1.1 system than the above control panels. The whole

1.

1  INTRODUCTION Technology advancement is happening all over theworld and complete world is moving towards digitalization. Substation Equipmentsare getting smarter in collecting data and information exchange. EnergyAutomation is in transformation stage from partial digitalization to completedigitalization with the advancement in communication and standards. TraditionalControl panels and complex wiring from process Equipments like circuitbreakers, Current Transformers, Voltage Transformers are now with Fiber OpticCommunication. Decentralization is also a topic for today andtomorrow as cloud computing and Internet of Things technologies are ready toroar in the Energy Automation and power grids. Pilot projects are happening allover the world with decentralization concepts with these technologies.

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On theother side cybersecurity incidents are happening in the energy environment andneed for awareness and standard implementation for cybersecurity is challengein order to ensure the assets and data. Further chapters in this study shall providedetailed information regarding digital substations and Decentralization inenergy Automation.                             1.

2  TRADITIONAL CONTROL PANEL A traditional control panel which were in placeuntil 2000’s where the field and process equipments were wired to control panelfor monitoring and operation. Single Line Diagrams of substation are made in formof mimic semaphore indications and control push buttons. Alarm and resethandling was through indication lamps leaving to a complex maintenance andtroubleshooting issues. Operators need to be there in the substation on shiftbasis and all records of measurements, alarms and notable events to be manuallynoted in the Maintenance Register. Root Cause Analysis was a challenge with theavailable less data in the Maintenance register.   Figure-1 – Traditional Control Panel until early2000s The modern-day substation control system is acomplete different system than the above control panels.

The whole data can bevisualized with the Human Machine Interface(HMI) operator workstations andEngineering workstations. All Alarms and Events with the data history can bevisualized in the Alarm and Event window of HMI Screens. Control and Monitoringis possible via keyboards and mouse operation in the HMI PCs. ProtectionRelays, Fault Recorders are smarter and communicable to the station controllerand thorough fiber optic communication network with a speed of 10/100 MBPS.

Inaddition to these, recent development of merger units adjacent to CT/VT ensuresthe complete digitalization of data from process bus to station bus.  This complete information exchange from process/fieldequipments to control center is called as digital substation. Figure 2: Modern Substation Control System.

 The advantages of digital substation are as below 1.    HumanMachine Interaction. 2.    Alarmand Event Windows with Filtering Facility. 3.    ArchivingBackup.4.

    SimpleFO Cabling -No Complex wiring. 5.    EasyMaintenance and Trouble Shooting. 6.    InformationExchange from Process to Station Level.

7.    BetterDecision Making.8.    Unmannedsubstations. Nothing runs with out electricity in this modernworld and no time for breakdowns which will produce economics loss and tensionsaround. The major tasks of substation digital automation are: §  Toensure personnel and operational safety always.§  Tooptimize control and monitoring of the electrical network concerned utilizingthe functions implemented.

 Operator Workstation, Engineering Workstation andStation Controllers are Industrial PCs with higher Hardisk capacity and RAMbased on the latest availability. Communications equipments such as Layer-2Ethernet switches and Layer-3 Ethernet switches (also called as Routers),Firewalls, Event Printers, Ethernet Patch chords and its connection toIntelligent Electronic Devices (Protection Relays, Bay Control Units,Multi-Function Meters etc.) form the station bus.   1.3 hierachy levels of substationinformation exchange The three levels of current substation automationsystem is as per the figure (X)below  Figure(X) Level 1 bay level/ied level At this lower level all CT/PT inputs are hardwiredto Intelligent Electronic Devices (Bay Control Units and Protection Relays) forupward communication to Substation Automation System and Control center.Various Feeder status, indications, measurements and metering as well as faultrecords are collected with these bay devices and sent to upstream level formonitoring, control, diagnosis and analysis.

 Fiber Optic Ring or star topology to ensure highestlevel of redundancy is adapted for connection to system. Inter baycommunication and communication to station controller is achieved via IEC 61850protocol standard for all protection relays and bay control units(IEDs). If anynon-IEC 61850 devices exist, the same shall be communicated via other serialtransmission protocols or hardwired to station controller. Level 2 STATION level At station level the station controller used offershigh flexibility spanning numerous communication protocols including IEC61850.With reference to UAE projects IEC 60870-5-101, IEC 60870-5-104, IEC61850, Modbus & OPC protocol are still used and in future all dataintegration shall happen through only IEC 61850 Standard. Additionally, thishighly robust system allows for a universal automation system CFC for IEC 61131standard logic realization.

 Generally redundant station units working as fullservers are provided at station level with automatic switch over facilityfurther upstream under HMI level to ensure the necessary uptime is maintainedfor control, monitoring and data acquisition. Both servers communicate todownstream level 1 IEDs via Ethernet LAN using Layer 2 Ethernet switches (IEC61850 complaint) that are interconnected in cross configuration. HMI Softwares run on windows platform with familiardrop-down menus as in windows applications. The Redundant computers (Operatorworkstation and Engineering workstation) where data archiving, Event.

, Alarmhandling and data distribution are done from respective downstream stationcontrollers (RTU/PC Server). This redundant HMI Computers normally equippedwith 2no flat screen monitors, keyboards, mouse ,Event printer together withlaser printer, forms the Front End part of Control. Monitoring and Automationfor the End User at station level. Taking the focus to Engineering and Operator workstation major Visual Diagrams include §  SystemCommunication Overview Diagram§  OverallVoltage Level Single Line Diagram§  Detailedviews of Individual Bay Wise Diagram§  Eventlist in a Chronological listing§  Alarmlist with Alarm classification§  TrendAnalysis Graphical Displays§   The figure(X) below shows the connection overview ofvarious hardware equipments together with their panel arrangement andcommunication mediums that represents the substation automation system.Segregation of voltage level is also done via dedicated voltage levelcommunication overview buttons and screens. Fig(X) Communication status of every connected equipmentincluding IEDs, Monitos,Ethernet Ports is indicated by dynamic color coded lineacross the perimeter of every connection block with “Red” indicating communication failure and “Green” indicating onlinestatus with good connectivity .

Communication failure will also result in alogged response in the Event and Alarm List. The below figure (X)gives an electricalrepresentation of the overall system status in the form of single line diagramthat operators are more familiar with. This substation overview screen providesa summed-up bus and feeder displays with sufficient dynamic switching devicestatus information necessary for the operator to get an overall system overviewof the station.

Additional overview pictures can also be developed forindividual voltage and bay screens which enhance he details to the operator.   Fig(X) The figure (X) shows the display of trend curveswhich are available for voltages and currents in every phase together withfrequency, active and reactive power readings. These analog values arecyclically read from respective IEDs at fixed intervals and graphicallydisplayed in screens. Buttons with in the frames on the left give accessto individual trend curves for specific bays being studied.

Tabulated readingsare also available via access button within each trend window. Other facilitiesavailable include printing, saving and trend freezing via stop button. Bayrelated information such as voltages (phase to phase ,phase to ground ,busvoltage),Three phase currents, Active, Reactive power, power factor and busfrequency amongst others are all detailed on these screens .   The below figure(X) shows the display of Event andAlarm processing information via Event and Alarm list configured in Operatorand Engineering Work station. Incoming information from multiple resourceslike  below are all accumulated fornecessary operator intervention(in case of Alarms) or for historical recordsfor future analysis and diagnosis(Event list) §  Feederspecific Information from individual bay control units §  Auxiliarysystem information -Common station signals §  Systemgenerated information like login/logout, Equipment failure etc.

§  Timesynchronization information from GPS receiver equipments§  ConfigurationLimit violations from predefined threshold limits By default, all signals received are recorded in theevent list and preconfigured signals with assigned classifications are sent tothe Alarm list.Interchangeability between these two lists isachieved via the navigation selection bar at the bottom of the screen. Specifically, to Alarm lists, OperatorAcknowledgement facilities available provide for a systematic approach totackle incoming and persistent alarms. Incoming Alarms appear with “Red”background for immediate operator action. Disappearing alarms take on a “Green”background. Acknowledged Alarms take on a “Blue” font to indicate recognitionof occurrence.   Fig(X) In general, the following functionality isincorporated in the above-mentioned screens §  Local/RemoteStatus Indication at Bay Level §  SwitchingOperations§  PeriodicMeasurement Monitoring §  PriorityAlarm Classification§  Disturbancerecord uploading facility with fault analysis§  Storageand Archiving Facility via Event list Archiving §  UserAdministration -Password Authorization for various user levels.§  GPSTime Synchronization§  HelpButton§   LEVEL 3 -CONTROl CENTER SCADA LEVEL At this level critical signals as per approved SCADAsignal list will be sent to Control Centre for necessary control and monitoringat SCADA or Load Dispatch Center.

Linkup from station controller via IEC60870-5-104 protocol a tele control ethernet based protocol will be provided upto dedicated redundant channel interface. This connection will allow for eitherAutomatic (in case of station controller failure) or manual control centeroperator selected switchover if required. Future protocol between substation and controlcenter shall be IEC 61850 and further research is ongoing to achieve the same.

 1.4 Process BUS Due to the technological advancement, a new addon tohierarchy level in communication arrived which is called process bus wherethere is no hardwiring CT and VT measurement and signals required at IED leveland the same shall be communicable via merger unit which can be integrated toIEDs on IEC 61850 protocol. All CT, VT wiring shall be done at switchgear levelitself to the merger unit which an integral part of switchgear. Fiber Opticpatch chords are used to communicate to IEDs (Bay Control Units and Protectionrelays) and Station bus. The below figure (X)show the difference in CT VThardwire connection and introduction of Process bus communication.  Figure (X) Process Bus Due to the above implementation from the process busto the station bus the information exchange is completely in digital form andhence these substations are called as digital substation. Merger units with smart communication ports and itsconnectivity to IEDs form the process bus.

These Station bus and process bus initiatingthe information exchange form process to station is called as digitalsubstation.  The whole communication network is fully on ethernetand digitalization leads to speed and scaling possible at same time. All theseadvancements are happening due to introduction of IEC Communication standardcalled IEC 61850. Our Hierachy level of information exchange is now adapted asbelow figure X   Figure (X) Hierarchy levels for Information Exchangeof Digital Substation   1.5 IEC 61850 STANDARD   IEC 61850 is a standard developed by InternationalElectro Techno Technical Commission and these standards are followed worldwidefor power transmission and distribution.

The arrival of standard open doors forbelow advantages in substation Automation §  ModularHardware.§  Variablesystem topologies like Ring Topology, Star Topology etc.§  Parallelprocessing of services.

§  HighInteroperability.§  StandardizedEngineering. §  EfficientService concepts. §  DisturbanceFault Retrieval through IEDs.§  RemoteParameterization of IEDs via Ethernet network.§  Interchangeability The Ethernet system interfaces for IEDs as shown infigure 3 enable a retroactive free communication independent of protectivefunctions and control functions. Electrical or Fiber Optic port modules areavailable, and relays can be ordered depending on the client requirement anddistance limitation.

                        Figure 3:Communication Port Modules for IEC 61850 in a Protection Relay.  Interoperability is an important feature whichallows exchange of information between IEDs of same vendor or different vendor.Interchangeability is the ability to replace a device supplied by onemanufacturer with a device supplied by another manufacturer without makingchanges to the other elements in the system. However, Interchangeability isbeyond this communication standard but always possible with this type ofEthernet network. 1.6 MAJOR COMPONENTS OF SUBSTATIONAUTOMATION  The major components typically used in a substation for informationexchange is as below §  RemoteTerminal Units.

§  HumanMachine Interface-Industrial PCs.§  EthernetSwitches -Layer 2/Layer 3.§  IntelligentElectronic Devices.   In addition to the main equipments Communication patch chords, printers, GPSAntenna, media converters also form part of substation Automation system.       Remote terminal units(rtu)                                  Remote TerminalUnits act as a data concentrator for data from process level and IED Level.Kernel based architecture exists in RTU with an embedded operating system.

Plugin communication and IO modules is used for easy maintenance, scaling andexpandability. The below figure x is a typical RTU which a rack based feature.              FigureX: Typical Remote Terminal Unit.  Human MACHINE INTERFACE INDUSTRIAL PC(HMI PC)                      Atypical substation automation system consists of an operator workstation andengineering workstation as a part of Human machine interface. These pcs act asan interface to the maintenance operator in substation for control andmonitoring realization. All graphical representations are configured in thesePCs.These PCs are normally industry grade handling high working temperature(approximately 55degree Celsius) and redundant raid configurations andredundant power supply units. All substation archives shall be stored in thisHMI PCs.

  The below figure (X) is aphysical representation of an Industrial PCs with front and rear view.             FigureX: Typical Industrial PCs Ethernet switch Ethernet switches form the communication network of thestation bus where station level equipments such as HMI PCs and IEDs shallintegrate via this ethernet switches. Layer-2 switches are generally used forsubstation network and for exchange of data between dissimilar networks layer-3switches are required. These Layer-3 switches are called as routers. IntegratedRouters with firewall functionality is used for connection to control centersince control center is of different network with different IP address classand subnet. The below figure is a typical layer-2 ethernet switch havingmodular communication ports.

  Figure(X)Layer -2 Ethernet switchTheseswitches are IEC 61850 complaint and industrially hardened, fully managedspecifically designed to operate reliably in electrically harsh and climaticallydemanding utility substation and industrial environments. These rugged hardwaredesign provides improved system reliability and advanced networking features ofEthernet. INtelligent iec 61850 ied Baycontrol Units, Protection IEDs, Multifunction Meters, Fault Recorders arecalled as IEDs – Intelligent Electronic Devices which can transfer data as softsignal to station level controllers. Bay Control Units are smart IEDs withgraphical display of individual feeder/bays having the alarms, measurement and statusof device representation of primary devices and operation of the primarydevices like circuit breaker and Isolator of the particular bay is possiblethrough Bay control units. Authority between bay control units and substationstation controller shall be possible via local/remote keys present in the BCUs.The below figure (X) is a typical siemens make bay control unit   Figure(X)Typical Intelligent Electronic Device-Bay Control Unit. Featuresof a Typical Bay Control Unit include: ProgrammingInterface and Function Chart ApplicationSoftwareand key switch security mechanismCalculationof Metering dataCollectionof Maintenance dataComprehensivedigital fault recording capabilitiesLCDdisplay providing local control and monitoring of bayUserdefinable function keysLANCommunication protocol over Fiber optic or electrical mediaSynchrocheck function Backupif main HMI failure occurs at station level.

    CYBER THREATS & RISKS Thoughtechnology is in advanced mode, at the same related cyber risks and hackingincidents are happening throughout the globe. The most publishedvulnerabilities in critical infrastructure are in the Energy area. Thefigure(X) below depicts ICS-CERT responses to sector specific cyber securitythreats across the critical infrastructure sectors in the U.S in 2014. Figure (X) Cyber Securityreported incidents in U.S CYBER security It is important that all data transmitted and received areto be in a secured and environment. Awareness and understanding of cyber securityshould be at all levels starting from product level, Solution level and atoperational level. All Communicable products should supportConfidentiality-Integrity-Availability(CIA) criteria and comply to Industrialstandard.

 The Key standards to be complied are as below           IEC 62443(System Security)          IEC62351(Communication Security)                 IS0 27001 (Security Management)  Cybersecurityprocesses should cover the whole product life-cycle and to foster solution andoperational requirements.       CONCLUSIONS IEC 61850 standard provides a uniform method ofcommunication and integration in substation in an interoperable manner amongmulti-vendor IEDs used for bay control, protection, metering and fault recordapplications. This standard addresses the migration to digital substation withthe definition of process bus. Research discussions are on board for controlcenter communication on IEC 61850 which gives the universal choice of protocolfor substations Automation in Utilities and Electrical Industrial sectors.These digitalization in substation is clearly a future driver for energy world.  FUTURE SCOPE OF WORK In addition to Digitalization as key future driver forenergy world, my research study will continue for other drivers such asDecarbonization and Decentralization. Renewable Energy is a vital part ofdecreasing global carbon foot prints and the investment pace has greatlyimproved as the cost of these technologies drop down and efficiency levelcontinue to rise.

This clearly shows that Decarbonization play a vital role asa future driver in energy world.  Due to effect of Distributed generation, DistributionAutomation and Technology advancement in Internet of Things and Cloud computingwill result in decentralization architecture of Information exchange from theIEDs directly to server via Internet and Cloud. In this context undoubtedly,Decentralization shall also be a future driver for energy world. A detailed study in Decentralization and Decarbonizationshall be my future scope of work.                 List of figures                                                  REFERENCES 1Roy E Cosse, Harrison T Combs, Martyn A.

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Monitoring andControl of Medium Voltage Power systems”, IEEE Paper No. 0-7803-7771-0/03  4 TarlochanS Sidhu, Mital Kumar G. Kanabar and Palak.P Parikh, (2008),” Implementation Issues withIEC 61850 Based Substation Automation Systems” Fifteenth national power systemsconference(NPSC), IIT Bombay 5 DavidC. Mazur, Joseph Sottile and Thomas Novak (March/April 2015) “An ElectricalMine Monitoring System Utilizing the IEC 61850 Standard” IEEE Transactions onIndustry Applications, Vol.51NO.

2 6 K.P Brand, C. brunner and W. Wimmer. (2004)”Design of IEC 61850 based substationAutomation systems according to customer requirements” CIGRE session 2004,reference B5-103