guidelines for the submission of the final paper

CIRED

20th International Conference on Electricity Distribution

Prague, 8-11 June 2009 Paper 0912

ELECTRIC GRID VERSUS DATA NETWORK ARCHITECTURES AND STANDARDS SMARTGRID AS PLUG&PLAY Jorge SANTOS EDP Distribuição – Portugal [email protected]

Nuno SILVA EFACEC Engenharia SA – Portugal [email protected]

Paulo RODRIGUES EFACEC Engenharia SA – Portugal [email protected]

Alberto RODRIGUES EFACEC Engenharia SA – Portugal [email protected]

Dave MARSH EFACEC Engenharia SA – Portugal [email protected]

Fernando GOMES EFACEC Engenharia SA – Portugal [email protected]

Carlos MOTA PINTO EDP Distribuição – Portugal [email protected]

Aurélio BLANQUET António CARRAPATOSO EDP Distribuição SA – Portugal EFACEC Engenharia SA – Portugal [email protected] [email protected] operations, new services exploitation, renewable and microgeneration integration, and others. ABSTRACT The system should be seen as a whole. A utility-wide, twoSmartGrid is the natural evolution for the control and way data communications network connects customers, optimization of electric grid operation, improving quality of distributed resources and field devices with the enterprise service and reducing costs. systems [3]. On the consumer/producer level smart meters The implementation of the SmartGrid means evolving the record load and generation profiles in real time, at the SCADA and DMS systems from systems that aid humans in Distribution Substation the Distribution Transformer the management of the power network to intelligent semiController (DTC) is introduced and in the HV/MV autonomous systems with a reduced human element. transformation level the Substation Automation Systems The introduction of Distributed Energy Resources (DER) (SAS) complement the existing SCADA equipment. The and Demand Response (DR) are changing the character of central systems continue to provide the global view and the electrical network managed by the new systems. control for all commercial and technical activities, but now Consumers pass from clients to active agents, contributing with more data of a higher quality than in the past, effective interactively [1] to network management and thus Quality control and a more efficient power network at all levels. of Service (QoS). This paper indicates how the new systems must use selfSCADA AS AN INFORMATION SERVICE describing equipment, standardised data models and protocols, must integrate with other corporate systems as To process and analyse this myriad of information, central both information vendors and purchasers, to achieve these systems provide the necessary intelligence to support grid while maintaining high data quality with acceptable costs of management and operation. Systems integration enables data capture and maintenance coordinated decision making and operations and enhances the overall operational efficiency and system reliability. As the system complexity increases and many actors INTRODUCTION produce and consume power simultaneously, traditional Today’s electric infrastructure context provides a golden SCADA is inadequate to handle, let alone optimize, all opportunity to replace ageing assets with new and improved possible combinations of power production and ones, together with a carefully planned communications consumption [4]. network and information systems. The growing concern This paper recognizes a trend implicit in SmartGrids where with climate change, the increasing demand for higher the controlling system adapts itself to the controlled electric reliability and security levels, the need to operate the network. SCADA and other systems for the first time act as network in a more efficient way and the penetration of one and extend over the entire network, from generation to renewable and microgeneration opens the door for the client. Control and automation functions are no longer creation of SmartGrids. limited to control centres and appear throughout the The large scale deployment of communications and network. automation is changing the passive distribution network into The bridge between Supervisory Control And Data an active SmartGrid where all manoeuvres can be Acquisition (SCADA) components, Energy Data monitored and remotely operated. Management (EDM) applications and other enterprise The expected growth in DER will significantly affect the systems is made at all levels, from control centre through to operation and control of today’s distribution system [2]. lower levels. The result is an optimal network management, New innovative and integrated solutions are crucial for the enhanced reliability and QoS, opportunities for Demand improvement of end-use energy efficiency, demand side Side Management (DSM) and Demand Response (DR). participation, support for life-cycle remote contractual

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Central management, energy data and SCADA/DMS systems will guarantee the dispatching orders and data collection activities – measurements, notifications and alarms from devices, network monitoring and potential fraud detection, etc. Subsequently, integration with existing and new Meter Data Management (MDM) and EDM applications will provide services improvement for market activities, energy balance for network losses characterization, optimal network operation and reconfiguration strategies, outage management, DER management and planning, protection and coordination,

fault detection and analysis, system stability, optimal maintenance strategies (validation of day-ahead schedules) so that operational costs are minimised and reliability and system stability is increased. In order to achieve overall optimization, a full integration of central systems such as SCADA/DMS, Energy Management Systems (EMS), Distribution Automation, Outage Management System (OMS), Geographic Information System (GIS), Meter Data Management (MDM), Asset Management System (AMS), and Customer Information System (CIS) should be maintained.

Figure 1: Parallel architecture of the communications system and the electrical distribution network infrastructure.

DISTRIBUTION AUTOMATION On the Prosumer premises the smart meter enables accurate registration of load/generation profiles in real time, reducing billing costs, detecting fraud, providing energy balance opportunities and allowing the customer to actively manage his energy behaviour. Some of this data is stored and uploaded later on to central systems. Other data is sent in real time or on request to central systems where it is essential to DR. At the Distribution Substation the DTC additionally clusters the attached meters, manage Public Lighting and can monitor and control local components. It will be responsible for collecting information from the Prosumer devices, process some of that and send it upward. It will also receive information from central systems and distribute it amongst Prosumer devices. It enables optimal local network

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operation based on constantly updated distribution system parameters optimising energy flows. The local network topology is thus controlled locally, including the adoption of self-healing algorithms. These autonomous functions will need to communicate with the centre to provide the information needed to operate the network in an optimal way, offering in new control capabilities to the Distribution Network Operator (DNO) that improve reliability, quality of supply and optimise network operation while supporting distributed generation. The Primary Substation, using intelligent algorithms, can optimise energy flows, network topology and offer selfhealing algorithms. Additional functions here may encompass the management of DR orders, energy flow, the control of DER, of microgeneration, grid optimisation, etc. Where nowadays Remote Terminal Units (RTU) resident at

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this level just communicate upwards with SCADA systems, the IEC standard goals already cover the communication between RTUs at the same level from different substations and this will expand to include standard protocols to communicate down to the DTCs. With the protocols established the processes and algorithms to run in concert in these devices may be developed. The Control Centre systems provide the global view over all these devices, operating over the active distribution network. At the moment, Control Centre and SCADA systems are the most favourable systems to implement and test the new SmartGrid algorithms, having all the information, further it will be easier to develop and test algorithms running here than repeatedly upgrade hundreds of substation RTUs. Once the algorithms are tested in the centralized architectures, the time will come to choose the algorithms to decentralize, to distribute, to Primary or Distribution Substation level systems, SAS and DTC. Information and Communication Technologies (ICT) and standardisation will be fundamental here, since cost, simplicity, openness and overall systems compatibility are major concerns.

DEMAND RESPONSE The present electricity grid is designed based on a vertically integrated supply model using dispatchable centralized generation and distributed consumption with little or no dispersed generation resources. The SmartGrid will need to accommodate more intermittent and decentralised generation and support bi-directional power flows, continuing to guarantee the energy supply from other sources when local microgeneration or DER fails. Consumers, suppliers and other market actors will have a much more active role in managing the network in the future. To improve the supply quality it is not difficult to envision an increase in demand side management and demand side bidding approaches, coupled with the introduction of distributed generation based voltage control. This active distribution grid will require a high degree of automation to ensure the reliability and quality of the power supply. Coordinated voltage and VAr control, automated switching and relay coordination and extensive monitoring will be a necessity. The network will be interactive for both power generation and consumption. The tools here include in-home automation, smart metering, the communications infrastructure and microgeneration. Demand side management will play a key role in establishing new services that will create value for the parties involved through responsive loads, load shifting, load shedding or peak shaving algorithms. The information network will bring together the diverse data needed to manage generating and demand resources present on the distribution network while maintaining power quality and respecting commercial agreements with the customer.

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NETWORK MANAGEMENT With the continuous expansion of Distribution Automation and more notably with the SmartGrid concept advance, the electrical utilities face the challenge of managing the exponential increase in the number of intelligent devices and subsystems that support utility operations. This technical infrastructure is distributed and geographically dispersed and includes a wide spectrum of heterogeneous equipment such as ancillary devices in electrical installations, traditional RTUs, Intelligent Electronic Devices (IED), Digital Protection, Smart Meters, LAN/WAN communications equipment, and sophisticated computer subsystems at the Control Centre level. This environment requires a management similar to the electrical network capable of handling large volumes of data, equipment maintenance and also the additional management of the smart devices configuration. Taking in account these considerations the current trend within the utility organization is to evolve network operations and technical management into autonomous / collaborative systems and staff providing a more clear responsibility and role of each one. Reducing the configuration burden of the technical management system is also an important issue and as much as possible equipment auto-discovery mechanisms should be supported.

CONFIGURATION BY PLUG AND PLAY The goal here is to use the natural alignment of the electrical system to be monitored and controlled with the emerging monitoring infrastructure to reduce the overall cost of maintaining the models of the monitored system. In previous generations of SCADA it was not unknown for the user to define a given measurement in more than one of the locations through which it passed, the RTU, Front-End, SCADA, energy applications. Even when the system was user-friendly a centralized monolithic approach to this data management or mapping between one domain and another would make the process more complicated than necessary. The emerging system will of course start from this position, with existing equipment, ranging from highly 'individual' equipment in the HV installations to pattern MV/LV equipment, all or nearly all telemetered by conventional RTU's configured manually. With the addition of selfcontained, self described, equipment (IED's, DTC's) with their several aspects described independently and coherently through an editor designed for that equipment, the central system should now be acquiring the new equipment data for connection into the central SCADA/DMS database, absorbing the telemetry configuration, electrical characteristics and default limits from 'below'. Some aspects will be of interest only locally to the equipment, others will be of interest to other parts of the enterprise. Let us consider the definition of the new self described equipment. The electrical characteristics for integrated Page 3 / 4

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equipment may already be present, with the 'local' telemetry identities (logical addresses) also defined. Thus a minimum configuration would need only to identify the location of the equipment in the network (name and description) to complete the local definition. Connecting the equipment into the network model can be aided by the geographical location, captured at site installation, manually orienting the device to connect it to the power lines and adjacent equipment. Descriptions can now be automatically generated to identify the switches and controls as "Switch in installation 1 towards installation 2". As a result of this integration into the central model, the value-added information can now be returned to the new equipment in the field. Now a pole-top switch controlled locally, at the substation or centrally presents the same description and information consistently and without redundant data input, including for example the location of priority clients. We can expect the SCADA/DMS editor to thus evolve to be an integration tool as much as an editor, supporting the editing and importation of network and equipment information and its management in versions. This central editor can offer networked access to the specific equipment type editors, offering centralized data capture with tools specific to the equipment. Where the equipment already exists in the network model and only an update to the configuration occurs, the new information may enter into the system with no further manual intervention, dependent on the company procedures adopted. This data interchange will only be possible with the support offered by existing and emerging standards. To extend this paradigm to existing equipment or the markedly individual HV equipment the continued use of templates for equipment types, advanced graphical editing procedures and integration with other enterprise systems will reduce the cost of data capture and maintenance across the board. The central editor assumes the role of integration and connection in preference to a 'one by one' data point capture. For example, this editor will be able to fetch by web service the configuration of a field equipment to incorporate in a new version of the system model. Note that this evolution will be facilitated by the identification of versions of the equipment definition, separate for each aspect as appropriate, an update request identifying conflicts based on this version information.

STANDARDS The IEC, namely the TC57, responsible for communications for electrical utilities, is aware of the importance of the medium voltage network for the management of the entire network. Such importance can be highlighted by the proposal of a New Work Item associated with “Communication Systems for Distribution Feeder and Network Equipments”. This new standard will incorporate information models associated with distribution feeder and network equipment in the IEC61850 standard that initially defined information models for transmission and

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distribution substations, and later expanded its role to hydro power plants and DER [5-6]. The usage of standard protocols and models, from the beginning of the deployment of devices in the MV network will enable a high level of interoperability among the IED, avoiding the repetition of the situations that occurred in the sixties and seventies when SCADA systems using proprietary protocols and data models were deployed.

CONCLUSION Matching the controlling data system model to the controlled electric system, applying and extending existing standards, will reduce configuration costs and raise data quality. Only data standards and an imaginative approach to the management of the information involved can solve the problem. The result will lead us towards “Plug & Play” and self-described equipments in the Electrical Network controlling components. Autonomous and Collaborative systems will be fundamental to implement DR programs and integrate DER all over the electric grid. SCADA systems will have a fundamental role in the implementation of the new algorithms, permitting development and testing before passing them through to the distributed control system. A large scale SmartGrid project will impact many utility systems and processes spanning customer services through system operations, planning, engineering and field operations, integrating all systems into one complete system.

REFERENCES [1] J. Santos, A. de Almeida, 2005, “Concepts For SCADA Systems Planning In A Changing Competitive Environment”, CIRED - 18th International Conference on Electricity Distribution, Turin, Italy, Paper 352. [2] P. Djapic, C. Ramsay, D. Pudjianto, G. Strbac, J. Mutale, N. Jenkins, R. Allan, 2007, "Taking an active approach", IEEE Power and Energy Magazine, vol. 5, issue 4, 68-77 [3] R. C. Sonderegger, 2001, "Distributed Generation Architecture and Control", Department of Energy, RAND, 292-301 [4] J. Jimeno, L. Laresgoiti, J. Oyarzabal, B. Stene, R. Bacher, 2003, "Architectural Framework for the Integration of Distributed Resources", IEEE Bologna PowerTech Conference, 292-301 [5] "Communication networks and systems for power utility automation – Part 7 – 410: Hydroelectric power plants – Communications for monitoring and control", International Electrotechnical Comission, 2007. [6] "Communication networks and systems for power utility automation – Part 7 - 420: Basic communication structure – Distributed energy resources logical nodes", International Electrotechnical Comission, 2008. Page 4 / 4