An Introduction To SCADA For Electrical Engineers BeginnersPostedJUN 19 2013byBIPUL RAMANinAUTOMATION,SCADAwith29 COMMENTS

An Introduction To SCADA (Supervisory Control And Data Acquisition) For Beginners // On photo Monitor iFIX By ServiTecno via FlickRControl and SupervisionIt is impossible to keep control and supervision on all industrial activities manually. Some automated tool is required which can control, supervise, collect data, analyses data and generate reports. A unique solution is introduced to meet all this demand isSCADA system.SCADA stands for supervisory control and data acquisition.It is an industrial control system where a computer system monitoring and controlling a process.Another term is there,Distributed Control System (DCS). Usually there is a confusion between the concept of these two.A SCADA system usually refers to a system thatcoordinates,but does not control processes in real time, but DCS do that. SCADA systems often have Distributed Control System (DCS) components.

Components of SCADA1. Human Machine Interface (HMI)It is an interface which presentsprocess data to a human operator, and through this, the human operator monitors and controls the process.2. Supervisory (computer) systemIt gathers data on the process and sending commands (or control) to the process.3. Remote Terminal Units (RTUs)It connects to sensors in the process, converting sensor signals to digital data and sending digital data to the supervisory system.4. Programmable Logic Controller (PLCs)It is used as field devices because they are more economical, versatile, flexible, and configurable than special-purpose RTUs.5. Communication infrastructureIt provides connectivity to the supervisory system to the Remote Terminal Units.

SCADA System ConceptThe term SCADAusually refers to centralized systems which monitor and control entire sites, or complexes of systems spread out over large areas (anything between an industrial plant and a country).Most control actions are performed automatically byRemote Terminal Units (RTUs)or byprogrammable logic controllers (PLCs).Host control functionsare usually restricted to basic overriding or supervisory level intervention. For example, a PLC may control the flow of cooling water through part of an industrial process, buttheSCADA system may allow operators to change the set points for the flow, and enable alarm conditions, such as loss of flow and high temperature, to be displayed and recorded.The feedback control loop passes through the RTU or PLC, while the SCADA system monitors the overall performance of the loop.

A simple SCADA system with single computer

Three generations of SCADA system architecturesPostedAPR 22 2013byEDVARDinAUTOMATION,MONITORING,SCADAwith4 COMMENTS

Institute 'Mihailo Pupin' - Third generation of Control and Data Acquisition (SCADA) Systems and Digital Control Systems (DCS) - On photo Distribution System of Elektrovojvodina, SerbiaGenerationsSCADA systemshave evolved in parallel with the growth and sophistication of moderncomputing technology.The following sections will provide a description of thefollowingthree generations of SCADA systems:1. First Generation Monolithic2. Second Generation Distributed3. Third Generation Networked-Waste Water Treatment Plant SCADA (VIDEO)

1. Monolithic SCADA SystemsWhen SCADA systems were first developed, the concept of computing in generalcentered onmainframe systems. Networks were generally non-existent, and eachcentralized system stood alone.As a result, SCADA systems were standalone systemswith virtually no connectivity to other systems.TheWide Area Networks (WANs)that were implemented to communicate with remoteterminal units (RTUs)were designed with a single purpose in mindthat ofcommunicating with RTUs in the field and nothing else. In addition, WAN protocols inuse today were largely unknown at the time.The communication protocols in use on SCADA networks were developed by vendors ofRTU equipment and were often proprietary.In addition, these protocols weregenerallyvery lean, supporting virtually no functionality beyond that required scanning andcontrolling points within the remote device. Also, it was generally not feasible tointermingle other types of data traffic with RTU communications on the network.Connectivity to the SCADA master station itself was very limited by the system vendor.Connections to the master typically were done at the bus level via a proprietary adapter orcontroller plugged into theCentral Processing Unit (CPU)backplane.Redundancy in these first generation systems was accomplished by the use of twoidentically equipped mainframe systems, a primary and a backup, connected at the buslevel.

Figure 1 - First Generation SCADA Architecture

The standby systems primary function was to monitor the primary and take over inthe event of a detected failure. This type of standby operation meant that little or noprocessing was done on the standby system.Figure 1shows a typical first generationSCADA architecture.Go to Content

2. Distributed SCADA SystemsThe next generation of SCADA systems took advantage of developments andimprovement in system miniaturizationandLocal Area Networking (LAN) technologyto distribute the processing across multiple systems.Multiple stations, each with a specificfunction, were connected to a LAN and shared information with each other in real-time.These stations were typically of themini-computer class,smallerandless expensivethantheir first generation processors.Some of these distributed stations served as communications processors, primarilycommunicating with field devices such as RTUs. Some served as operator interfaces,providing thehuman-machine interface (HMI)for system operators. Still others served ascalculation processors or database servers.

Remote terminal unit (RTU)The distribution ofindividual SCADA systemfunctions across multiple systems providedmore processing power for the systemas awholethan would have been available in a single processor. The networks that connectedthese individual systems were generally based on LAN protocols and were not capable ofreaching beyond the limits of the local environment.Some of the LAN protocols that were used were of a proprietary nature, where the vendorcreated its own network protocolor version thereof rather than pulling an existing one offthe shelf. This allowed a vendor to optimize its LAN protocol for real-time traffic,but itlimited (or effectively eliminated) the connection of network from other vendors to theSCADA LAN.Figure 2depictstypical second generation SCADA architecture.

Figure2 - Second Generation SCADA Architecture

Distribution of system functionality across network-connected systems served not only toincrease processing power, but alsoto improve the redundancy and reliability of thesystem as a whole. Rather than the simple primary/standby fail over scheme that wasutilized in many first generation systems, the distributed architecture often kept allstations on the LAN in an online state all of the time.For example, if an HMI stationwere to fail,another HMI station could be used to operate the system, without waiting forfail over from the primary system to the secondary.The WAN used to communicate with devices in the field were largely unchanged by thedevelopment of LAN connectivity between local stations at the SCADA master. Theseexternal communications networks were still limited to RTU protocols and were notavailable for other types of network traffic.As was the case with the first generation of systems,the second generation of SCADAsystems was also limited to hardware,software, andperipheral devicesthat wereprovided or at least selected by the vendor.Go to Content

3. Networked SCADA SystemsThe current generation of SCADA master station architecture is closely related to that ofthe second generation, with the primary difference being that of an open systemarchitecture rather than a vendor controlled, proprietary environment.There are stillmultiple networked systems, sharing masterstation functions. There are still RTUsutilizing protocols that are vendor-proprietary.The major improvement in the thirdgeneration is that ofopening the system architecture,utilizing open standards and protocolsand making it possible to distribute SCADA functionality across aWANandnot just aLAN.Open standards eliminate a number of the limitations of previous generations of SCADAsystems. The utilization of off-the-shelf systems makes it easier for the user to connectthird party peripheral devices (such as monitors, printers, disk drives, tape drives, etc.) tothe system and/or the network.As they have moved to open or off-the-shelf systems, SCADA vendors havegradually gotten out of the hardware development business. These vendors have lookedto system vendors such asCompaq,Hewlett-Packard, andSun Microsystemsfor theirexpertise in developing the basic computer platforms and operating system software.Thisallows SCADA vendors to concentrate their development in an area where they can addspecific value to the system that of SCADA master station software.The major improvement in third generation SCADA systems comes from the use ofWAN protocols such as theInternet Protocol (IP)for Communication between the masterstation and communications equipment. This allows the portion of the master station thatis responsible for communications with the field devices to be separated from the masterstation proper across a WAN.Vendors are now producing RTUs that cancommunicate with the master station using an Ethernet connection.Figure 3representsa networked SCADA system.

Figure 3 - Third Generation SCADA System

Another advantage brought about by the distribution of SCADA functionality over aWAN is that ofdisaster survivability. The distribution of SCADA processing across aLAN in second-generation systemsimproves reliability, but in the event of a total loss ofthe facility housing the SCADA master, the entire system could be lost as well.Bydistributing the processing across physically separate locations, it becomes possible tobuild a SCADA system that can survive a total loss of any one location.For someorganizations that see SCADA as a super-critical function, this is a real benefit.

SCADA As Heart Of Distribution Management SystemPostedDEC 25 2012byEDVARDinAUTOMATION,MONITORING,SCADAwith10 COMMENTS

SCADA The Heart Of Distribution Management System (DMS) - On photo: Fima UAB - Dedicated control systems and SCADA (Supervisory Control and Data Acquisition) as well as DMS (Distribution Management System) type of systems are offered for electricity, water and gas supply companies, as well as telecommunication operators and manufacturing companies.SCADA System ElementsAt a high level, the elements of a distribution automation system can be divided into three main areas:1. SCADAapplication and server(s)2. DMSapplications and server(s)3. Trouble management applications and server(s)

Distribution SCADAAs was stated in the title, theSupervisory Control And Data Acquisition (SCADA)system is the heart ofDistribution Management System (DMS) architecture.ASCADA systemshould have all of the infrastructure elements to support the multifaceted nature of distribution automation and the higher level applications of a DMS. A Distribution SCADA systems primary function is in support of distribution operations telemetry, alarming, event recording, and remote control of field equipment.Historically, SCADA systems have beennotorious for their lack of support for the import, and more importantly, the export of power system data values.A modern SCADA system should support the engineering budgeting and planning functions by providing access to power system data without having to have possession of an operational workstation.The main elements of a SCADA system are:1. Host equipment2. Communication infrastructure(network and serial communications)3. Field devices (in sufficient quantity to support operations and telemetry requirements of a DMSplatform)

Figure 1 - DA system architectureHost EquipmentThe essential elements of a distribution SCADA host are:1. Host servers (redundant servers with backup/failover capability).2. Communication front-end nodes(network based).3. Full graphics user interfaces.4. Relational database server (for archival of historical power system values) and data server/Webserver (for access to near real time values and events).The elements and components of the typical distribution automation system are illustrated inFigure 1above.

Host Computer SystemSCADA ServersAs SCADA has proven its value in operation during inclement weather conditions, service restoration, and daily operations, the dependency on SCADA has created a requirement forhighly available and high performance systems. Redundant server hardware operating in a live backup/failover mode is required to meet the high availability criteria.High-performance servers withabundant physical memory,RAID hard disk systems, andinterconnected by 10/100 baseT switched Ethernetare typical of todays SCADA servers.

Communication Front-End (CFE) ProcessorsThe current state of host to field device communications still depends heavily on serial communications.This requirement is filled by the CFE. The CFE can come in several forms based on bus architecture (e.g., VME or PCI) and operating system. Location of the CFE in relation to the SCADA servercan vary based on requirement. In some configurations the CFE is located on the LAN with the SCADA server. In other cases, existing communications hubs may dictate that the CFE reside at the communication hub.The incorporation of the WAN into the architecture requires a more robust CFE application to compensate for less reliable communications (in comparison to LAN).In general the CFE will include three functional devices:1. A network/CPU board,2. Serial cards, and3. Possibly a time code receiver.Functionality should include the ability to download configuration and scan tables. The CFE should also support the ability to dead band values (i.e., report only those analog values that have changed by a user-defined amount).CFE, network, and SCADA serversshould be capable of supporting worst-case conditions(i.e., all points changing outside of the dead band limits), which typically occur during severe system disturbances.

Full Graphics User InterfaceThe current trend in theuser interface (UI)is toward afull graphics (FG) user interface. While character graphics consoles are still in use by many utilities today, SCADA vendors are aggressively moving their platforms to a full graphics UI.Quite often the SCADA vendors have implemented their new full graphics user interface on low-cost NT workstations using third-party applications to emulate theX11 window system.

SCADA - Full graphic display using Video Wall

Full graphic displays provide the ability to displaypower system dataalong with the electric distribution facilities in a geographical (or semigeographical) perspective.The advantage of using a full graphics interface becomes evident (particularly for distribution utilities) as SCADA is deployed beyond the substation fence where feeder diagrams become critical to distribution operations.

Relational Databases, Data Servers, and Web ServersThe traditional SCADA systemswere poor providers of datato anyone not connected to the SCADAsystem by an operational console.This occurred due to the proprietary nature of the performance (inmemory) database and its design optimization for putting scanned data in and pushing display valuesout. Power system quantities such as: bank and feeder loading (MW, MWH, MQH, and ampere loading),and bus volts provide valuable information to the distribution planning engineer.The availability ofevent (log) datais important in postmortem analysis. The use of relational databases, data servers, andWeb servers by the corporate and engineering functions provides access to power system informationand data while isolating the SCADA server from nonoperations personnel.

Host to Field CommunicationsSerial communications to field devicescan occur over several mediums:copper wire,fiber,radio, and evensatellite. Telephone circuits, fiber, and satellites have a relatively high cost. New radio technologies offer good communications value.One such technology is theMultiple Address Radio System (MAS).The MAS operates in the 900 MHz range and is omnidirectional, providing radio coverage in an area with radius up to 2025 miles depending on terrain. A single MAS master radio can communicate with many remote sites. Protocol and bandwidth limit the number of remote terminal units that can be communicated with by a master radio. The protocol limit is simply the address range supported by the protocol.Bandwidth limitationscan be offset by the use of efficient protocols, or slowing down the scan rate to include more remote units. Spread-spectrum and point-to-point radio (in combination with MAS) offers an opportunity to address specific communication problems.At the present time MAS radio is preferred to packet radio (another new radio technology); MAS radio communications tend to be more deterministic providing for smaller timeout values on communication noresponses and controls.

Field DevicesDistribution Automation (DA) field devicesare multi-featured installations meeting a broad range of control, operations, planning, and system performance issues for the utility personnel.Each device provides specific functionality, supports system operations, includes fault detection, captures planning data and records power quality information. These devices are found in the distribution substation and at selected locations along the distribution line. The multi-featured capability of the DA device increases its ability to be integrated into the electric distribution system.The functionality and operations capabilitiescomplement each other with regard to the control and operation of the electric distribution system.The fault detection feature is the eyes and ears for the operating personnel. The fault detection capability becomes increasingly more useful with the penetration of DA devices on the distribution line.The real-time data collected by the SCADA system is provided to the planning engineers for inclusion in the radial distribution line studies. As the distribution system continues to grow, the utility makes annual investments to improve the electric distribution system to maintain adequate facilities to meet the increasing load requirements.The use of thereal-time datapermits the planning engineers to optimize the annual capital expenditures required to meet the growing needs of the electric distribution system.The power quality information includes capturing harmonic content to the 15th harmonic and recordingPercent Total Harmonic Distortion (%THD). This information is used to monitor the performance of the distribution electric system.

Modern RTUTodaysmodern RTUis modular in construction with advanced capabilities to support functions that heretofore were not included in the RTU design.Themodular designsupports installation configurations ranging from the small point count required for the distribution line pole-mounted units to the very large point count required for large bulk-power substations and power plant switchyard installations.

Modern RTU Scada

The modern RTU modules includeanalog units with 9 points,control units with 4 control pair points,status units with 16 points, andcommunication units with power supply.The RTU installation requirements are met by accumulating the necessary number of modern RTU modules to support the analog, control, status, and communication requirements for the site to be automated. Packaging of the minimum point count RTUs is available for the distribution line requirement.Thesubstation automation requirementhas the option of installing the traditional RTU in one cabinet with connections to the substationdevices or distributing the RTU modules at the devices within the substation with fiberoptic communications between the modules.The distributed RTU modules are connected to a data concentrating unit which in turn communicates with the host SCADA computer system.The modern RTU acceptsdirect AC inputsfrom a variety of measurement devices including line-post sensors, current transformers, potential transformers, station service transformers, and transducers. Direct AC inputs with the processing capability in the modern RTU supports fault current detection and harmonic content measurements.The modern RTU has the capability to report the magnitude, direction, and duration of fault current with time tagging of the fault event to 1-millisecond resolution. Monitoring and reporting of harmonic content in the distribution electric circuit are capabilities that are included in the modern RTU.Thedigital signal processing capability of the modern RTUsupports the necessary calculations to report %THD for each voltage and current measurement at the automated distribution line or substation site.The modern RTU includes logic capability to support the creation of algorithms to meet specific operating needs.Automatic transfer schemeshave been built using automated switches and modern RTUs with the logic capability. This capability provides another option to the distribution line engineer when developing the method of service and addressing critical load concerns.The logic capability in the modern RTU has been used to create the algorithm to control distribution line switched capacitors for operation on a per phase basis. The capacitors are switched on at zero voltage crossing and switched off at zero current crossing.The algorithm can be designed to switch the capacitors for various system parameters, such as voltage, reactive load, time, etc. The remote control capability of the modern RTU then allows the system operator to take control of the capacitors to meet system reactive load needs.The modern RTU has become a dynamic device with increased capabilities. The new logic and input capabilities are being exploited to expand the uses and applications of the modern RTU.

PLCs and IEDsProgrammable Logic Controller (PLC)andIntelligent Electronic Device (IED)are components of the distribution automation system, which meet specific operating and data gathering requirements.

PLC SCADA Panel

While there is some overlap in capability with the modern RTU, the authors are familiar with the use ofPLCs for automatic isolation of the faulted power transformer in a two-bank substation and automatictransfer of load to the unfaulted power transformer to maintain an increased degree of reliability.ThePLC communicates with the modern RTU in the substation to facilitate the remote operation of thesubstation facility.The typical PLC can support serial communications to a SCADA server. The modernRTU has the capability to communicate via an RS-232 interface with the PLC.IEDs include electronic meters, electronic relays, and controls on specific substation equipment, suchas breakers, regulators, LTC on power transformers, etc.The IEDs also have the capability to supportserial communicationsto a SCADA server. However, the authors experience indicates that the IEDs aretypically reporting to the modern RTU via anRS-232 interfaceor via status output contact points.Asits communicating capability improves and achieves equal status with the functionality capability, theIED has the potential to become an equal player in the automation communication environment.However, in the opinion of the authors, the limited processing capability for supporting the communicationrequirement, in addition to its functional requirements (i.e., relays, meters, etc.), hampers thewidespread use of the IEDs in the distribution automation system.Resource:Power System Operation and Control -George L. Clark and Simon W. Bowen