Missouri Kansas Ch 3 Smart Grid Infrastructure Technology and Solutions Questions

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Question-1 [10 Points]

What is the threshold level of renewable energy penetration (in percentage) at which the utilities are required to change their engineering and planning strategies?

Question-2 [20 Points]

Enumerate the impacts of large scale renewable penetration on the U.S transmission grid.

Question-3 [40 Points]

During the periods of high penetration, wind and solar energy have to be curtailed. What is the reason for doing this? Provide practical examples.

Question-4 [20 Points]

State the applications of energy storage for integrating intermittent renewable energy sources into the power system.

Question-5 [50 Points]

Write a one page summary on “spinning reserves”. Your description should include the applications and examples of spinning reserves.

Question-6 [50 Points]

Do some independent research and write a short report on the impact of plug-in hybrid electric vehicles on the distribution network.

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Mini S. Thomas Jamia Millia Islamia University New Delhi, India John D. McDonald GE Energy Management - Digital Energy Atlanta, Georgia, USA Boca Raton London New York CRC Press is an imprint of the Taylor & Francis Group, an informa business CRC Press Taylor & Francis Group 6000 Broken Sound Parkway NW, Suite 300 Boca Raton, FL 33487-2742 © 2015 by Taylor & Francis Group, LLC CRC Press is an imprint of Taylor & Francis Group, an Informa business No claim to original U.S. Government works Version Date: 20150203 International Standard Book Number-13: 978-1-4822-2675-1 (eBook - PDF) This book contains information obtained from authentic and highly regarded sources. Reasonable efforts have been made to publish reliable data and information, but the author and publisher cannot assume responsibility for the validity of all materials or the consequences of their use. 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CCC is a not-for-profit organization that provides licenses and registration for a variety of users. For organizations that have been granted a photocopy license by the CCC, a separate system of payment has been arranged. Trademark Notice: Product or corporate names may be trademarks or registered trademarks, and are used only for identification and explanation without intent to infringe. Visit the Taylor & Francis Web site at http://www.taylorandfrancis.com and the CRC Press Web site at http://www.crcpress.com Contents Preface.............................................................................................................. xvii The authors.......................................................................................................xix Chapter 1 Power system automation.......................................................... 1 1.1 Introduction............................................................................................... 1 1.2 Evolution of automation systems........................................................... 2 1.2.1 History of automation systems................................................. 3 1.3 Supervisory control and data acquisition (SCADA) systems......................................................................................... 4 1.3.1 Components of SCADA systems.............................................. 5 1.3.2 SCADA applications................................................................... 6 1.4 SCADA in power systems....................................................................... 7 1.4.1 SCADA basic functions.............................................................. 7 1.4.2 SCADA application functions................................................... 7 1.4.2.1 Generation SCADA application functions............. 8 1.4.2.2 Transmission SCADA application functions......... 9 1.4.2.3 Distribution automation application functions..... 9 1.5 Advantages of SCADA in power systems........................................... 10 1.5.1 Deferred capital expenditure.................................................. 10 1.5.2 Optimized operation and maintenance costs...................... 11 1.5.3 Equipment condition monitoring (ECM).............................. 11 1.5.4 Sequence of events (SOE) recording...................................... 11 1.5.5 Power quality improvement................................................... 11 1.5.6 Data warehousing for power utilities.................................... 12 1.6 Power system field.................................................................................. 12 1.6.1 Transmission and distribution systems................................ 12 1.6.2 Customer premises................................................................... 14 1.6.3 Types of data and signals in power system.......................... 14 1.6.3.1 Analog signals.......................................................... 14 1.6.3.2 Data acquisition systems........................................ 15 1.6.3.3 Digital signals........................................................... 16 1.6.3.4 Pulse signals............................................................. 17 v vi Contents 1.7 Flow of data from the field to the SCADA control center................. 17 1.8 Organization of the book....................................................................... 18 1.9 Summary................................................................................................. 19 Bibliography....................................................................................................... 19 Chapter 2 SCADA fundamentals.............................................................. 21 2.1 Introduction............................................................................................. 21 2.2 Open system: Need and advantages................................................... 21 2.3 Building blocks of SCADA systems..................................................... 22 2.4 Remote terminal unit (RTU)................................................................. 24 2.4.1 Evolution of RTUs..................................................................... 24 2.4.2 Components of RTU................................................................. 25 2.4.3 Communication subsystem..................................................... 26 2.4.3.1 Communication protocols...................................... 27 2.4.3.2 Message security...................................................... 27 2.4.3.3 Multi-­port communication..................................... 27 2.4.4 Logic subsystem........................................................................ 27 2.4.4.1 Time keeping............................................................ 28 2.4.4.2 Data acquisition and processing............................ 28 2.4.4.3 Digital data acquisition........................................... 28 2.4.4.4 Analog data acquisition.......................................... 29 2.4.4.5 Analog outputs......................................................... 29 2.4.4.6 Digital (contact) output........................................... 29 2.4.4.7 Pulse inputs.............................................................. 30 2.4.4.8 Pulse outputs............................................................ 30 2.4.5 Termination subsystem............................................................ 30 2.4.5.1 Digital terminations................................................ 31 2.4.5.2 Analog terminations............................................... 31 2.4.6 Testing and human-­machine interface (HMI) subsystem.... 31 2.4.7 Power supplies.......................................................................... 32 2.4.8 Advanced RTU functionalities............................................... 32 2.4.8.1 Multi-­port and multi-­protocol operation.............. 33 2.4.8.2 Digital interface to other electronic devices......... 33 2.4.8.3 Closed-­loop control, computation, and optimization at the RTU level........................ 34 2.4.8.4 Interface to application functions.......................... 34 2.4.8.5 Advanced data processing..................................... 34 2.4.8.6 Other functions........................................................ 35 2.5 Intelligent electronic devices (IEDs).................................................... 35 2.5.1 Evolution of IEDs...................................................................... 35 2.5.2 IED functional block diagram................................................ 36 2.5.3 Hardware and software architecture of the IED................. 38 2.5.4 IED communication subsystem.............................................. 38 Contents 2.5.5 2.6 2.7 2.8 2.9 vii IED advanced functionalities.................................................. 40 2.5.5.1 Protection function including phasor estimation.................................................................. 40 2.5.5.2 Programmable logic and breaker control............. 42 2.5.5.3 Metering and power quality analysis................... 42 2.5.5.4 Self-­monitoring and external circuit monitoring................................................................ 44 2.5.5.5 Event reporting and fault diagnosis..................... 44 2.5.6 Tools for settings, commissioning, and testing.................... 45 2.5.7 Programmable LCD display................................................... 45 2.5.8 Typical IEDs............................................................................... 45 Data concentrators and merging units................................................ 46 2.6.1 RTUs, IEDs, and data concentrator........................................ 46 2.6.2 Merging units and IEDs.......................................................... 46 SCADA communication systems......................................................... 46 Master station.......................................................................................... 46 2.8.1 Master station software components..................................... 47 2.8.1.1 Basic SCADA software............................................ 47 2.8.1.2 Advanced SCADA application functions............. 48 2.8.2 Master station hardware components................................... 48 2.8.3 Server systems in the master station..................................... 48 2.8.3.1 SCADA server.......................................................... 49 2.8.3.2 Application server.................................................... 49 2.8.3.3 ISR or HIM server.................................................... 49 2.8.3.4 Development server................................................. 50 2.8.3.5 Network management server................................. 50 2.8.3.6 Video projection system.......................................... 50 2.8.3.7 CFE (communication front end) and FEP (front-­end processor)............................................... 50 2.8.3.8 ICCP server............................................................... 50 2.8.3.9 Dispatcher training simulator (DTS) server........ 51 2.8.4 Small, medium, and large master stations............................ 51 2.8.5 Global positioning systems (GPS).......................................... 52 2.8.6 Master station performance.................................................... 53 Human-­machine interface (HMI)........................................................ 54 2.9.1 HMI components...................................................................... 54 2.9.1.1 Operator console...................................................... 54 2.9.1.2 Operator dialogue.................................................... 55 2.9.1.3 Mimic diagram......................................................... 55 2.9.1.4 Peripheral devices.................................................... 55 2.9.2 HMI software functionalities................................................. 55 2.9.3 Situational awareness.............................................................. 56 2.9.4 Intelligent alarm filtering: Need and technique.................. 57 viii Contents 2.9.5 Alarm suppression techniques............................................... 58 2.9.5.1 Area of responsibility (AOR) alarm filtering....... 58 2.9.5.2 Alarm point priority filtering................................. 59 2.9.5.3 Timed alarm suppression....................................... 59 2.9.5.4 Knowledge-­based alarm suppression................... 60 2.9.6 Operator needs and requirements......................................... 61 2.10 Building the SCADA systems, legacy, hybrid, and new systems.... 62 2.11 Classification of SCADA systems......................................................... 62 2.11.1 Single master–­single remote................................................... 62 2.11.2 Single master–­multiple RTU................................................... 63 2.11.3 Multiple master–­multiple RTUs............................................. 63 2.11.4 Single master, multiple submaster, multiple remote........... 64 2.12 SCADA implementation: A laboratory model.................................... 65 2.12.1 The SCADA laboratory............................................................ 65 2.12.2 System hardware...................................................................... 66 2.12.3 System software........................................................................ 67 2.12.4 SCADA lab field design........................................................... 69 2.13 Case studies in SCADA......................................................................... 70 2.13.1 “Kentucky utility fires up its first SCADA system”............ 71 2.13.2 “Ketchikan Public Utilities finds solutions to outdated, proprietary RTUs”.................................................. 71 2.13.3 “Overwhelmed by alarms: The blackout puts filtering and suppression technologies in the spotlight”................... 71 2.13.4 “North Carolina Municipal Power Agency boosts revenue by replacing SCADA”................................................ 71 2.14 Summary................................................................................................. 72 Bibliography....................................................................................................... 72 Chapter 3 SCADA communication........................................................... 75 3.1 Introduction............................................................................................. 75 3.2 SCADA communication requirements................................................ 76 3.3 Smart grid communication infrastructure......................................... 76 3.3.1 Quality of services (QoS)......................................................... 78 3.3.2 Interoperability......................................................................... 78 3.3.3 Scalability................................................................................... 78 3.3.4 Security...................................................................................... 78 3.3.5 Standardization......................................................................... 79 3.4 SCADA communication topologies..................................................... 79 3.4.1 Point to point and multi-­drop................................................. 79 3.4.2 Bus topology.............................................................................. 80 3.4.3 Ring topology............................................................................ 80 3.4.4 Star topology............................................................................. 81 3.4.5 Mesh topology........................................................................... 81 3.4.6 Data flow: Simplex and duplex............................................... 81 Contents 3.5 3.6 3.7 3.8 3.9 ix SCADA data communication techniques........................................... 81 3.5.1 Master-­slave............................................................................... 81 3.5.2 Peer-to-peer............................................................................... 82 3.5.3 Multi-peer (broadcast and multicast).................................... 82 Data communication.............................................................................. 82 3.6.1 Components of a data communication system.................... 83 3.6.2 Transmission of digital signals............................................... 83 3.6.2.1 Baseband communication...................................... 83 3.6.2.2 Broadband communication.................................... 84 3.6.3 Modes of digital data communication........................................ 84 3.6.3.1 Synchronous data transmission............................ 84 3.6.3.2 Asynchronous data transmission.......................... 85 3.6.4 Error detection techniques...................................................... 85 3.6.4.1 Parity check.............................................................. 86 3.6.4.2 Checksum error detection...................................... 86 3.6.4.3 Cyclic redundancy check (CRC)............................ 86 3.6.5 Media access control (MAC) techniques............................... 87 3.6.5.1 Polling........................................................................ 87 3.6.5.2 Polling by exception................................................ 87 3.6.5.3 Token passing........................................................... 88 3.6.5.4 Time division multiplex media access.................. 88 3.6.5.5 Carrier sense multiple access with collision detection (CSMA/­CD)............................................. 88 SCADA communication protocol architecture.................................. 89 3.7.1 OSI seven-­layer model............................................................. 90 3.7.2 Enhanced performance architecture (EPA) model.............. 96 3.7.3 TCP/­IP model............................................................................ 98 Evolution of SCADA communication protocols............................... 100 SCADA and smart grid protocols...................................................... 101 3.9.1 Modbus.................................................................................... 101 3.9.1.1 Modbus message frame........................................ 101 3.9.2 IEC 60870-5-101/103/104........................................................ 102 3.9.2.1 Protocol architecture............................................. 103 3.9.2.2 IEC 60870 message structure................................ 104 3.9.3 Distributed network protocol 3 (DNP3).............................. 106 3.9.3.1 DNP3 protocol structure....................................... 106 3.9.3.2 DNP3 message structure...................................... 106 3.9.4 Inter-­control center protocol (ICCP)..................................... 107 3.9.5 Ethernet.................................................................................... 109 3.9.6 IEC 61850...................................................................................110 3.9.7 IEEE C37.118: Synchrophasor standard............................... 112 3.9.7.1 Measurement time tag from synchrophasor......113 3.9.7.2 Reporting rates........................................................113 3.9.7.3 Message structure...................................................113 x Contents 3.9.8 Wireless technologies for home automation.......................115 3.9.8.1 ZigBee.......................................................................115 3.9.8.2 ZigBee devices.........................................................115 3.9.8.3 Wi-­Fi..........................................................................116 3.9.9 Protocols in the power system: Deployed and evolving....116 3.10 Media for SCADA and smart grid communication.........................118 3.11 Guided media.........................................................................................118 3.11.1 Twisted pair..............................................................................118 3.11.2 Coaxial (coax) metallic cable..................................................119 3.11.3 Optical fiber............................................................................. 120 3.11.4 Power line carrier communication (PLCC)......................... 121 3.11.4.1 Power line carrier (PLC)........................................ 121 3.11.4.2 Distribution line carrier (DLC)............................ 121 3.11.4.3 Broadband over power lines (BPL)...................... 122 3.11.5 Telephone-­based systems...................................................... 122 3.11.5.1 Telephone lines: Dial-­up and leased................... 122 3.11.5.2 ISDN (integrated services digital network)........ 123 3.11.5.3 Digital subscriber loop (DSL)............................... 123 3.12 Unguided (wireless) media................................................................. 124 3.12.1 Satellite communication........................................................ 124 3.12.2 Radio (VHF, UHF, spread spectrum)................................... 124 3.12.3 Microwaves.............................................................................. 125 3.12.4 Cell phone................................................................................ 126 3.12.5 Paging....................................................................................... 126 3.13 Communication media: Utility owned versus leased..................... 127 3.14 Security for SCADA and smart grid communication..................... 128 3.15 Challenges for SCADA and smart grid communication................ 130 3.16 Summary............................................................................................... 131 Bibliography..................................................................................................... 131 Chapter 4 Substation automation (SA)................................................... 133 4.1 Substation automation: Why? Why now?......................................... 133 4.1.1 Deregulation and competition.............................................. 133 4.1.2 Development of intelligent electronic devices (IEDs)....... 133 4.1.3 Enterprise-­wide interest in information from IEDs.......... 134 4.1.4 Implementation and acceptance of standards.................... 134 4.1.5 Construction cost savings and reduction in physical complexity............................................................................... 134 4.2 Conventional substations: Islands of automation............................ 134 4.3 New smart devices for substation automation................................. 137 4.3.1 IEDs........................................................................................... 137 4.3.2 New instrument transformers with digital interface........ 138 4.3.3 Intelligent breaker.................................................................. 139 4.3.4 Merging units (MUs).............................................................. 139 Contents 4.4 xi The new integrated digital substation............................................... 139 4.4.1 Levels of automation in a substation................................... 140 4.4.2 Architecture functional data paths.......................................141 4.4.3 Data warehouse...................................................................... 143 4.5 Substation automation: Technical issues........................................... 145 4.5.1 System responsibilities........................................................... 146 4.5.2 System architecture................................................................ 146 4.5.3 Substation host processor...................................................... 147 4.5.4 Substation LAN....................................................................... 147 4.5.5 User interface........................................................................... 147 4.5.6 Communications interfaces.................................................. 147 4.5.7 Protocol considerations.......................................................... 148 4.6 The new digital substation.................................................................. 148 4.6.1 Process level............................................................................ 148 4.6.2 Protection and control level.................................................. 150 4.6.3 Station bus and station level................................................. 150 4.7 Substation automation architectures................................................. 150 4.7.1 Legacy substation automation system................................. 151 4.7.2 Digital substation automation design.................................. 151 4.7.2.1 Station bus architecture........................................ 152 4.7.2.2 Station bus and process bus architecture........... 154 4.8 New versus existing substations........................................................ 154 4.8.1 Drivers of transition............................................................... 155 4.8.2 Migration paths and the steps involved.............................. 156 4.8.3 Value of standards in substation automation..................... 157 4.9 Substation automation (SA) application functions.......................... 158 4.9.1 Integrated protection functions: Traditional approach and IED-­based approach....................................................... 159 4.9.2 Automation functions............................................................ 159 4.9.2.1 Intelligent bus failover and automatic load restoration............................................................... 160 4.9.2.2 Supply line sectionalizing.....................................161 4.9.2.3 Adaptive relaying...................................................161 4.9.2.4 Equipment condition monitoring (ECM)............162 4.9.3 Enterprise-­level application functions..................................162 4.9.3.1 Disturbance analysis............................................. 163 4.9.3.2 Intelligent alarm processing................................. 163 4.9.3.3 Power quality monitoring..................................... 163 4.9.3.4 Real-­time equipment monitoring........................ 163 4.10 Data analysis: Benefits of data warehousing.................................... 164 4.10.1 Benefits of data analysis to utilities...................................... 165 4.10.2 Problems in data analysis...................................................... 166 4.10.3 Ways to handle data................................................................167 4.10.4 Knowledge extraction techniques.........................................167 xii Contents 4.11 SA practical implementation: Substation automation laboratory.... 169 4.11.1 Hardware design of the SA laboratory................................ 170 4.11.2 Software components of the SA laboratory........................ 170 4.11.3 Mitigation from old technology to the new technology.... 173 4.12 Case studies in substation automation.............................................. 173 4.13 Summary................................................................................................174 Bibliography..................................................................................................... 175 Chapter 5 Energy management systems (EMS) for control centers........................................................................................ 177 5.1 Introduction........................................................................................... 177 5.2 Operating states of the power system and sources of grid vulnerability.......................................................................................... 177 5.3 Energy control centers......................................................................... 179 5.3.1 Energy management systems (EMS): Why and what and challenges......................................................................... 180 5.3.2 Energy management systems evolution.............................. 181 5.4 EMS framework.................................................................................... 183 5.4.1 EMS time frames..................................................................... 185 5.4.2 EMS software applications and data flow.......................... 185 5.5 Data acquisition and communication (SCADA systems)............... 186 5.6 Generation operation and management............................................ 188 5.6.1 Load forecasting..................................................................... 188 5.6.2 Unit commitment.................................................................... 189 5.6.3 Hydrothermal coordination.................................................. 191 5.6.4 Real-­time economic dispatch and reserve monitoring..... 192 5.6.5 Real-­time automatic generation control.............................. 193 5.7 Transmission operations and management: Real time................... 194 5.7.1 Network configuration and topology processors.............. 194 5.7.2 State estimation....................................................................... 195 5.7.3 Contingency analysis............................................................. 198 5.7.4 Security constrained optimal power flow.......................... 199 5.7.5 Islanding of power systems.................................................. 200 5.8 Study-­mode simulations...................................................................... 200 5.8.1 Network modeling................................................................. 200 5.8.2 Power flow analysis................................................................ 201 5.8.3 Short-­circuit analysis.............................................................. 201 5.9 Post-­event analysis and energy scheduling and accounting......... 201 5.9.1 Energy scheduling and accounting..................................... 201 5.9.2 Event analysis.......................................................................... 202 5.9.3 Energy service providers....................................................... 202 5.10 Dispatcher training simulator............................................................ 203 Contents xiii 5.11 Smart transmission.............................................................................. 204 5.11.1 Phasor measurement unit..................................................... 204 5.11.2 Phasor quantity and time synchronization........................ 206 5.11.3 PMU-PDC system architecture............................................ 207 5.11.4 Applications of PMU.............................................................. 208 5.11.5 WAMS (wide-­area monitoring system)............................... 209 5.12 EMS with WAMS.................................................................................. 210 5.13 Future trends in EMS and DMS with WAMS.................................. 212 5.14 Case studies in EMS and WAMS....................................................... 213 5.15 Summary............................................................................................... 213 Bibliography..................................................................................................... 213 Chapter 6 6.1 6.2 6.3 6.4 6.5 6.6 6.7 Distribution automation and distribution management (DA/DMS) systems......................................... 215 Overview of distribution systems...................................................... 215 Introduction to distribution automation........................................... 215 6.2.1 Customer automation............................................................. 217 6.2.2 Feeder automation.................................................................. 218 6.2.3 Substation automation........................................................... 219 Subsystems in a distribution control center..................................... 220 6.3.1 Distribution management systems (DMSs)........................ 220 6.3.2 Outage management systems (OMS)................................... 220 6.3.2.1 Unplanned outages................................................ 220 6.3.2.2 Planned outage....................................................... 221 6.3.3 CIS (customer information system)...................................... 222 6.3.4 GIS (geographical information system)............................... 223 6.3.5 AMS (asset management system)......................................... 224 6.3.6 AMI (advanced metering infrastructure)........................... 226 DMS framework: Integration with subsystems............................... 227 6.4.1 Common information model (CIM)..................................... 229 DMS application functions.................................................................. 229 Advanced real-­time DMS applications.............................................. 229 6.6.1 Topology processing (TP)...................................................... 229 6.6.2 Integrated volt-var control (IVVC)....................................... 230 6.6.3 Fault detection, isolation, and service restoration (FDIR).... 231 6.6.3.1 FDIR control strategies.......................................... 235 6.6.3.2 Reliability indices.................................................. 235 6.6.4 Distribution load flow............................................................ 236 6.6.5 Distribution state estimation (SE) and load estimation.... 236 Advanced analytical DMS applications............................................ 238 6.7.1 Optimal feeder reconfiguration........................................... 238 6.7.2 Optimal capacitor placement................................................ 238 6.7.3 Other applications.................................................................. 239 xiv Contents 6.8 DMS coordination with other systems.............................................. 240 6.8.1 Integration with outage management systems (OMS)...... 240 6.8.2 Integration with AMI............................................................. 240 6.8.2.1 Consumer energy consumption data................. 240 6.8.2.2 Reactive energy consumption.............................. 241 6.8.2.3 Voltage profile data and energization status data........................................................................... 241 6.9 Customer automation functions......................................................... 241 6.10 Social media usage for improved reliability and customer satisfaction............................................................................................. 242 6.10.1 Replacing truck rolls.............................................................. 243 6.10.2 Tying it all together................................................................ 244 6.10.3 Routing signals....................................................................... 245 6.10.4 DMS in outage management................................................. 246 6.11 Future trends in DA and DMS............................................................ 247 6.12 Case studies in DA and DMS.............................................................. 247 6.13 Summary............................................................................................... 247 Bibliography..................................................................................................... 248 Chapter 7 Smart grid concepts................................................................. 251 7.1 Introduction........................................................................................... 251 7.2 Smart grid definition and development............................................ 252 7.3 Old grid versus new grid.................................................................... 252 7.4 Stakeholders in smart grid development.......................................... 253 7.5 Smart grid solutions............................................................................. 256 7.5.1 Asset optimization................................................................. 257 7.5.2 Demand optimization............................................................ 257 7.5.3 Distribution optimization..................................................... 258 7.5.4 Smart meter and communications....................................... 259 7.5.5 Transmission optimization................................................... 260 7.5.6 Workforce and engineering optimization.......................... 261 7.5.7 Smart grid road map.............................................................. 261 7.6 Smart distribution................................................................................ 261 7.6.1 Demand-­side management and demand response........... 262 7.6.1.1 Energy efficiency (EE)........................................... 264 7.6.1.2 Time of use (TOU)................................................. 264 7.6.1.3 Demand response (DR)......................................... 264 7.6.1.4 Peak load on the system: Case study.................. 265 7.6.2 Distributed energy resource and energy storage.............. 266 7.6.2.1 Distributed generation (DG)................................ 267 7.6.2.2 Energy storage........................................................ 267 Contents xv 7.6.3 Advanced metering infrastructure (AMI).......................... 270 7.6.3.1 Components of AMI.............................................. 271 7.6.3.2 AMI integration with DA, DMS, and OMS........ 273 7.6.3.3 The market and the business case....................... 275 7.6.4 Smart homes with home energy management systems (HEMs)...................................................................... 279 7.6.5 Plugged hybrid electric vehicles........................................... 281 7.6.5.1 PHEV characteristics............................................. 282 7.6.5.2 PHEV impact on the grid..................................... 283 7.6.6 Microgrids............................................................................... 284 7.6.6.1 Types of microgrids............................................... 286 7.6.6.2 Microgrid control................................................... 286 7.6.6.3 DC microgrid.......................................................... 288 7.7 Smart transmission.............................................................................. 290 7.8 Lessons learned in deployment of smart grid technologies.......... 290 7.8.1 Lessons on technology........................................................... 290 7.8.2 Lessons on implementation and deployment.................... 291 7.8.3 Lessons on project management: Building a collaborative management team........................................... 292 7.8.4 Share lessons learned............................................................. 293 7.8.5 The lessons continue.............................................................. 293 7.9 Case studies in smart grid................................................................... 293 7.9.1 PG&E improves information visibility................................ 294 7.9.2 Present and future integration of diagnostic equipment monitoring........................................................... 294 7.9.3 Accelerated deployment of smart grid technologies in India: Present scenario, challenges, and way forward...... 294 7.10 Summary............................................................................................... 295 Bibliography..................................................................................................... 295 Glossary............................................................................................................ 299 Index................................................................................................................. 305 Preface Although SCADA systems have revolutionized the way complex, geographically distributed industrial systems are monitored and controlled, the details about SCADA components, implementations and application functions have largely remained proprietary. Engineers learn the fundamentals of this evolving technology, mostly on the job and students have difficulty in gathering information as the literature on SCADA fundamentals is scarce and scattered. With the smart grid initiatives taking a giant leap in recent times, it is imperative to have sound knowledge of SCADA basics to implement all the functionalities effectively. Hence this book is an attempt to bring the fundamentals of SCADA systems and elaborate the possible application functions so that academia and practitioners stand to gain from the content. The book is dedicated to power system SCADA, although SCADA systems are extensively used in other industrial sectors like oil and gas, water supply, etc. The discussion revolves around SCADA fundamentals in the initial chapters, followed by application functions from generation, transmission, distribution, and customer automation functions. The first chapter provides an overview of SCADA systems, evolution, and use of SCADA in power systems, the power system field, and the data acquisition process. Chapter two is the soul of the book where the building blocks of SCADA systems are discussed in detail from the legacy Remote Terminal Units (RTUs) to the latest Intelligent Electronic Devices (IEDs), data concentrators, and master stations. The building of different SCADA systems is elaborated with practical implementation descriptions. Communications is of utmost importance in power system SCADA as the field is widely distributed over a large geographical area and owing to the time bound data transmission requirements in milliseconds. Chapter three gives a comprehensive discussion of the data communication, protocols, and media usage. Chapter four discusses substation automation which forms the basis for transmission, distribution, and customer automation. Chapter five discusses energy management systems for transmission control centers with specific emphasis on generation operation and management, real-time transmission operation and management xvii xviii Preface and study mode simulations. Distribution automation and distribution management systems (DMS) are discussed in detail in Chapter six with real time, advanced analytical DMS functionalities, and DMS integration with other distribution application. Chapter seven introduces readers to smart grid concepts discussing the building blocks of smart distribution and smart transmission. The book is intended to catch the attention of practitioners, fresh and experienced alike, to acquire basic knowledge of SCADA systems and application functions, which are evolving day by day, to help them adapt to the new challenges effortlessly. Senior undergraduate and graduate students will find the content very useful with the description of each and every component of SCADA systems and the application functionalities. This book is the outcome of a dream to assist academia and industry in enhancing the understanding of SCADA systems which has fascinated both of us over the years. With one person gaining experience from dedicating his entire career in designing and implementing new SCADA systems across the world for utilities and the other, learning and developing SCADA laboratory systems for students to learn and experiment, it was a natural choice to pen down the content for the users of SCADA systems. However, this journey was not possible without the help of a few friends who believed in us and helped us with motivation, support and suggestions. We thank Nora Konopka, of CRC Press who put her trust in us and helped us write this book with her gentle push once in a while. Professor Saifur Rahman, Director, ARI, Virginia Tech has always been a supporter and thanks are due to Dr. Jiyuan Fan, who helped us finalize the content of the book. The support received from faculty and students of Jamia Millia Islamia, especially Anupama Prakash, Ankur Singh Rana, Namrata Bhaskar and Praveen Bansal, is gratefully appreciated. The support received from our families, especially Shaji and Jo-Ann, our spouses, Shobha & Mathew and Sarah & Mark, our children, is acknowledged. We do hope that this book will bring a better understanding of the inner secrets of SCADA systems, unveil the potential of the smart grid and inspire more minds to get involved. Mini S. Thomas John D. McDonald The authors Mini S. Thomas is a professor in the Department of Electrical Engineering, Faculty of Engineering and Technology, Jamia Millia Islamia (JMI), and has 29 years of teaching and research experience in the field of power systems. Currently she is the Director of Centre for Innovation and Entrepreneurship at the University. She was the head of the Department of Electrical Engineering from 2005 to 2008. Thomas was a faculty member at Delhi College of Engineering, Delhi (now DTU), and at the Regional Engineering College (now NIT) Calicut, Kerala, before joining Jamia. She graduated from the University of Kerala (Gold Medalist), and completed her MTech from IIT Madras (Gold Medalist, Siemens prize) and PhD from IIT Delhi, India, all in electrical engineering. Thomas has done extensive research work in the areas of supervisory control and data acquisition (SCADA) systems, substation and distribution automation, and smart grid. She has published over 100 research papers in international journals and conferences of repute, has successfully completed many research projects, and is the coordinator of the special assistance program (SAP) on power system automation from UGC, Government of India. She is also a reviewer of prominent journals in her field. The first SCADA laboratory and substation automation (SA) laboratory were set up by Thomas at JMI, and they are bringing laurels to the university in terms of research publications, memoranda of understanding (MOUs), and training opportunities, and more importantly, an enhanced image among the world power engineering fraternity. She, as the founder coordinator, with industry participation, has drafted the curriculum and started a unique, first full-time MTech program in the xix xx The authors Faculty of Engineering and Technology at JMI in 2003 in electrical power system management, which offers unique courses on power automation and novel hands-on training. Thomas has worked continuously for industry and academia interaction; the MTech program and the SCADA and SA laboratories have been set up with industry collaboration. She was instrumental in signing an MOU with Power Grid Corporation of India Limited (PGCIL), the transmission utility of India, for long-term cooperation with JMI. She and her team regularly conduct training and certification programs for control center operators of Power System Operations Corporation (POSCOCO) in SCADA basics. She is a certified trainer for “Capacity Building of Women Managers in Higher Education” by UGC and has conducted many training sessions for empowerment. She initiated the Center for Innovation and Entrepreneurship at JMI to promote innovation and business development for students and faculty members. She received the Career Award for young teachers from the government of India, and has won the IEEE MGA Larry K Wilson transnational award, MGA Innovation award, Outstanding Volunteer award, Outstanding Branch Counselor award, and Power and Energy Society (PES) Outstanding Chapter Engineer award, to name a few. Thomas is very active in professional societies and has served on the global boards of IEEE. She is currently a member of the PES LRP (longrange planning) committee. She was a board member of IEEE PSPB (publication services and products board), educational activities board (EAB), served as the vice chair of IEEE MGA (member and geographic activities) board, and was the Asia Pacific student activities coordinator. She has experience of over a decade on international boards and committees of the IEEE and is currently IEEE Delhi section chairperson. She has traveled extensively around the globe, delivered lectures at prestigious universities, and has interacted with technical experts all over the world. The authors xxi John D. McDonald, P.E., is director of Technical Strategy and Policy Development for GE Energy Management’s Digital Energy business. He has 40 years of experience in the electric utility industry. McDonald joined GE in 2008 as general manager, marketing, for GE Energy’s Transmission and Distribution (now Digital Energy) business. In 2010, he accepted his current role of director, Technical Strategy and Policy Development and is responsible for setting and driving the vision that integrates GE’s standards participation, and Digital Energy’s industry organization participation through leadership activities, regulatory/policy participation, education programs, and product/systems development for designing comprehensive solutions for customers. McDonald is a sought-after industry leader, technical expert, educator, and speaker. In his 28 years of working group and subcommittee leadership with the IEEE Power and Energy Society (PES) Substations Committee, he led seven working groups and task forces that published standards and tutorials in the areas of distribution SCADA, master and remote terminal unit (RTU), and RTU/IED communications protocols. He was elected to the board of governors of the IEEE-SA (standards association) for 2010 to 2011, focusing on long-term IEEE smart grid standards strategy. McDonald was elected to chair the NIST Smart Grid Interoperability Panel (SGIP) Governing Board from 2010 to 2012. He is presently chairman of the board for SGIP 2.0, Inc., the member-funded nonprofit organization. He is past president of the IEEE PES, chair of the Smart Grid Consumer Collaborative (SGCC) board, member of the IEEE PES Region 3 Scholarship Committee, the vice president for technical activities for the US National Committee (USNC) of CIGRE, and the past chair of the IEEE PES Substations Committee. He was the IEEE Division VII director in 2008 to 2009. McDonald is a member of the advisory committee for the annual DistribuTECH Conference, vice chair of the Texas A&M University Smart Grid Center advisory board, and member of the Purdue University Office of Global Affairs Strategic Advisory Council. He received the 2009 Outstanding Electrical and Computer Engineer Award from Purdue University. xxii The authors McDonald teaches a smart grid course at the Georgia Institute of Technology, a smart grid course for GE, and substation automation, distribution SCADA, and communications courses for various IEEE PES local chapters as an IEEE PES distinguished lecturer. He has published 60 papers and articles in the areas of SCADA, SCADA/EMS, SCADA/DMS, and communications, and is a registered Professional Engineer (Electrical) in California and Georgia. He received his BSEE and MSEE (power engineering) degrees from Purdue University, and an MBA (finance) degree from the University of California-Berkeley. He is a member of Eta Kappa Nu (Electrical Engineering Honorary) and Tau Beta Pi (Engineering Honorary), a fellow of IEEE, and was awarded the IEEE Millennium Medal in 2000, the IEEE PES Excellence in Power Distribution Engineering Award in 2002, and the IEEE PES Substations Committee Distinguished Service Award in 2003. McDonald was editor of the substations chapter, and a co-author, of The Electric Power Engineering Handbook (co-sponsored by the IEEE PES and published by CRC Press, Boca Raton, FL, 2000). He was also editor-inchief for Electric Power Substations Engineering (3rd ed., Taylor & Francis/ CRC Press, 2012). chapter one Power system automation 1.1 Introduction The global electricity demand is growing at a rapid pace, making the requirements for more reliable, environment friendly, and efficient transmission and distribution systems inevitable. The traditional grids and substations are no longer acceptable for sustainable development and environment-friendly power delivery. Hence, the utilities are moving toward the next-­generation grid incorporating the innovations in diverse fields of technology, thereby enabling the end users to have more flexible choices and also empowering the utilities to reduce peak demand and carbon dioxide emissions to become more efficient in all respects. Power engineering today is an amalgam of the latest techniques in signal processing, wide area networks, data communication, and advanced computer applications. The advances in instrumentation, intelligent electronic devices (IEDs), Ethernet-­based communication media coupled with the availability of less-­expensive automation products and standardization of communication protocols led to the widespread automation of power systems, especially in the transmission and distribution sector. In today’s world with limited resources and increasing energy needs, optimization of the available resources is absolutely essential. Conventional power generation resources such as coal, water, and nuclear fuels are either depleting or raising environmental concerns. Renewable sources are also to be utilized judiciously. Hence there is a need to optimize the energy use and reduce waste. Automation of power systems is a solution toward this goal, and every sector of the power system, from generation, to transmission to distribution to the customer is being automated today to achieve optimal use of energy and resources. In order to integrate the new technologies with the existing system, it is necessary that the practicing engineers are well versed with the old and new technologies. However, in the present scenario, most of the engineering professionals learn the new technology “on the job” as the pace of technology development is very fast with the advent of new communication protocols, relay IEDs, and related functions. This is all the more relevant in the core field of power engineering as the power industry needs trained engineers to keep up the pace of the rapid expansion the power industry is envisaging, to meet the energy consumption that is expected to triple by 2050. It is pertinent to explore the automation of power systems in detail. 1 2 Power system SCADA and smart grids 1.2 Evolution of automation systems The evolution of automation systems could be traced back to the first industrial revolution (1750–1850), when the work done by the human muscle was replaced by the power of machines. During the second industrial revolution (1850–1920), process control was introduced and the routine functions of the human mind and continuous presence were taken over by machines. The human mind was relieved of the bulk and tedious physical and mental activities. Michael Faraday invented the electric motor in 1821, and James Clark Maxwell linked electricity and magnetism in 1861–1862. In the later part of the nineteenth century, there were rapid developments in electricity and supply of electric power with the giants like Siemens, Westinghouse, Nikola Tesla, Alexander Graham Bell, Lord Kelvin, and many others contributing immensely. In 1891, the first long-­ distance three-­phase transmission line of high power was featured at the International Electro-­Technical Exhibition in Frankfurt. Along with the developments in electric power generation, transmission, and distribution to customers, the automation including remote monitoring and control of electric systems became inevitable. The initial control equipment consisted of analog devices which were large and bulky, and the control rooms had huge panels with innumerable wires running from the field to the control center. The operator could not make use of the information available, as during an emergency, a number of events occurred simultaneously and it was impossible to handle all of them since there was no intelligent alarm processing. Excessive cost was associated with a reconfiguration or expansion of the system. The expensive space requirement was also a constraint in the case of analog control, as the control panels were large. Storage of information was also an issue, as for power systems post-­event analysis is crucial. With the introduction of computers into the automation scenario, automation became more operator friendly, although initially computer use was restricted to data storage and to change set points for analog controllers. Early digital computers had serious disadvantages such as minimal memory, poor reliability, and programming written in machine language. Two major developments led to the advent of distributed control: the advances in integrated circuits and in communication systems. Distributed control systems were modular in structure, with preprogrammed menus, having a wide selection of control algorithms for execution. The data highway became possible with the introduction of new communication techniques and media. Redundancy at any level was possible, due to the availability of components at cheaper rates, and extensive diagnostic tools became part of the supervisory control and data acquisition (SCADA) systems. Chapter one: Power system automation 3 1.2.1 History of automation systems Supervisory control and data acquisition (SCADA) systems are widely used for automation of the power sector and represent an evolving field, with new products and services added on a daily basis. Detailed study of SCADA systems is essential for power automation personnel to understand the integration of devices, to understand the communication between components, and for proper monitoring and control of the system in general. There were undoubtedly many methods of remote control invented by early pioneers in the supervisory control field which have long since been forgotten. Control probably began with an operator reading a measurement and taking some mechanical control action as a result of that measurement. Most early patents on supervisory control were issued between 1890 and 1930. These patents were granted mainly to engineers working for telephone and other communication industries. Almost all patents involving remote control closely followed the techniques of the first automatic telephone exchange installed in 1892 by Automatic Electric Company. From 1900 until the early 1920s many varieties of remote control systems were developed. Most of these, however, were of only one class or the other (i.e., either remote control or remote supervision [monitoring only]). One of the earliest forerunners of the modern SCADA system was a system designed in 1921 by John B. Harlow. Harlow’s system automatically detected a change of status at a remote station and reported this change to a control center. In 1923, John J. Bellamy and Rodney G. Richardson developed a remote control system employing an equivalent of our modern “check-­before-­operate” technique to ensure the validity of a selected control point before the actual control was initiated. The operator could also ask for a point “check” to verify its status. The first logging system was designed by Harry E. Hersey in 1927. This system monitored information from a remote location and printed any change in the status of the equipment together with the reported time and date when the change took place. As the scope of supervisory control applications changed, so did many of the fundamentals of supervisory control technology. During the early years all of the systems were electromechanical. The supervisory systems evolved to using solid-­state components, electronic sensors, and analog-­to-­digital convertors. In this evolution, however, the same remote terminal unit (RTU) configuration was maintained. The companies making the RTUs merely upgraded their technology without looking at alternate ways of performing the RTU functions. In the 1980s process control companies began applying their technology and technical approach to the 4 Power system SCADA and smart grids SCADA electric utility market. As a result, RTUs used microprocessor-­ based logic to perform expanded functions. The application of microprocessors increased the flexibility of supervisory systems and created new possibilities in both operation and capabilities. 1.3 Supervisory control and data acquisition (SCADA) systems Automation is used worldwide in a variety of applications ranging from the gas and petroleum industry, power system automation, building automation, to small manufacturing unit automation. The terminology SCADA is generally used when the process to be controlled is spread over a wide geographic area, like power systems. SCADA systems, though used extensively by many industries, are undergoing drastic changes. The addition of new technologies and devices poses a serious challenge to educators, researchers, and practicing engineers to catch up with the latest developments. SCADA systems are defined as a collection of equipment that will provide an operator at a remote location with sufficient information to determine the status of particular equipment or a process and cause actions to take place regarding that equipment or process without being physically present. SCADA implementation thus involves two major activities: data acquisition (monitoring) of a process or equipment and the supervisory control of the process, thus leading to complete automation. The complete automation of a process can be achieved by automating the monitoring and the control actions. Automating the monitoring part translates into an operator in a control room, being able to “see” the remote process on the operator console, complete with all the information required displayed and updated at the appropriate time intervals. This will involve the following steps: • • • • • • • Collect the data from the field. Convert the data into transmittable form. Bundle the data into packets. Transmit the packets of data over the communication media. Receive the data at the control center. Decode the data. Display the data at the appropriate points on the display screens of the operator. Automating the control process will ensure that the control command issued by the system operator gets translated into the appropriate action in the field and will involve the following steps: Chapter one: Power system automation 5 Master Station Computer System Communication Channel Interface Devices A/D Converter Interface Devices D/A Converter Sensor/Transducer Relays Controller/Actuator Measuring Elements Power System Controlling Elements Figure 1.1 The monitoring and controlling process. • • • • • The operator initiates the control command. Bundle the control command as a data packet. Transmit the packet over the communication media. The field device receives and decodes the control command. Control action is initiated in the field using the appropriate device actuation. The set of equipment measuring elements helps in acquiring the data from the field, and the set of equipment controlling elements implements the control commands in the field, as shown in Figure 1.1. 1.3.1 Components of SCADA systems SCADA is an integrated technology composed of the following four major components: 1. RTU: RTU serves as the eyes, ears, and hands of a SCADA system. The RTU acquires all the field data from different field devices, as the human eyes and ears monitor the surroundings, process the data and transmit the relevant data to the master station. At the same time, it distributes the control signals received from the master station to the field devices, as the human hand executes instructions from the brain. Today Intelligent Electronic Devices (IEDs) are replacing RTUs. 6 Power system SCADA and smart grids Master Station Communication System RTU/IED HMI Field Equipment Figure 1.2 Components of SCADA systems. 2. Communication System: This refers to the communication channels employed between the field equipment and the master station. The bandwidth of the channel limits the speed of communication. 3. Master Station: This is a collection of computers, peripherals, and appropriate input and output (I/­O) systems that enable the operators to monitor the state of the power system (or a process) and control it. 4. Human-­Machine Interface (HMI): HMI refers to the interface required for the interaction between the master station and the operators or users of the SCADA system. Figure 1.2 illustrates the components of a SCADA system. 1.3.2 SCADA applications SCADA systems are extensively used in a large number of industries, for their monitoring and control. The oil and gas industry uses SCADA extensively for the oil fields, refineries, and pumping stations. The large oil pipelines and gas pipelines running across the oceans and continents are also monitored by appropriate SCADA systems, where the flow, pressure, temperature, leak, and other essential features are assessed and controlled. Water treatment, water distribution, and wastewater management systems use SCADA to monitor and control tank levels, remote and lift station pumps, and the chemical processes involved. SCADA systems control the heating, ventilation, and air conditioning of buildings such as airports and large communication facilities. Steel, plastic, paper, and other major manufacturing industries utilize the potential of SCADA systems to achieve more standardized and quality products. The mining industry with integrated SCADA for the mining processes, like tunneling, product flow optimization, material logistics, worker tracking, and security features, is the latest addition to the list, making digital mines. The use of SCADA systems in the power industry is widespread, and the rest of the discussion in this chapter will focus specifically on the power sector, including generation, transmission, and distribution of power. Chapter one: Power system automation 7 1.4 SCADA in power systems SCADA systems are in use in all spheres of power system operations starting from generation, to transmission, to distribution, and to utilization of electrical energy. The SCADA functions can be classified as basic and advanced application functions. 1.4.1 SCADA basic functions The basic SCADA functions include data acquisition, remote control, human-­ machine interface, historical data analysis, and report writing, which are common to generation, transmission, and distribution systems. Data acquisition is the function by which all kinds of data—analog, digital, and pulse—are acquired from the power system. This is accomplished by the use of sensors, transducers, and status point information acquired from the field. Remote control involves the control of all the required variables by the operator from the control room. In power systems, the control is mostly of switch positions; hence, digital control output points are abundant, such as circuit breaker and isolator positions and equipment on and off positions. Historical data analysis is an important function performed by the power system SCADA, where the post-­ event analysis is done using the data available after the event has happened. An example is the post-­ outage analysis where the data acquired by the SCADA system can provide insights into such information as the sequence of events during the outage, malfunctioning of any device in the system, and the action taken by the operator. This could be a powerful tool for future planning and is extensively used by power engineering personnel. Power system SCADA requires a number of reports to be generated for consumption at different levels of the management and from different departments of the utility. Hence, report generation is essential as per the requirements of the parties and departments involved. 1.4.2 SCADA application functions Figure 1.3 illustrates the use of SCADA in power systems, with the initial SCADA block depicting the basic functions, as discussed in Section 1.4.1. The right section of the figure illustrates the generation SCADA, represented by SCADA/­AGC (Automatic Generation Control), implemented in the generation control centers across the world. Further, the transmission SCADA is shown as SCADA/­EMS (Energy Management Systems) where the basic functions are supplemented by the energy management system functions. This is implemented in the transmission control centers. 8 Power system SCADA and smart grids Supervisory Control and Data Acquisition (SCADA) Substation Automation (SA) Distribution Automation (DA) Distribution Management System (DMS) SCADA/Automation Generation Control (SCADA/AGC) SCADA/Energy Management System (SCADA/EMS) Figure 1.3 Use of SCADA in power systems. The EMS software applications are the most expensive component of the SCADA/­EMS, mainly due to the complexity of each application. The left part of the figure shows the distribution functions superimposed on the basic SCADA functions, beginning at the SCADA/­distribution automation system and further expanding to the distribution management system functions. As one scans the figure from top to bottom, the systems become more complex and more expensive (i.e., the basic SCADA system is the simplest and least expensive, the SCADA/­AGC is more involved and a little more expensive, and the SCADA/­EMS is much more complex and expensive). The same is true for distribution. The SCADA/­DA is more involved and more expensive than the basic SCADA system. The SCADA/­ DMS is much more complex and expensive. 1.4.2.1 Generation SCADA application functions As discussed earlier, generation SCADA, in addition to the basic functions discussed earlier, will include the following application functions. • Automatic Generation Control (AGC): a compendium of equipment and computer programs implementing closed-­loop feedback control of frequency and net interchange • Economic Dispatch Calculation (EDC): the scheduling of power from all available sources in such a way to minimize cost within some security limit Chapter one: Power system automation 9 • Interchange Transaction Scheduling (ITS): ensures that sufficient energy and capacity are available to satisfy load energy and capacity requirements • Transaction Evaluation (TE): evaluates economy of transactions using the unit commitment results as the base condition • Unit Commitment (UC): produces the hourly start-­up and loading schedule which minimizes the production cost for up to one week in the future • Short-­Term Load Forecasting (STLF): produces the hourly system load for up to one week into the future and is used as input to the unit commitment program • Hydrothermal coordination: the scheduling of power from all available hydro generation in such a way to minimize cost within constraints (e.g., reservoir levels) 1.4.2.2 Transmission SCADA application functions The transmission SCADA will include energy management system (EMS) functions such as • Network Configuration/­Topology Processor: analyzes the status of circuit breakers as well as measurements to automatically determine the current model of the power system • State Estimation: provides a means of processing a set of redundant information to obtain an estimate of the state variables of the system • Contingency Analysis: simulates outages of generating units and transmission facilities to study their effect on bus voltages, power flows, and the transient stability of the power system as a whole • Three-­Phase Balanced Power Flow: obtains complete voltage angle and magnitude information for each bus in a power system for specified load and generator real power and voltage conditions • Optimal Power Flow: optimize some system objective function, such as production cost, losses, and so on, subject to physical constraints on facilities and the observation of the network laws Details of the above functions and additional functions are explained in Chapter 5. 1.4.2.3 Distribution automation application functions Distribution automation/­ distribution management systems (DA/­ DMS) include substation automation, feeder automation, and customer automation. The additional features incorporated in distribution automation will be • Fault identification, isolation, and service restoration • Network reconfiguration 10 Power system SCADA and smart grids • • • • • • • • Load management/­demand response Active and reactive power control Power factor control Short-­term load forecasting Three-­phase unbalanced power flow Interface to customer information systems (CISs) Interface to geographical information systems (GISs) Trouble call management and interface to outage management systems (OMSs) Details of distribution automation functions are given in Chapter 6. 1.5 Advantages of SCADA in power systems Automating a system brings many advantages, and the case of power systems is no different. Some of the advantages are as follows: • Increased reliability, as the system can be operated with less severe contingencies and the outages are addressed quickly • Lower operating costs, as there is less personnel involvement due to automation • Faster restoration of power in case of a breakdown, as the faults can be detected faster and action taken • Better active and reactive power management, as the values are accurately captured in the automation system and appropriate action can be taken • Reduced maintenance cost, as the maintenance can be more effectively done (transition from time-­based to condition-­based maintenance) with continuous monitoring of the equipment • Reduced human influence and errors, as the values are accessed automatically, and the meter reading and related errors are avoided • Faster decision making, as a wealth of information is made available to the operator about the system conditions to assist the operator in making accurate and appropriate decisions • Optimized system operation, as optimization algorithms can be run and appropriate performance parameters chosen Some of the additional benefits by SCADA system implementation are as discussed below. 1.5.1 Deferred capital expenditure With a real-­time view of loading on various transmission lines, feeders, transformers, circuit breakers, and other equipment, and the ability to Chapter one: Power system automation 11 control from a central location, utilities can achieve proper load balancing on the system, avoiding unnecessary overloading of equipment and ensuring a longer service life for the components. Better equipment monitoring and load balancing can extend the economic life of the primary equipment and thus defer certain capital expenditures on assets. More capacity can be squeezed out of the existing equipment with proper monitoring; hence, additional expansion can be deferred for a while when the load increases. 1.5.2 Optimized operation and maintenance costs Utilities can achieve significant savings in operation and maintenance (O&M) costs through the SCADA implementation. Functions such as predictive maintenance, volt-­var control, self-­diagnostic programs, and access to the automation data help the utility to optimize their costs by allowing it to make better informed decisions on O&M strategies that are based on comprehensive and accurate operational data rather than rules of thumb. 1.5.3 Equipment condition monitoring (ECM) By implementing equipment condition monitoring, vital equipment parameters are automatically tracked to detect abnormalities, and with proper maintenance and care, the life of costly equipment can be extended. Intelligent electronic devices (IEDs) are available which continuously monitor equipment health. This helps in resolving issues in the preliminary stages rather than later, and hence major equipment failure and service disruption can be avoided. Power transformers, bushings, tap changers, and substation batteries are some of the power system equipment monitored by ECM IEDs. 1.5.4 Sequence of events (SOE) recording Crucial events in the system are time stamped for post-­event analysis, and this provides crucial data about the system loading patterns. Later it is easy to recreate events in the same sequence as they happened in the system which goes a long way in helping planners design the new transmission lines, feeders, and networks for the future. 1.5.5 Power quality improvement Power quality (PQ) monitoring devices can be connected to the network and monitored centrally to monitor harmonics, voltage sags, swells, and unbalances. Corrective measures such as switching of capacitor banks 12 Power system SCADA and smart grids and voltage regulators can be implemented to improve the power quality, so that the customer receives quality power supply all the time. 1.5.6 Data warehousing for power utilities The introduction of IEDs and availability of high-­speed communication systems have made it possible to convey the operational data to the SCADA master station and the nonoperational data, including the digitized waveforms, to the enterprise data warehouse. The data are archived, and the analysis of the data is driven by the urge to provide more reliable supply to the customer and to make the system operation more competitive. The major benefits of the data analysis include explaining why systems behave abnormally, restoring outages faster, preventing problems from escalating, operating equipment more efficiently, making informed decisions about infrastructure repair and replacement, keeping equipment healthy and extending equipment life, improving reliability and availability, maximizing the utilization of existing assets, improving employee efficiency, and increasing profitability. The major user groups that have been identified in a power utility which will benefit from data warehousing are the operations department, planning department, protection department, engineering department, maintenance department, asset management department, power quality department, purchasing department, marketing department, safety department, and customer support department. Thus, automation brings in a new set of solutions for better managing the assets for customer satisfaction and reliable operation of the system. Hence, utilities across the world are embracing SCADA systems and are reaping the associated benefits. 1.6 Power system field Electricity is generated at the generating stations and transmitted over the transmission system to the distribution substation, from where it is distributed to the consumers. In the current scenario, to this traditional system, renewable generation is added at transmission and distribution, including the customer premises. Hence, SCADA systems will acquire data from all these components, and a brief discussion of these components follows. 1.6.1 Transmission and distribution systems The generated electricity reaches the customer premises passing through a variety of substations which are classified as follows: • Switchyard or generating substations • Bulk power substations or grid substations Chapter one: Power system automation 13 • Distribution substations • Special-­purpose substations (e.g., traction substation, mining substation, mobile substations, etc.) A transmission substation (generating or grid substation) usually has the following components: • • • • • • • • • • • Transformers (with or without tap changers) Station buses and insulators Current transformers Potential transformers Circuit breakers Disconnecting switches (isolators or fuses) Reactors, series or shunt Capacitors, series or shunt Relays/­relay IEDs Substation batteries Line or wave trap and coupling capacitors for power line carrier communication The present-­day distribution substations have similar equipment with reactive and capacitive compensation equipment in place, however with all the equipment at a lower rating. Figure 1.4 shows a typical substation. As far as the SCADA systems are concerned, analog data are acquired from the transformers and station buses via the current and voltage transducers and are further processed for transmission to the control room. Status data (digital data) are acquired from the circuit breakers, isolators, and the shunt and series compensation devices (on/­off positions) and are conveyed to the master station as per the requirement. Environmental data such as temperature, pressure, humidity, and weather conditions are Figure 1.4 A typical substation. 14 Power system SCADA and smart grids collected by the appropriate sensors and are processed for onward transmission to the control center. 1.6.2 Customer premises With the customer taking center stage in an automated distribution system, the devices in the customer premises hold the key to successful implementation of the future smart grid. The smart energy meter capable of two-­way communication, the smart appliances in the house, and also the smart plugs with communication facility are inevitable for customer automation. The main challenge here will be the integration of existing plugs and devices with the new smart meters at the customer premises. The integration of data from a variety of customer meters communicating in different protocols to the collecting hubs and further communication and processing of the data at the substation are challenges to be addressed. 1.6.3 Types of data and signals in power system In the monitoring part of the SCADA systems, the data acquired can be broadly classified into two categories: analog and digital. Pulse data also are acquired, as per the requirement, in case of a count accumulation function, like energy meter data. 1.6.3.1 Analog signals Analog data involve all continuous, time-­varying signals from the field, and are usually thought of in an electrical context; however, mechanical, pneumatic, hydraulic, and other systems may also convey analog signals. Examples are voltage, current, pressure, level, and temperature, to name a few. In power systems, the voltage transformers step down the voltages from kilovolt level to 110 V, and the voltage transducer converts the physical signals to milliampere current (normally 4 to 20 mA) range which is then used for further transmission. Current output is preferred for transducers due to the ease of transmission over long distances and because it is less prone to distortion by interferences. The output of a transducer that measures the power is shown in Figure 1.5 where the range is from 4 to 20 mA. The threshold value of 4 mA was chosen for two reasons. The first reason is that zero input corresponds to 4 mA, not zero amperes, which helps to identify a broken wire, which also will manifest as a zero output. The other reason is that the output curve of the transducer is linear along the 4 to 20 mA portion, as seen from the figure, which gives an accurate output. Errors are introduced in the measurement due to the saturation of the current and voltage transformers, which creates a major problem in Chapter one: Power system automation 15 Transducer Output (in mA) 20 mA 12 mA 4 mA –P MW MW flow in line P MW Figure 1.5 The transducer output curve at 4 to 20 mA. magnitude and phase angle measurements. Errors can also occur due to the poor precision levels of the instrument transformers. The characteristics can deteriorate with time, temperature, and environmental factors. 1.6.3.2 Data acquisition systems Data acquisition is the process of sampling real-­world physical conditions and converting the resulting samples into digital numeric values that can be manipulated by a computer. Data acquisition and data acquisition systems (DASs) typically involve the conversion of analog waveforms into digital values for processing. The components of data acquisition systems include the following: • Sensors/­transducers that convert physical parameters to electrical signals (4 to 20 mA generally) • Signal conditioning circuitry to convert sensor signals into a form that can be converted to digital values • Analog-­to-­digital converters, which convert conditioned sensor signals to digital values Figure 1.6 depicts a typical analog-­ to-­ digital conversion circuitry block diagram. 16 Power system SCADA and smart grids Process Sensors/ Transducers Amplifier Filter Digital Output Analog to Digital Converter (ADC) Sampling Figure 1.6 Analog to digital conversion. 1.6.3.3 Digital signals A digital data signal is a discontinuous signal that changes from one state to another in discrete steps, usually represented in binary, or two levels, low and high. Digital signals include switch positions and isolator and circuit breaker positions in a power system. Digital signals can be directly accessed by the automation system; however, for physical isolation, all digital signals come into the system via interposing relays. Interposing relays initiate action in a circuit in response to some change in conditions in that circuit or in some other circuit, as illustrated in Figure 1.7. Potential free contacts are used for bringing the data from the field, as can be seen in Figure 1.7. The coupling is electromagnetic from the circuit breaker contacts to the RTU, so that no Movement of Breaker Contacts (Mechanical Coupling) NO/NC Contact Multiplier Relay Electromagnetic coupling 220 V NO/NC 220 V NO/NC COIL V1 COIL V2 NC/NO 0V 0V Semaphore (Open/Close indicator) Figure 1.7 Status point data acquisition. Remote Terminal Unit Chapter one: Power system automation 17 physical wiring from the field reaches the control equipment. Errors can be introduced here due to the rusting of the contacts or maloperation. 1.6.3.4 Pulse signals Pulse data refer to the periodic information to be acquired from the field. Pulse data capture the duration between the changes in the value of a signal. This includes the energy data, rainfall, and so forth, and the outputs could be the stepper motor pulse signals. 1.7 Flow of data from the field to the SCADA control center Bus bar Voltage Va=220 kV Potential Transformer 220 kV/110 V Field Control Room HMI Va=220 kV FEP/CFE Voltage Transducer 110 V to 4–20 mA Analog to Digital Conversion Data Packets (Protocol) Communication Channel Master Station Figure 1.8 Data transfer from the bus bar to the control center HMI. RTU The flow of information in a SCADA system can be tracked by analyzing the flow of an analog signal from the field to the display screen of a dispatcher, as shown in Figure 1.8. As an example, the display of a bus bar voltage, say 220 kV, on the mimic screen of an operator is illustrated. Starting from the substation bus bar in the field, the potential transformer connected to the bus converts the 220 kV into 110 V. This 110 V is converted into a 4 to 20 mA analog signal by a voltage transducer. As explained, this analog signal needs to be converted to a digital signal for onward transmission to the master station. The 4 to 20 mA analog signal is converted to a digital signal by the analog input (AI) module of the RTU. Further, this digital signal obtained is packaged into a data packet in the RTU, according to the communication protocol existing between the RTU and the master station. The data packets are then transmitted to the master station along the communication medium available. In the master station, the packets are received by the front-­end processor/­communication front end (FEP/­CFE), decoded, and the data retrieved. The data are then scaled up to the 220 kV range and displayed at the appropriate bus bar in the mimic diagram of the operator console, completing the monitoring cycle. 18 Power system SCADA and smart grids The same sequence could be retraced from the master station to the field, in the case of a control command issued by the operator, to be executed in the field. Use of RTUs with hardwired I/­O and serial communications, once predominant with all field equipment, has transitioned to data concentrators talking to IEDs with digital networked communications. Where substations used to have 100% of their points hardwired, new substations today have 5% or fewer of their points hardwired. Thus, the transition from the conventional RTU to the data concentrator can be seen. 1.8 Organization of the book The book is organized into seven chapters, as given in Figure 1.9. Chapter 1 discusses the history of automation systems and how the SCADA control centers evolved. Chapter 2 elaborates the fundamental building blocks of SCADA systems including RTUs/­IEDs, master stations, and human-­ machine interface in detail. Chapter 3 discusses the SCADA communication with emphasis on the protocols, media usage, and requirements. The rest of the chapters deal with the application of SCADA and associated technologies to the power system. Hence, Chapter 4 discusses substation automation, which is the SCADA application at the substation level, associated with any kind of substation, whether it is at the generation Chapter 1 Introduction Chapter 4 Chapter 2 Chapter 3 SCADA Fundamentals SCADA Communication Chapter 7 Chapter 6 Chapter 5 Smart Grid Concepts Distribution Automation/ Distribution Management Systems (DA/DMS) Energy Management Systems (EMS) Figure 1.9 Organization of the book. Substation Automation (SA) Chapter one: Power system automation 19 switch yard, transmission, or distribution level. Chapter 5 discusses the range of application functions associated with the basic SCADA systems, when applied to transmission systems, termed energy management systems (EMS). The SCADA and associated applications for distribution systems form the content of Chapter 6. Chapter 7, the concluding chapter, introduces the smart grid concept and the functionalities to be integrated and the challenges ahead. 1.9 Summary This chapter is an introduction to SCADA systems, the history of power system automation, and the use of SCADA in the power sector. The advantages and application of SCADA in the power sector are discussed, and the types of data available at the power system and customer are touched upon for clarity. Bibliography 1. J. D. McDonald, Substation automation, IED integration and availability of information, IEEE Power & Energy Magazine, vol. 1, no. 2, pp. 22–31, March/ April 2003. 2. Mini S. Thomas, Pramod Kumar, and V. K. Chandna, Design, development and commissioning of a supervisory control and data acquisition (SCADA) laboratory for research and training, IEEE Transactions on Power Systems, vol. 20, pp. 1582–1588, August 2004. 3. IEEE Tutorial course on Fundamentals of Supervisory Systems, course 94 EH0392-1 PWR. 4. James Momoh, Electric Power Distribution, Automation Protection and Control, CRC Press, Boca Raton, FL, 2007. 5. Mini S. Thomas, D. P. Kothari, and Anupama Prakash, IED models for data generation in a transmission substation, in Proceedings of the IEEE Conference: PEDES-2010, December 2010, pp. 1–8. DOI: 10.1109/PEDES.2010.5712415. 6. James Northcote-­ Green and Robert Wilson, Control and Automation of Electrical Power Distribution Systems, CRC Press, Boca Raton, FL, 2006. 7. William T. Shaw, Cybersecurity for SCADA Systems, Pennwell, Tulsa, OK, 2006. 8. IEEE Tutorial Energy Control Center Design, course 77 TU0010-9-PWR. 9. Mini S. Thomas, Anupama Prakash, and D. P. Kothari, Design, development and commissioning of a substation automation laboratory to enhance learning, IEEE Transactions on Education, vol. 54, no. 2, pp. 286–293, May 2011. 10. Mini S. Thomas, Remote control, IEEE Power & Energy Magazine, vol. 8, no. 4, pp. 53–60, July/August 2010. 11. John D. McDonald, Electric Power Substations Engineering, 3rd ed., CRC Press, Boca Raton, FL, 2012. chapter two SCADA fundamentals 2.1 Introduction Supervisory control and data acquisition (SCADA) systems are extensively used for monitoring and controlling geographically distributed processes in a variety of industries. However, many of the SCADA-­related products are proprietary, and the knowledge of the components is acquired by the personnel on the job. Hence, students and new graduates find it difficult to understand the fundamentals of SCADA systems. An attempt has been made in this chapter to elaborate on the essential components of the SCADA systems which will help explain the functioning and the hierarchy, especially for power systems. 2.2 Open system: Need and advantages SCADA systems are complex and require a variety of hardware and software seamlessly integrated into a system that can perform the monitoring and control operation of the large process involved. Communication among devices is key to successful SCADA implementation in modern power systems. Traditionally most vendors in the automation scenario established their own unique (“proprietary”) way to communicate between devices. Getting two vendors’ proprietary devices to communicate properly is a complex and expensive task. The possible solution to the problem is through two basic approaches: 1. Buy everything from one vendor. 2. Get vendors to agree on a standard communication interface. The first proposition was widely used as earlier proprietary products were utilized for SCADA implementations and large turnkey projects were commissioned by a single vendor. This created a monopoly of products and processes, and it became increasingly difficult to maintain or expand the established SCADA systems. The latter approach, to get all the vendors to agree on a standard communication interface, is the fundamental objective of the “open systems” movement. This led to the concept of nonproprietary, open systems, which 21 22 Power system SCADA and smart grids created a level playing field for all the players in the automation industry. Interoperable systems are becoming popular due to the huge advantages they provide for manufacturers, vendors, and end users. An open system is a computer system that embodies vendor-­ independent standards so that software may be applied on many different platforms and can interoperate with other applications on local and remote systems. Open systems are thus an evolutionary means for a control system, based on the use of nonproprietary and standard software and hardware interfaces, that enables future upgrades to be available from multiple vendors at lowered cost and integrated with relative ease and low risk. The advantages of open systems are manifold, evolving from the definition: • Vendor-­independent platforms for project implementation can be used, avoiding reliance on a single vendor. • Interoperable products are used. Turnkey projects where one vendor supplies and implements the complete project are no longer required, as use of hardware and software from different vendors is possible. • Standard software that could be used to program different hardware can be used. • The de jure (by law) and de facto (in fact or actually) standards can be used. • System and intelligent electronic devices (IEDs) from competing suppliers will have common elements that allow for interchange and the sharing of information. • Open systems are upgradable and expandable. • They have a longer expected system life. • There are readily available third-­party components. As the following sections discuss the building blocks of SCADA systems, it is apparent that all the components discussed use open systems now and the SCADA implementations are exciting propositions with hardware and software acquired from multiple vendors as per the functional requirements of each system. 2.3 Building blocks of SCADA systems The SCADA system has four components, the first being the remote terminal unit (RTU) or data concentrator, which is the link of the control system to the field, for acquiring the data from the field devices and Chapter two: SCADA fundamentals 23 passing on the control commands from the control station to the field devices. Modern-­day SCADA systems are incomplete without the data concentrators and intelligent electronic devices (IEDs) which are replacing the conventional RTUs with their hardwired input and output (I/­O) points. In this book, both RTUs and IEDs have been discussed in detail. Legacy systems with only RTUs, hybrid systems with RTUs and IEDs, and new systems with only IEDs have to be handled with ease by the SCADA system designer today. The second component is the communication system that carries the monitored data from the RTU to the control center and the control commands from the master station to the RTU or data concentrator to be conveyed to the field. The communication system is of great significance in SCADA generally and in power automation specifically, as the power system field is widely distributed over the landscape, and critical information that is time bound is to be communicated to the master station and control decisions to the field. The third component of the SCADA system is the master station where the operator monitors the system and makes control decisions to be conveyed to the field. The fourth component is the user interface (UI) also referred to as the human-­machine interface (HMI) which is the interaction between the operator and the machine. Figure 2.1 gives a pictorial representation of the components of a SCADA system. All automation systems essentially have these four components, in varied proportions depending on the process requirements. Power system SCADA systems are focused on the master stations and HMI is of great significance, whereas process automation is focused on controllers, and master station and the HMI has less significance. The following sections will elaborate how the components of the SCADA system work cohesively to accomplish monitoring and control of the process to achieve optimum performance of the system. Master station CFE/FEP Communication Channel RTU Field Equipment IED Data Concentrator Figure 2.1 Components of SCADA systems. IED IED Field Equipment 24 Power system SCADA and smart grids 2.4 Remote terminal unit (RTU) [1–7,18–19,24] The RTU is the eyes, ears, and hands of the SCADA system. In older days, RTU was a slave of the master station, but now RTUs are equipped with internal computational and optimization facilities. RTU collects data from the field devices, processes the data, and sends the data to the master station through the communication system to assist the monitoring of the power system as “eyes” and “ears” of the master station. At the same time, the RTU receives control commands from the master station and transmits these commands to the field devices, thus justifying the comparison to the “hands” of the master station. Figure 2.1 shows the location of the RTU and the communication front end/­front-­end processor (CFE/FEP) of the master station. 2.4.1 Evolution of RTUs From 1900 to the early 1920s, varieties of remote control systems were developed by engineers for remotely supervising processes. The systems could only monitor the process and no control was possible. In 1921 a system designed by John B. Harlow could automatically detect a change of status at a remote station and could report the change to the control center. In 1923 the remote control system developed by John J. Bellamy and Rodney G. Richardson employed an equivalent of our modern “che...
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1. What is the threshold level of renewable energy penetration at which utilities are
required to change their engineering and planning strategies
Renewable energy is essential and is becoming popular in recent years, and this is
because of its efficiency and reliability in the world. The threshold level of renewable energy
penetration refers to the influence that energy prices have on renewable energy
developments. The installation of the renewable energy power system is proper but has been
proving to be difficult, especially in changing the engineering and planning strategies.
Renewable energy providers have been implementing the distribution of network, adding
tools needed to manage, store, and control the energy systems.
Renewable energy penetration refers to the amount of electricity in percentage, which
is generated by a specific resource. Renewable energy penetration can also refer to the
relative percentage of the total amount of electricity generated or even the consumed amount
of electricity. Both wind and solar have specific percentages of the energy produced. For
wind energy, the threshold level shows that wind can provide about 25 -35 percent of a given
power system’s electricity. Solar energy on the hand can provide a 10-20 percentage.
Therefore, if both wind and solar energy will able to reach the speculated percentages, the
implementation, planning, and designing of engineering strategies will be achieved easily.
This is because the renewable energies will be producing enough electricity and be able to
fund the engineering and planning strategies.
Wind power and solar energy are the primary sources of renewable energy; therefore,
a lot of resources should be put toward making sure that these systems are generating as
much energy as possible and this will make it easier for the future engineering projects and
the plans on the future of renewable energy. By reaching the expected threshold level of
renewable energy, a lot can be achieved because this will mean enough clean energy is
supplied. This implementation will result in a clean environment first because renewable
energy releases low carbon to the environment, and this will translate to a healthy and cl...


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