifically: IEC 61850-7-2 [30] defines the commu-nication services, which permit to query or sendcommands to the devices; IEC 61850-7-3 [31] and IEC61850-7-4 [32] define the object model that describesthe equipment of the substation.

All big vendors of power automation technologies andmany smaller ones support or even favorite IEC 61850.Within the context of many smart grid projects in NorthAmerica, Europe, or Asia IEC 61850 is seen as the mostimportant standard.

5.4. Harmonization. There exist semiautomated approachesto create converters betweenCIMand IEC 61850models suchas in [33].

A direct translation between CIM andMultiSpeak can beachieved using style sheets and readily available tools [34].

IEC TC 57 WG 19 [35] is working [36] on harmonizingCIM and SCL. IEC TC 57 WG 14 [23] is working [37] onharmonizing CIM and MultiSpeak.

In the context of their smart grid interoperability efforts[38] NIST is working [39] on integrating IEC 61850, IEC61968, and MultiSpeak.

5.5. Comparison. Table 1 shows a comparison of function-alities: market and domain for the presented informationmodels.

6. Security and Regulations

Security in Smart Grids is a crucial factor because disruptionsin these systems can lead not only to the destruction ofexpensive equipment but also interruption of critical opera-tions that can include significant risk to the health and safetyof human lives, serious damage to the environment, andfinancial issues such as production losses and negative impactto a nation’s economy.

In a report entitled “Electric Power Risk Assessment”[40], the National Security Telecommunications AdvisoryCommittee (NSTAC) concluded that power substations were“themost significant information security vulnerability in thepower grid” mainly because the remotely accessible devicesused within substations are largely unprotected against intru-sions.

Various regulatory mandates exist or are emerging thatrequires energy utilities to secure, monitor, and manage their

critical sites and data networks in accordance with regulatoryrequirements and standards. These differ in granularity andscope, ranking from process oriented to technical standards[41–45].

Figure 8 gives an exemplary overview of potential targetsfor cyber-attacks (indicated by yellow exclamation marks)on the communication infrastructure of SCADA systems.The main problem in most of the existing systems derivesfrom the fact that SCADA systems were not designed tobe connected to the outside network infrastructure andconsequently security aspects were not considered during thedevelopment phase.

The vulnerabilities affecting the SCADA system regardmainly the following components [46].

(i) IEDs and RTUs in the substations;(ii) Substation LAN and firewall;(iii) Communication network between substation and

control center;(iv) SCADA LAN and firewall;(v) Corporate (office) LAN and firewall;(vi) Computers of vendors that can access the SCADA

network for maintenance.

Specifically, concerning IEDs, the security risk is causedby the lack of cryptographic capability because the overheadinduced by the extra payload and processing would causeunacceptable delays in time-sensitive applications, especiallydue to the fact that the microprocessors used in IEDshave little processing capabilities. More recently, IEDs thatimplement protocols such as IEC 61850 are however able tovalidate the authenticity of messages.

The messages that IEDs exchange with the outside worldare often transmitted over communication channels that arepotentially open to eavesdropping or active intrusions.More-over, the communication protocols most frequently used insubstations are well known (Modbus, Modbus-Plus, DNP3,etc.) but security was not an issue when these protocolswere designed, and they contain no features to ensure theconfidentiality or authenticity of the data transmitted. Hencecontrol messages can be easily spoofed or replayed.

A large potential threat to these systems is derived fromunauthorized users on the corporate network or any networkthat has connection with the SA. Consequently, the first stepin securing substation assets should be to ensure that thecorporate network is made as secure as possible and hassufficient points of control and isolation from the SA systemnetwork using appropriate firewall rules and other knowncyber-security measures [1]. Moreover, if wireless technologyis deployed at the substation, it can create a new attack vectorif no proper security measure such as access control andencryption are in place.

The physical protection of the cyber components anddata associated must be addressed as part of the overallsecurity. Having physical access to a control room or controlsystem components often implies gaining logical access to theprocess control system as well (e.g., through network or USBports).


Table 1: Information model comparison.

CIM MultiSpeak IEC 61850Utility domain andinteroperability Transmission, generation, and distribution Distribution Substation automation

Markets focus International utilities Electric cooperatives in USA International utilitiesCommunication/data transfer Transport independent SOAP messages using HTTP, TCP/IP MMS, TCP/IPDefinitions XML XML XML

DMZ

Substation LAN Substation LAN

IED

IED

RTU

Communication network

RTU

SCADA LAN

SCADAserver

HMI Historian

Terminalserver

Reportsserver

Internet WAN

IED

Modem

System vendors

Corporate LAN

Figure 8: SCADA system vulnerabilities.

IEEE Standard 1402-2000 [43] identifies and classifies thetypes of “intrusions” into a substation and discusses somesecurity methods to be adopted for mitigating risks.

Also NERC in “Security Guidelines for the ElectricitySector” [44] has developed a comprehensive set of guidelinesaddressing general approaches, considerations, practices, andplanning methods to be applied in protecting the electricinfrastructure systems.

Other physical security measures coupled with electroniccontrols are discussed in NERC-CIP-006 [45].

7. Conclusions

Industrial Control Systems (ICS) have passed through asignificant transformation from proprietary, isolated systemswith dozens of different vendor specific standards towardsopen architectures and standard technologies highly inter-connectedwith other applications and systems over corporatenetworks, as well as wide area networks, or the Internet.This paper focused on the ICS of the electrical sector andparticularly on the Smart Grid and provided the necessary

background information on SCADA and utility applicationsthat run typically at the control center of transmission ordistribution grid operators. This sector has been particularlyactive at establishing new standards to improve interoperabil-ity between all sector players and will continue developingtowards the Smart Grid which is needed for an efficientintegration of distributed energy generation technologies.

Moreover, a state-of-the-art analysis of the communica-tion and information standards and technologies in trans-mission and distribution has been presented, ranging fromthe field devices in electrical substations to the control center.Throughout the state-of-the-art analysis, it can be concludedthat there is tremendous effort from the Smart Grid keystakeholders to improve interoperability across the differentcomponentsmanaging an electrical grid, from field processesto market exchanges. The information can now flow moreand more freely across applications and domains, and thereis an opportunity for new applications that are not any moreconstraint to a single domain.

ICS are very heterogeneous in protocols, applications, andnetwork topologies they use. Therefore the selection of the


communication protocol or technology should be thoroughlyinvestigated. Based on how widespread the adoption of aprotocol is, as well as the support of the interoperability, it isobserved that approaches likeOPCUAas the communicationprotocol and CIM as the information model show promisingresults and are more and more adopted by industry.

The observed developments in the Smart Grid domainraise several security aspectswhichwere briefly discussed andmost probably will gain more importance in the future.

Conflict of Interests

The authors declare that there is no conflict of interestsregarding the publication of this paper.

Acknowledgments

The authors thank A.-K. Chandra-Sekaran, R. Gold, A.Hessler, G. Mazarakis, and K. Sasloglou for their valuablecontribution to this work.

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