Evolution of Control for the Power Grid

Transcription

1 Evolution of Control for the Power Grid Anjan Bose Washington State University Pullman, Washington, USA University of Seville Seville, Spain June 17, 2016

2

3 THE INTERCONNECTED GRID Economics Transfer electric energy from areas where it is cheap to where it is expensive. Electricity trading dates back to the beginning Reliability Neighbors can back up each other. The cost of redundancy is shared.

4 The Past (before 1960s) Hard wired metering Ink chart recording Light and sound alarming Hard wired remote switching Analog Load Frequency Control (1930s) Economic Dispatch (1950s) ED was first to go digital

5 The Present (since 1960s) The digital control center (SCADA-AGC) The RTU to gather digital data at substation Comm. channel from sub to control center (CC) The SCADA The Data Acquisition from RTU to CC The Supervisory Control signal from CC to RTU The screen based operator display Automatic Generation Control (AGC) The digital algorithm for ED The digital version of LFC

6 The Present (since 1970s) The Energy Management System (EMS) State Estimation (SE) Static Security Analysis (n-1) Dynamic Security Analysis (stability) Transient, Oscillatory, Voltage Optimal Power Flow based analysis Preventive Action calculation Corrective Action calculation

7 Evolution of Control Center Architecture Special real time computers for SCADA-AGC Mainframe computer back ends for EMS Redundant hardware configuration with checkpoint and failover Multiple workstation configuration Back-up is more flexible Open architecture initiated CIM (Common Information Model) standard

8

9

10

11

12 West European Power Grid

13 Communication for Power System Analog measurements Digital states Third Party Control Center RTU RTU RTU

14 Eastern Interconnect Control/Monitoring Center RC 1 RC i RC 10 CC 1 CC j CC 1 0 Sub Sub 10 1 Sub k Act 1-10 Sen

15 Phasor Measurement Units Measurements at substations are now handled by microprocessors Measurements can be sampled at very high rates Measurements can be time-stamped by satellite Measure magnitude and phase angle (PMU) PMU output rates: per second Data rates for control centers will increase by 2-3 magnitudes

16

17 Phasor Measurements Super PDC PDC PDC PMU PMU PMU PMU PMU PMU

18 Proposed Communications Measurement1 Control Center R R Substation Server 1 Substation 1 L A N Measurement i Executive Unit1 Executive Unit i R Measurement1 R Substation Server 2 L A N Measurement i Executive Unit1 Power System Communication Systems Substation 2 Executive Unit i R SPS 1 R Measurement1 SPS 2 R R Substation Server 3 L A N Measurement i Executive Unit1 Substation 3 Executive Unit i

19 Advanced Metering Infrastructure Smart Meters Gateway between utility and customer Communication to utility and home appliances Time-of-day and real-time rates Applications Optimize energy efficiency and energy cost Demand response Can integrate generation (roof PV), storage (EV) Microgrids

20

21

22

23 PicRegulator of one feeder with the new equipment Recloser Switched Capacitors Francis & Cedar F3, Spokane, WA 23

24 DISTRIBUTION MANAGEMENT SYSTEM Measurements along the feeder Switches, transformer taps, shunt capacitor and inductor controls Communications: Radio, Power Line Carrier, Fiber backhaul Closer voltage control increases efficiency Greater switching ability increases reliability Better coordination with outage management Sets up for distributed generation, demand response, electric vehicles or local storage

25 Substation Automation Many substations have Microprocessor based devices (IED) Data acquisition at faster rates (30-60 Hz) Digital protection and control systems Remote setting capabilities Data can be time-stamped by satellite Measure magnitude and phase angle (PMU) Local Area Network to control room (LAN) New substation applications

26 Geographic Information System GIS is getting more integrated into all aspects of system operations, especially Distribution management Outage management This has been helpful in other applications like Crew Management, Distribution Planning, etc

27 Outage Management System The computerization of Outage Management has made huge strides Requires less people to handle customer calls Requires less people to do crew dispatching Time savings are significant

28 Building Automation Smart Meters Gateway between utility and customer Utility can send price signals or control signals Change rates (in real time?) Control appliances (especially heating/cooling) Customer Applications Optimize energy efficiency and energy cost Demand response Can integrate generation (roof PV), storage (EV) Microgrids

29 So What Can You Do? Transmission grid: Wide Area Monitoring and Control Distribution: Integrated Volt-Var Control, Conservation Voltage Reduction, Automatic- Remote Reconfiguration Customer: Demand Response, Optimize Cost- Benefits

30 What Wide-Area Monitoring, Protection and Control are Available? Wide-Area Monitoring Systems (WAMS) First installation of PMUs was called WAMS Mostly used for post-event studies Wide-Area Protection and Control Wide-area protection is called SPS or SIPS Experiments with controlling SVC, HVDC, etc. Other applications Oscillation detection PMU-only State Estimator

31 Distribution Applications Integrated Volt-Var Control (IVVC) Use remote control of transformer taps and capacitor banks Minimize losses Conservation Voltage Reduction (CVR) Minimize voltage to reduce load Remote control of sectionalizers for reconfiguration around faults Minimize outage of customers

32 Customer Applications Large customers can play the market Demand response Optimize consumption by rescheduling heatingcooling-large equipment Optimize solar, electric vehicles, other storage Smaller customers have less opportunities Time-of-day or real-time pricing Neighborhood microgrid

33 Data Base Issues At present all applications (XMS) have separate data bases and cannot exchange data All data must be coordinated across the whole system from consumers to generation Standards will be key Real time data is geographically dispersed and require a distributed data base Data has to be moved timely to where it is needed which requires a flexible communication system All data bases in the same interconnection will have to be coordinated

34 INSTITUTIONAL ISSUES Reliability standards need emphasis on best practices rather than compliance Transmission planning who is responsible? Operational procedures e.g. data sharing Market rules often does not take into account operational realities Rate regulation FERC, state PUCs Federal or state energy policies

35 Conclusions Smart grid is developing piecemeal A holistic systems approach is needed The systems approach will have to be driven by utilities the vendors have no interest in doing this The technologies sensors, computers, communications, controllers - are all available, the system vision is not there R&D is needed with a clear path towards implementation Institutional policies updated to encourage technological solutions to meet goals