Tuesday, March 27, 2012

Phase Synchronizer

Phasor technology enables real-time system monitoring and reduces the probability of major disturbances

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1. Background

2. Acronyms/Definitions
3. Business Case
4. Benefits
5. Risks/Issues
6. Success Criteria
7. Next Steps
8. Links
Using a PMU, it is simple to detect abnormal waveform shapes. A waveform shape described mathematically is called a phasor.



1.Background
  • See my post Wide Area Situation Awareness for a description of how this technology is being deployed.
  • The inherent latency in grid monitoring is an important issue; a delay of 2 seconds or more before a grid operator sees an event is not uncommon, and this may be too late to take action to control system instability, leading to a blackout.
  • Popularly referred to as the power system’s “health meter,” Phasor Measurement Units (PMU) sample voltage and current many times a second at a given location, providing an “MRI” of the power system compared to the “X-Ray” quality available from earlier Supervisory Control and Data Acquisition (SCADA) technology. Offering wide-area situational awareness, phasors work to ease congestion and bottlenecks and mitigate – or even prevent – blackouts.
  • Typically, measurements are taken once every 2 or 4 seconds offering a steady state view into the power system behavior. Equipped with Smart Grid communications technologies, measurements taken are precisely time-synchronized and taken many times a second (i.e. 30 samples/second) offering dynamic visibility into the power system.
  • Time-synchronized measurement devices, referred to as “phasors” or “synchrophasors,” have the potential to significantly improve transmission reliability. Synchrophasors take data snapshots of system voltage, current, and frequency and time-synchronize the measurements with Global Positioning System (GPS) timing. The resulting data allows grid operators to see dynamic conditions on the grid in a more real-time manner and with greater accuracy and resolution than possible with current technologies. The result is greater reliability through better system control and early detection and mitigation of potential grid disturbances.


2. Acronyms/Definitions
  1. Angular Instability – A low-frequency (usually less than 1 Hz) undamped power fluctuation traveling from one end of a power grid to the other end. This traveling wave cannot be easily damped and can take up significant capacity on transmission lines.
  2. IEEE C37.118 - Phasor Measurement
  3. IEEE 1588 - Precision Time Protocol
  4. Flicker - Random or repetitive variations in the RMS voltage between 90 and 110% of nominal
  5. GPS Radio Clock – In a typical application, phasor measurement units are sampled from widely dispersed locations in the power system network and synchronized from this common time source. GPS time stamping can provide a theoretical accuracy of synchronization better than 1 microsecond. “Clocks need to be accurate to ± 500 nanoseconds to provide the one microsecond time standard needed by each device performing synchrophasor measurement.
  6. Harmonics - Variations in the wave shape. Electronic filters can remove harmonics.
  7. IED –Intelligent Electronic Device - A microprocessor-based controller of power system equipment, for monitoring and control of automated devices. IEDs receive data from sensors and power equipment, and can issue control commands, such as tripping circuit breakers if they sense voltage, current, or frequency anomalies, or raise/lower voltage levels in order to maintain the desired level. Common types of IEDs include protective relaying devices, load tap changer controllers, circuit breaker controllers, capacitor bank switches, recloser controllers, and voltage regulators. A typical IED can contain around 5-12 protection functions, 5-8 control functions controlling separate devices, an auto-reclose function, self monitoring function, and communication functions.
  8. Inter-Area Oscillation Damping - Low frequency Inter-area oscillations are detrimental to the goals of maximum power transfer and optimal power flow. An available solution to this problem is the addition of power system stabilizers to the automatic voltage regulators on the generators. The damping provided by this technique provides a means to minimize the effects of the oscillations. Although Power System Stabilizers exist on many generators, they effect is only on the local area and do not effectively damp out inter-area oscillations. It can be shown that the inter-area oscillations can be detected through the analysis of phasor measurement units (PMU) located around the system.
  9. Nonzero low-frequency impedance (when a load draws more power, the voltage drops)
  10. Nonzero high-frequency impedance (when a load demands a large amount of current, then stops demanding it suddenly, there will be a dip or spike in the voltage due to the inductances in the power supply line.
  11. NASPI - North American SynchroPhasor Initiative - Working to advance the application of information and communications systems within the electric power industry.
  12. NASPInet– A distributed architecture linking the providers of synchrophasor data (publishers) with applications (subscribers) using a publish-and-subscribe middleware and data bus concept. Currently, NASPInet architecture is at a conceptual design phase and a detailed specification is under development.
  13. Overvoltage - Occurs when the nominal voltage rises above 110% for more than 1 minute. A surge protector or simple capacitor or varistor can protect against most overvoltage conditions.
  14. PDC - Phasor Data Concentrators - Collect the information The PDC correlates the data, and controls and monitors the PMUs (from a dozen up to 60). PMUs often use phone lines to connect to PDC, which then send data to the SCADA and/or Wide Area Measurement System (WAMS) server.
  15. Phase Angle - The fraction of a wave cycle which has elapsed relative to an arbitrary point
  16. Phasor - A complex number that represents both the magnitude and phase angle of the sine waves found in electricity. - In physics and engineering, a phase vector, or phasor, is a representation of a sine wave whose amplitude (A), phase (θ), and angular frequency (ω) are time-invariant.

    Phasors reduce the dependencies on these parameters to three independent factors, thereby simplifying certain kinds of calculations. Using phasors, the frequency factor can be factored out, leaving just the static amplitude and phase information to be combined algebraically (rather than trigonometrically). Similarly, linear differential equations can be reduced to algebraic ones. The term phasor therefore often refers to just those two factors.
  17. Phase Difference - Analogous to two athletes running around a race track at the same speed and direction but starting at different positions on the track. They pass a point at different instants in time. But the time difference (phase difference) between them is a constant - same for every pass since they are at the same speed and in the same direction. If they were at different speeds (different frequencies), the phase difference is undefined and would only reflect different starting positions.
  18. Phasor Data Gateway – The unifying concept that will allow hardware and/or software vendors to interface to NASPInet, either as a publisher or as a subscriber.
  19. PMU - Phasor Measurement Unit - Measures the electrical waves on an electricity grid to determine the health of the system. In power engineering, these are also commonly referred to as synchrophasors and are considered one of the most important measuring devices in the future of power systems. A PMU can be a dedicated device, or the PMU function can be incorporated into a protective relay or other device. PMUs help identify remote system disturbances in advance to prevent wide-scale power outages. For 60HZ systems, PMUs must deliver between 10 and 30 synchronous reports per second depending on the application.
  20. Power Conditioning - modifying the power to improve its quality.
  21. Power Quality - A set of boundaries that allows electrical systems to function in their intended manner without significant loss of performance or life. The term is used to describe electric power that drives an electrical load and the load's ability to function properly with that electric power. Without the proper power, an electrical device (or load) may malfunction, fail prematurely or not operate at all. There are many ways in which electric power can be of poor quality and many more causes of such poor quality power.
  22. PSO - Power System Outlook - A real-time tool that enables operators and engineers to quickly and affordably analyze phasor measurement system data.
  23. RFC – Remote Feedback Controllers - In a typical implementation, one or more of the generators in a system are selected as RFC. The RFC received synchronized phasor measurements from one or more remote phasor sources. The RFC analysis the phase angles from the multiple sites and determines if an inter-area oscillation exists. If an oscillation exists, a control signal is sent to the generator’s voltage regulator that effectively modulates the voltage and effectively damps out the oscillations.
  24. RMS – Root Mean Square - A statistical measure of the magnitude of a varying quantity. Engineers often need to know the power, P, dissipated by an electrical resistance, R.
  25. Sag - the RMS voltage is below the nominal voltage by 10 to 90% for 0.5 cycles to 1 minute. (A "dip" in British English)
  26. SCADA - Supervisory Control and Data Acquisition - An industrial control system: a computer system monitoring and controlling a process. The conventional technology used by grid operators for monitoring the grid.

    Generally speaking, a SCADA system usually refers to a system that coordinates, but does not control processes in real time. Used by a control center to operate elements in the substation domain across a wide area network. At the central control facility, the SCADA system presents system wide data on all generators and substations in the system every 2 to 10 seconds A SCADA System usually consists of the following subsystems:
    • A Human-Machine Interface or HMI is the apparatus which presents process data to a human operator, and through which the human operator monitors and controls the process.
    • A supervisory (computer) system, gathering (acquiring) data on the process and sending commands (control) to the process
    • Remote Terminal Units (RTUs) connecting to sensors in the process, converting sensor signals to digital data and sending digital data to the supervisory system.
    • Communication infrastructure connecting the supervisory system to the Remote Terminal Units
  27. SE - State Estimation - Application that uses SCADA data to determine and display the state of the power system.
  28. Surge - Abrupt, very brief increases in voltage, generally caused by large inductive loads being turned off, or more severely by lightning. A lightning arrestor protects against severe spikes. (Also called spikes, or impulses)
  29. Standard for PMU and PDCs
    1. IEEE C37.118 - The current primary standard for the communications of phasor measurement unit (PMU) and phasor data concentrator (PDC) data and information which was published in 2005. This standard also includes requirements for the measurement and determination of phasor values.
    2. IEC 61850 - The key standard for all substation and field equipment operating under both real-time and non-real time applications. The use of IEC 61850 for wide-area communication is already discussed in IEC 61850-90-1 (Draft technical report) in the context of communication between substations. It appears possible to use a similar approach for the transmission of PMU and PDC data but the capability needs to be formally defined in IEC 61850.
    3. IEEE 1588 - Available to achieve highly accurate synchronization over a communication network however an implementation profile for power system applications is required.
  30. Swell - When the RMS voltage exceeds the nominal voltage by 10 to 80% for 0.5 cycle to 1 minute
  31. Synchrophasors - Precise grid measurements taken by PMUs at high speed, typically 30 times per second, compared to one every 4 seconds using conventional technology. Each measurement is time-stamped according to a common time reference. Time-stamping allows synchrophasors from different utilities to be synchronized and combined, providing a precise and comprehensive view of a regional interconnection. Because these phasors are truly synchronized, synchronized comparison of two quantities is possible, in real time. These comparisons can be used to assess system conditions. Synchrophasor data enable the determination of grid stress and can be used to trigger corrective actions to maintain reliability.
  32. Time Error – An accumulated time difference between control area system time and the time standard. Time error is caused by a deviation in interconnection frequency from 60.0 Hz.
  33. Time Error Correction - An offset to the interconnection’s scheduled frequency to correct for the time error accumulated on electric clocks.
  34. Undervoltage - occurs when the nominal voltage drops below 90% for more than 1 minute. The term "brownout" is an apt description for voltage drops, but has no formal definition
Oscillations in transmission can go across hundreds or even a thousand miles. From Canada or Wyoming down to Southern California -- that’s over a thousand miles.” 


3. Business Case
  • Synchrophasor data enable the determination of grid stress and can be used to trigger corrective actions to maintain reliability.
  • Some applications use synchrophasor data to create the situational awareness for operators to detect sub-second phenomena across the power system. System stress across a wide area or an instantaneous measure of power system dynamics, such as swings, can be recognized nearly instantaneously using such highly accurate data.
  • Metaphorically, synchrophasor technology is like an MRI of the power system, as compared to an X-ray image provided by traditional SCADA technology. Because of instantaneous, high-resolution and more-detailed measurements, PMU data are well suited as input to activate local or centralized automated controls. Such use of synchrophasor technology for wide-area monitoring and control will facilitate the evolution of the existing grid into a smarter transmission grid.
  • Common time synchronization is the key to many Smart Grid applications for real-time operation necessary to make the Smart Grid highly robust and resilient to disturbances (“self-healing”), either from natural events such as earthquakes or large variations in wind or solar power availability, or from potential terrorist actions. Guidelines on how to achieve that synchronization and addressing different issues related to that synchronization are required.
  • Synchrophasor implementation is one of the primary Federal focus areas in the Smart Grid along with distribution automation, large-scale energy storage, demand response, and PHEV infrastructure (transmission & distribution focus)
  • Sensors and digital relays installed on power lines will enable utilities to operate transmission and distribution systems with greater efficiency and reliability. Today’s supervisory control and data acquisition systems, for example, typically provide data on the state of transmission lines every four seconds.
  • The Smart Grid, through, increased deployment of advanced sensors like Phasor Measurement Units will give bulk-power system operators access to large volumes of high-quality information about the actual state of the electric system.
  • Projects to demonstrate synchrophasor measurement technologies and approaches to improve transmission system reliability through large-scale deployment of synchrophasor technology are key to Smart Grid
  • Bridging the communication standards for synchrophasor data from current to more feature rich standards which will accelerate the implementation of the Smart Grid. Expected benefits include reduced capital and lifecycle costs, improved reliability and the enablement of new applications.
4. Benefits
  • Reduced Transmission Congestion Costs – Due to increased transmission transfer capability without building additional transmission capacity.
  • Increased Transmission Capacity - Synchrophasor data could be used to allow power flow up to a line's dynamic limit instead of to its worst case limit.
  • Reduced Outages - Phasor technology enables real-time system monitoring and reduces the probability of major disturbances. Phasor measurement units (PMUs) help identify remote system disturbances in advance to prevent wide-scale power outages.
  • Real-Time Data - Phasor Measurement Units will give bulk-power system operators access to large volumes of high-quality information about the actual state of the electric system that should enable a more efficient use of the electric grid, for example through a switch from static to dynamic line ratings addressing transmission congestion and optimization of the system.
  • Angular Instability Control - If the low-frequency oscillation could be damped, the transmission line capacity could be restored making it easier to relieve congested lines or reduce possible grid instability. In the past, this type of instability has been linked to wide-scale regional blackouts costing billions of dollars in lost productivity, goods and services. A flywheel energy storage system, combined with phasor measurements and an integrated communications and control network, has the potential to overcome this vulnerability and prevent such blackouts.
  • Early Warning - Analysis conducted by the Pacific Northwest National Laboratory (PNNL) of the August 10, 1996, blackout indicates that a Phasor Measurement Unit (PMU)-based Wide Area Measurement System (WAMS) could have provided a 6-minute warning prior to separation of the then-Western System Coordinating Council (WSCC) system into four islands. With a lead time of six minutes, the opportunity exists for real-time control actions designed to damp out the system oscillations. In the case of the August 10, 1996, blackout, system separation might have been avoided if the oscillations of the California-Oregon Intertie had been damped to a sufficient degree. Damping of oscillations may be achieved by fast injection of real and reactive power at a frequency similar to that of the oscillations.

5. Risks/Issues
  • Inconsistent Standards - Two standards are related to communications of phasor measurement unit (PMU) and phasor data concentrator (PDC) data and information. IEEE C37.118 was published in 2005 for PMUs. IEC 61850 has been substantially developed for substations but is seen as a key standard for all field equipment operating under both real-time and non-real time applications. There are significant differences in scope and content of the two standards. Integrating IEEE C37.118 with IEC 61850 will help to remove overlaps between the standards, which may impede development of interoperable equipment and systems.
  • Inaccuracy - PMUs from multiple vendors can yield inaccurate readings. In one test, readings differed by 47 microseconds- or a difference of 1 degree of at 60HZ- an unacceptable variance. China's solution to the problem was to build all its own PMUs adhering to its own specifications and standards so there would be no multi-vendor source of conflicts, standards, protocols, or performance characteristics.
  • Complexity - The growing complexity of interconnected electric grids increases the threat of blackouts and other operational challenges, facilitating the need for a smarter electric grid equipped with wide-area measurement units to monitor large grids.
  • Renewable Energy on the Grid - High Renewalable Portfolio Standards RPS alters system dynamics in a fundamental way, especially when fewer conventional generators are on line. Lack of inertia and governor response, different excitation; different locations of renewables.
  • Network Speed - Phasor measurement monitoring system requires high-speed communications for its most useful applications of system protections (a few seconds) to system state calculation (a few minutes).
  • Transmission Substations and Intertie Stations Issues:
    • Advanced standards for field equipment automation are proposed, but lack designs and implementations that use these standards.
    • There are legacy standards that at present cannot meet Smart Grid requirements. Standards are also in different stages of maturity with no migration pathways yet established to reach Smart Grid goals
    • A need for lower latencies for monitoring grid disturbances with phasor measurement units (PMUs) drives demanding quality-of-service (QoS) requirements as specified for NASPInet

6. Success Criteria
  • Phasor Measurement Units must have voltage (3-phase) and time synchronization in order to compute phasors. Time synchronization must be tight enough to maintain acceptable drift in local time keeping devices and maintained to IEEE 1588 Standards or better.
  • Wide area communications must meet latency and real-time applications requirements for WASA based applications.
  • Remote Feedback Controller must have valid secure communications from the remote sites; the controlled generator must be up and running with validation of status.
  • Topology and other processing must be able to integrate data from field equipment up to EMS systems and environments.

7. Next Steps
  • Collaborating with the Smart Grid community, NIST categorized priority actions to define challenges to and objectives for developing interoperability for the Smart Grid. Each of eighteen priority action plans listed below are linked to key standards organizations and users associations interested in specific Smart Grid standards. Harmonization of IEEE C37.118 with IEC 61850 and Precision Time Synchronization is Priority Action #13.
    • IEEE Standard C37.118 which was published in 2005 is the current primary standard for the communications of phasor measurement unit (PMU) and phasor data concentrator (PDC) data and information. This standard also includes requirements for the measurement and determination of phasor values.
    • IEC 61850 is the key standard for all substation and field equipment operating under both real-time and non-real time applications. The use of IEC 61850 for wide-area communication is already discussed in IEC 61850-90-1 (Draft technical report) in the context of communication between substations. It appears possible to use a similar approach for the transmission of PMU and PDC data but the capability needs to be formally defined in IEC 61850. This action plan seeks to assist and accelerate the integration of standards that can impact phasor measurement and applications depending on PMU and PDC based data and information.
  • March 27, 2009 Funding Opportunity Announcement DE-FOA-0000035 entitled "Advanced SynchroPhasor Research." Application due date was May 27, 2009. $4.3 million was awarded to four, 3-year projects
    • Regents of University of California - SynchroPhasor-based Adaptive Relaying
    • Virginia Polytechnic Institute and State University - Implement Synchrophasor-based Three-Phase Tracking State Estimator for Unbalanced Conditions and Adaptive Islanding
    • Georgia Tech Research Corporation - Real-Time Implementation of the Distributed Dynamic State Estimation for On-line Generator Parameter Identification and Wide-Area Transient Stability analysis
    • Electric Power Research Institute - Wide-area, Real-time Visualization of Frequency ,Voltage and Current Contours for Security Monitoring, on-line Identification of Major Events and Event “instant” Replay
    • Washington State University - Power Grid Reliability and Security – Analysis and Simulation for a Secure Communication Network from PMU to Synchrophasor
    • Applications
  • Develop strategies to migrate legacy standards to meet lower latency requirement for substation and transmission tie stations.
  • Harmonize the “next generation” suites of standards that meet Smart Grid requirements, such as IEC 61850 with the CIM standards, IEC 61970 and 61968 and more demanding Quality of Service requirements of NASPInet.
  • Develop new communication protocols such as the NASPInet GridStat for wide area monitoring using phasor measurement units.
    1. Analyze Grid dynamics under high RPS
      • Definitive studies on stability impacts of high RPS levels
      • Control algorithms and technologies to utilize high speed resources for stabilization
      • Analysis of where to deploy high speed resources
      • Visualization concepts and technologies
      • New algorithms for dynamic grid control and stabilization

    8. Links
    1. Current Status and Experience of WAMS Implementation in North America
    2. North American SynchroPhasor Initiative - Working with DOE to advance the application of information and communications systems within the electric power industry.
    3. Zhenyu H, B Kasztenny, V Madani, K Martin, S Meliopoulos, D Novosel, and J Stenbakken. July 2008. "Performance Evaluation of Phasor Measurement Systems." Power and Energy Society General Meeting - Conversion and Delivery of Electrical Energy in the 21st Century, IEEE , vol., no., pp.1-7, 20-24.
    4. Becker D. May 2010. EPRI: Harmonizing the International Electrotechnical Commission Common Information Model (CIM) and 61850 Key to Achieve Smart Grid Interoperability Objectives.

    Monday, March 26, 2012

    Wide Area Situational Awareness

    The Northeast blackout of 2003 which resulted in a $6 billion economic loss to the region could have been avoided by better communication across system operators.

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    Back to Transmission Index
    1. Background
    2. Acronyms/Definitions
    3. Business Case
    4. NIST Wide Area Situational Awareness Use Cases
    5. Benefits
    6. Risks/Issues
    7. Next Steps
    8. Companies
    9. Links



    Regional Transmission Organizations


    1. Background
    • See my post Phase Synchronizer for a description of how this technology works.
    • There have been five massive blackouts over the past 40 years, three of which have occurred in the past ten years. Many blackouts and brownouts occur due to the slow response times of mechanical switches, a lack of automated analytics, and poor visibility – a “lack of situational awareness” on the part of grid operators.
    • Many wind and solar photovoltaic generators do not have inherent inertial response because of the present controls associated with the power electronic interfaces to the grid. As a result, when these new technologies replace conventional generation, the frequency response and modal behavior of the power system will change.There will be a lack of inertia and governor response, different excitation, different locations of renewables which will all make integrated control of high speed system resources even more important.
    • America is relying on a centrally planned and controlled infrastructure created largely more than fifty years ago before the age of microprocessors that limits our flexibility and puts us at risk on several critical fronts.
    • Wide Area Situational Awareness (WASA) represents the monitoring of the power system across wide geographic areas. These broad area perspectives are necessary to maintain system knowledge and decisions that go beyond conventions of individual companies or even RTO boundaries. The requirements for WASA are architecturally significant from the standpoint of requiring uniformity across traditional systems operation boundaries. Enabling WASA based applications brings forward unique requirements and challenges for the Smart Grid infrastructure.

      Oscillations in transmission can go across hundreds or even a thousand miles. From Canada or Wyoming down to Southern California -- that’s over a thousand miles.” 


      2. Acronyms/Definitions
      1. AGC - Automatic Generation Control – Generators automatic respond in real time to control the power output of the electric generators in accordance with the set limits. - A computation based on measured frequency and computed economic dispatch.

        Generation equipment under AGC automatically responds to signals from an energy management system computer in real time to adjust power output in response to a change in system frequency, tile-line loading or to a prescribed relation between these quantities. A Generation output is adjusted so as to maintain a target system frequency (usually 60 Hz) AGC Regulates the moment by moment balancing of load and generation. Steady system frequency = good regulation. The AGC system adjusts the output of generators under its control, typically every 4-10 seconds in the western U.S. State of system is continuously assessed with input from SCADA algorithms that determine required control actions.

      2. Contingency – The unexpected failure or outage of a system component, such as a generator, transmission line, circuit breaker or other electric element. A contingency plan specifies actions to alleviate the impacts of a possible shortage or disruption of energy. The grid is operated using a conservative approach with margin for anticipated contingencies. This helps to maintain a reliable bulk electric system but also limits throughput capacity. Under selected operating scenarios, it may be advantageous to rely on real-time corrective controls following the contingencies instead of providing operating margins in anticipation of the contingencies.

      3. Contingency Analysis – (aka N-1 analysis) – Contingency analysis simulates the effects of removing equipment and calculates the results using a model of the power system. Makes sure the transmission system gives power users the ability to draw from a diverse set of power plants in different locations and with different operating characteristics. If the transmission system is robust, with a certain amount of redundancy built in, it can withstand the failure of it most critical lines or other components.

      4. EMS - Energy Management System – A computer control system used by electric utility dispatchers to monitor real-time performance of various elements of an electric system and to control generation and transmission facilities.

      5. Control Area Operator - An individual or organization responsible for controlling generation to maintain interchange schedule with other control areas and contributing to the frequency regulation of the interconnection. The control area is an electric system that is bounded by interconnection metering and telemetry.

      6. FERC - The Federal Energy Regulatory Commission - United States federal agency with jurisdiction over interstate electricity sales, wholesale electric rates, hydroelectric licensing, natural gas pricing, and oil pipeline rates. FERC is also responsible for ensuring the reliability of the nation’s high-voltage interstate transmission system.

        Not all transmission is subject to FERC jurisdiction. Public power entities such as the Los Angeles Department of Water and Power are not under FERC jurisdiction. Federal agencies also self-govern, so the Bonneville Power Administration, the Western Area Power Administration and the Tennessee Valley Authority all fall outside FERC’s authority. Finally, most of Texas and all of Hawaii and Alaska are outside FERC jurisdiction because they are not connected, or not tightly connected, to the interstate transmission grid.

      7. Inter-system Interfaces - those interfaces between the boundary of the utility’s transmission, distribution and customer systems and the boundary of another entity’s systems or devices (i.e., between utility grid management system and RTO system)

      8. ISO - Independent System Operator - An independent entity that controls a power grid to coordinate the generation and transmission of electricity, provide open transmission access to all market participants on a nondiscriminatory basis, and ensure a reliable power supply. Each ISO coordinates controls and monitors the operations of the electrical power system. An ISO is usually not for profit and can advise utilities within its territory on transmission expansion and maintenance, but does not have the responsibility to carry out the functions/ There are currently eight ISOs including Alberta, California, Florida, New England, New York, Ontario, and Texas plus four RTO’s.

      9. NARUC - National Association of Regulatory Utility Commissioners - The trade association representing the state public utility commissioners who regulate electricity, natural gas, telecommunications, water and transportation throughout the US. These regulatory commissioners are charged with ensuring that the rates charged by regulated utilities are fair, just and reasonable. NARUC’s mission is to serve the public interest by improving the quality and effectiveness of public utility regulation.

      10. NASPI - North American SynchroPhasor Initiative - Working to advance the application of information and communications systems within the electric power industry. NASPI is a collaborative effort between the DOE, the North American Electric Reliability Corporation, and North American electric utilities, vendors, consultants, federal and private researchers and academics. NASPI activities are funded by DOE and NERC, and by the voluntary efforts of many industry members and experts. Goals:
        1. Angle/frequency monitoring for enhanced situational awareness
        2. Post mortem analysis for disturbances or events
        3. Voltage stability monitoring
        4. Model validation and benchmarking
        5. Enhanced state estimation
        6. Adaptive protection and control algorithms
        7. Real-time control applications

      11. NASPInet– A distributed architecture linking the providers of synchrophasor data (publishers) with applications (subscribers) using a publish-and-subscribe middleware and data bus concept.
        NASPInet Data Classification architecture is designed for interconnection-wide phasor data sharing. It is intended to support multiple on-line and off-line phasor data
        applications. Services classes supported, with quality of service guarantees for each class are:
        • Class A – high performance feedback control
        • Class B – feed forward control (state estimation)
        • Class C – operator visualization
        • Class D – event analysis and off-line queries
        • Class E – test and research

      12. NERC - North American Electric Reliability Council.
        A non profit company formed by the electric utility industry in 1968 to promote the reliability of the electricity supply in North America. Establishes reliability standards for planning and operations in order to improve the reliability and security of the North American bulk power system. For example, NPCC assisted the three northeast system operators (ISO-New England, New York ISO, PJM) to develop a plan to share reserves. NERC includes ten Regional Reliability Councils
        1. ECAR – East Central Area Reliability Agreement
        2. ERCOT – Electric Reliability Council of Texas
        3. MAAC – Mid-Atlantic Area Council
        4. MAIN Mid-America Interconnected Network
        5. MAP – Mid-Continent Area Power Pool
        6. NPCC – Northeast Power Coordination Council
        7. SERC – Southeastern Electric Reliability Council
        8. SPP – Southwest Power Pool
        9. SWCC – Western Systems Coordinating Council
        10. ASCC – Alaskan Systems Coordination Council (Affiliate)

        NERC Regions



      13. NIST – National Institute of Standards and Technology - Under the Energy Independence and Security Act (EISA) of 2007, NIST has “primary responsibility to coordinate development of a framework that includes protocols and model standards for information management to achieve interoperability of smart grid devices and systems.”

      14. PMU – Phasor Measurement Units - Sample voltage and current many times a second at a given location providing an “MRI” enabling wide-area situational awareness.

      15. PUC - Public Utility Commissions -State agency responsible for regulation of retail electricity to consumers and approve for electric generation transmission and distribution facilities.

      16. Reliability Coordinator – An organization responsible for the safe and reliable operation of the interconnected transmission system for their defined areas, in accordance with NERC reliability standards, regional criteria and sub-regional criteria and practices, This entity facilitates the sharing of data and information about the status of the control areas for which it is responsible, establishes a security policy for those control areas and their interconnections and coordinates emergency opting procedures that rely on common operating terminology, criteria and standards.

      17. Reliability Standards - Defined, written, measurable electric system practices and protocols created by NERC that have a material effect on reliability and enable operators to see when a standard is compromised. NERC has agreements with all electric utilities that call for them to comply with the standards, and sanctions exist for violations. For example, one reliability standard governs how facilities such as transmission lines are rated for power-carrying capability in order to avoid cascading outages and other problems. Another standard guides planners as to the types of system events to protect against. In July 2006, FERC designated NERC as the electric reliability organization under section 215 of the Federal Power Act, a new provision added by the Energy Policy Act of 2005 to establish a system of mandatory, enforceable reliability standards under FERC’s oversight.

      18. RAS - Remedial Automation Schemes

      19. RTO – Regional Transmission Organization - Similar to an ISO though controls the operation of electric power transmission system over wider areas. An independent organization that coordinates, controls, and monitors the operation of the electrical power system and supply in a particular geographic area; similar to Independent System Operator. Where RTOs exist, the RTO and the transmission owners in the area decide which one (or both) prepares and submits transmission rates to FERC for approval.

      20. SA - Situational Awareness - The state of the power system components. Situation awareness, situational awareness, or SA, is the perception of environmental elements with respect to time and/or space, the comprehension of their meaning, and the projection of their status after some variable has changed, such as time. It is also a field of study concerned with perception of the environment critical to decision-makers in complex, dynamic areas from aviation, air traffic control, power plant operations, military command and control, and emergency services such as fire fighting and policing; to more ordinary but nevertheless complex tasks such as driving an automobile or bicycle.

      21. Security - the capability of the critical elements of power system infrastructure to withstand outages

      22. Situational Understanding – The capabilities and behavior of the power system components, how each relate to the entire power system state as a whole and how you manage each.

      23. Situational Prediction - How different situations and control commands affect the overall system. The optimal solutions to efficiently manage the system, correct system disturbances, or restore interrupted electrical services.

      24. Synchrophasors - Precise grid measurements taken by PMUs at high speed, typically 30 times per second, compared to one every 4 seconds using conventional technology. Each measurement is time-stamped according to a common time reference. Time-stamping allows synchrophasors from different utilities to be synchronized and combined, providing a precise and comprehensive view of a regional interconnection. Because these phasors are truly synchronized, synchronized comparison of two quantities is possible, in real time. These comparisons can be used to assess system conditions. Synchrophasor data enable the determination of grid stress and can be used to trigger corrective actions to maintain reliability.

      25. Visualization Technology. - Already used for real-time load monitoring and load-growth planning at the utility level, such tools generally lack the ability to integrate information from a variety of sources or display different views to different users. The result is limited situational awareness. This condition will grow even more acute as customer-focused efficiency and demand-response programs increase, requiring significantly more data as well as the ability to understand and act on that data.

        Next-generation visualization is on its way. Of particular note is VERDE, a project in development for DOE at the Oak Ridge National Laboratory. VERDE (Visualizing Energy Resources Dynamically on Earth) will provide wide-area grid awareness, integrating real-time sensor data, weather information and grid modeling with geographical information. Potentially, it will be able to explore the state of the grid at the national level and switch within seconds to explore specific details at the street level. It will provide rapid information about blackouts and power quality as well as insights into system operation for utilities. With a platform built on Google Earth, it can also take advantage of content generated by Google Earth’s user community

      26. WAMA – Wide Area Measurement System

      27. WASA – Wide Area Situational Awareness - Monitoring of the power system across wide geographic areas. Specifically according to FERC, the visual display of interconnection-wide system conditions in near real time at the reliability coordinator level and above.

      28. WECC - Western Electricity Coordinating Council - Regional forum for promoting regional electric service reliability in Western Canada and the Western United States. - WECC operates two reliability coordination offices that provide situational awareness and real-time supervision of the entire Western Interconnection.

      29. WISP - WECC’s Western Interconnection Synchrophasor Project - Will enable smart grid functionality such as improved integrated system operations, enhanced energy loss reduction, more efficient asset use, knowledge-based real-time advanced warning systems, improved market efficiency, and more.

        In 2009, the DOE awarded $54 million to the WECC's Synchrophasor project to improve grid reliability and transmission efficiency as part of the American Recovery and Reinvestment Act of 2009 (ARRA).  This regional project involves nine partner entities.  Partners will install or replace synchrophasor technology, also known as PMUs, throughout their service territories, network them together, and provide the data in a secured interface to their  electric transmission operators, neighboring utilities, and the CAISO.  Planned Completion Date:  April 2013  Remaining Spend:  $42.9M (of which $22M is funded through the DOE grant)

      3. Business Case
      • Here is an excellent example of the value of WASA. On January 26, 2008, transformation was lost at Bonneville Power Administration’s Big Eddy substation, near the northern terminus of the 3100 MW DC Intertie. Control center operators in the West observed oscillations and, after the power on the DC Intertie was reduced by 500 MW, it appeared that the oscillations had ceased. However, the oscillations had only been reduced by 50 percent, which is below the observable level, by dispatchers using their main tool — the Energy Management Systems in the control centers. However, in the California Independent System Operator’s control room, synchro-phasor data was available and presented to power system dispatchers. They were able to see the reduced, but still present, system oscillations. When the DC Intertie flow was reduced to zero MW, the oscillations stopped. Providing better situational awareness tools to operators of the system will enable them to see power system vulnerabilities much better and prevent such a vulnerability from ever becoming a disturbance or blackout.

      • Wide Area Situational Awareness is one the four "Four Priority Functionalities"  identified by FERC in their "Smart Grid Policy" adopted in July 2009. The plan provides guidance to inform the development of a smarter grid for the nation’s electric transmission system and prioritizes the development of key standards for interoperability of Smart Grid devices and systems. FERC will ensure that operators of the nation’s bulk power system have the equipment that gives them a complete view of their systems so they can monitor and operate their systems. Smart Grid technology will play a vital role in making this happen.
      • Situational awareness of grid behavior is being transformed by wide-area-measurement networks.  Only recently have time-synchronized, high quality measurements (from phasor measurement units – PMUs) worked their way into operating rooms of reliability coordinators and balancing authorities.

      • The North American Synchro-Phasor Initiative (NASPI), led by NERC and supported by DOE, is advancing the coordination of the deployment of PMUs and the networking of their measurements for wide-area situation awareness and other applications.

      • The Energy Independence and Security Act of 2007 (EISA) requires FERC, once sufficient consensus has been achieved through a process coordinated by the NIST, to adopt standards and protocols necessary to ensure smart-grid functionality and interoperability in the interstate transmission of electric power and in regional and wholesale markets.

      • NIST has engaged utilities, equipment suppliers, consumers, standards developers and other stakeholders in a participatory public process to identify applicable interoperability standards, gaps in currently available standards and priorities for new standardization activities in Wide Area Situational Awareness. It developed use cases are a method through which to describe applications and the requirements needed to support them.

      An EPRI study team expects utilities to install approximately 1,250 PMUs throughout the grid over the next 20 years at a total cost of $26-39 million.Source: EPRI

      4. NIST Wide Area Situational Awareness Use Cases
      • CA - Contingency Analysis - An Energy Management System (EMS) application that analyzes the security of a power system. It calculates, identifies, and prioritizes: current and power flow overloads in equipment, voltage violations at buses, and system stability problems that would occur if contingency events happen in the future.
      • Wide Area Control System for Self Healing Grid Application - The Wide area control system functions comprise a set of computing applications for information gathering, modeling, decision-making, and controlling actions.
      • Voltage Security - The Voltage Security function is designed to detect severe low voltage conditions based on phasor measurements of Power and Voltage and upon detection, initiate corrective action such as load shed.
      • Monitoring Distribution Operations as a Part of WASA - The results of the analysis are aggregated at the demarcation lines between distribution and transmission.
      • Voltage, Var, and Watt Control (VVWC) - The application calculates the optimal settings of voltage controller of LTCs, voltage regulators, Distributed Energy Resources, power electronic devices, capacitor statuses, and may enable demand response means for optimizing the operations following current objectives.

      5. Benefits
      • Mitigate, or even prevent, blackouts - According to the DOE Final Report on the August 14, 2003 Blackout in the United States and Canada, use of data from wide-area measurement systems (WAMS), including synchro-phasor measurements, could have mitigated or even avoided the estimated $4.5 billion in losses suffered by over 50 million people in the 2003 blackout of the northeastern U.S. and Canada.
      • Ease transmission congestion and bottlenecks
      • Reduce transmission congestion costs from increased transmission transfer capability without building additional transmission capacity
      • Optimize the transmission system
      • Evaluate power system behavior in real-time
      • Prepare the power system for withstanding credible combinations of contingencies, prevent wide-area blackouts
      • Accommodate fast recovery from emergency state to normal state.
      • Reduce load while respecting given voltage tolerance (normal and emergency);
      • Reduce or eliminate overload in transmission lines
      • Reduce or eliminate voltage violations on transmission lines

      6. Risks/Issues
      • Situational awareness needs to include information from the distribution and customer systems. These systems are becoming more interconnected with two way power flows becoming more common.
      • Utilities have generally deployed silo systems Smart Grid is about an enterprise platform. All departments sharing data and analytics. Actionable intelligence needs to be integrated between IT systems and within the business processes.
      • WASA creates very large volumes of data which will present challenges in information processing and management. Advanced software and systems will be needed to manage, process, and render this data into a form suitable for human operators and automated control systems. The Institute’s process should strive to identify the core requirements for such software and systems that would be most useful to system operators in addressing transmission congestion and reliability.

      7. Next Steps
      • The DOE is providing grants to install more than 850 PMUs. Per the DOE, these PMUs “will cover 100% of the U.S. electric grid and make it possible for grid operators to better monitor grid conditions and prevent minor disturbances in the electrical system from cascading into local or regional power outages or blackouts.
        • In October 2009, the Western Electricity Coordinating Council (WECC) was awarded $54 million of Smart Grid Stimulus funds (See my blog Smart Grid Stimulus) to install over 250 phasor measurement units across Western Interconnection and create a communications system to collect data for real-time situational awareness. (Project Scope White Paper PDF)  The Smart Grid stimulus is a matching grant program so total project value will be $108 million.  The project will improve integrated systems operation across 11  organizations and in all or part of 14 western states, enhancing reliability and reducing energy loss.
        • In the same grant, the New York Independent System Operator was awarded $37 million to deploy a range of smart grid technologies, including 35 new phasor measurement units and 19 phasor data concentrators, across NY to allow area-wide control, and an open, flexible, interoperable, secure, and expandable communciations system that will work in concert with the existing control and monitoring systems.
        • The Midwest Independent Transmission System Operator was awarded $17 million to install, test, integrate and monitor 150 phasor measurement units in strategic locations across the Midwest on independent transmissions system operators, which will improve the energy dispatching, system reliability and planning capabilities.
        • PJM Interconnection was awarded $14 million to deploy over 90 phasor measurement units and other digital monitoring and analysis technologies across 10 states that will provide real-time data on the operating conditions of the transmission system, improving reliability and reducing congestion.
        • American Transmission Company was awarded $11 million to build a fiber optics communications network for high-speed communications to maximize the full capability of phasor measurement networks across ATC's transmission system.

      • Examples of the types of demonstration projects under this funding opportunity announcement include:
        1. Reliability Coordinator saturation Demo – Projects to establish an extensive measurement hardware, communications, processing and applications deployment within one of the Reliability Coordinator regions . This could include a new, dedicated fiber network for all bulk power transmission system communications linking the synchrophasor measurement devices with the control center(s) and linking to generation and transmission assets that facilitate phasor and other phasor-related applications.
        2. Reliability Coordinator Synchrophasor Backbone Demo – Projects to establish a communications network to link standard configuration measurement and data collection hardware to deliver fast data traffic between Reliability Coordinators and major Balancing Authorities within an area. This should serve as the foundation for supporting multiple synchrophasor applications.
        3. Phasors for Renewable Generator Interconnection –Projects to install a networked phasor measurement unit at every large renewable generator and key substation within a specific area, e.g., within a single Reliability Coordinator’s region. Design and initiate a research project for data analysis to identify impacts of intermittent generation over various time spans. Link to intermittent generator analysts and share data patterns with adjacent Reliability Coordinators to design methods to feed patterns into intermittent generation forecasting and grid analysis. Integrate phasor data into real-time grid monitoring and operations. Look for ways to use the phasor data to feed into new renewable integration opportunities, including ancillary services provided by demand-side resources.
        4. NASPInet Demo –Following the release of the draft NASPInet specification, expected in mid-2009, there will be pilot demonstration projects to further refine and modify this specification based on lessons learned from interconnecting multiple vendors and a spectrum of applications in a common architectural framework.
      • In FERC’s plan, the wide-area situational awareness efforts, with appropriate cyber-security protections, can rely on the NASPInet work undertaken by the North American SynchroPhasor Initiative (NASPI) and will require substantial communications and coordination across the RTO and utility interfaces. FERC encourages the RTOs to take a leadership role in coordinating the NASPI work with the member transmission operators.

      8. Companies
      1. GRIDiant Raleigh, NC – Optimal Technologies announced in November 2009 in conjunction with the transfer of its business to GRIDiant Corporation that they were changing their application product suite name from AEMPFAST to GRIDmaster.  They received $25 million VC funding in 2008 towards the development of software for managing electrical grids. GRIDmaster is software and services for analysis, optimization, ranking, and management of complex electric power systems. Designed for electrical transmission and distribution grid owners and operators, it provides a unique and highly effective non-linear network analysis, optimization, management, ranking, and prediction “engine” capable of solving previously “unsolvable” problems.
      2. InStep Software - Chicago, IL -  Providing a solution to Southern California Edison  utilizing a series of Phasor Measurement Unit's (PMU's) to monitor and analyze the operation and health of the electric grid. This system provides metrics to reduce the risk of system failure and to analyze problems when an event occurs and uses InStep's eDNA historian and SyncPhzr interface.

      8. Links
      1. Report to NIST on the Smart Grid Interoperability Standards Roadmap
      2. FERC Smart Grid Policy - FAQ - Detail
      3. WECC – Western Electricity Coordinating Council– Reliability Coordination
      4. Dagle - Smart Grid System Report, DOE July 2009
      5. Galvan F, L Beard, J Minnicucci, and P Overholt. 2008. “Phasors Monitor Grid Conditions” Transmission and Distribution World.
      6. Patel M, S Aivaliotis, E Ellen, et al. October 2010. NERC Real-Time Application of Synchrophasors for Improving Reliability.
      7. Novosel D, V Madani, B Bhargavam, V Khoi, and J Cole. January-February 2008. "Dawn of the Grid Synchronization." Power and Energy Magazine, IEEE, vol.6, no.1, pp.49-60.
      8. Phadke AG and RM de Moraes. September-October 2008. "The Wide World of Wide-area Measurement." Power and Energy Magazine, IEEE, vol.6, no.5, pp.52-65.
      9. Boston T, M Heyeck, and A Mansoor. January 6, 2011. "Phasor Measurements Go the Last Mile." Transmission and Distribution World.