August will Mark the Five-Year Anniversary of the Largest Blackout in U.S. History. Looking back, how much has changed? Is our grid more secure or resilient to blackouts? What more needs to be done? The answers to these questions are as thorny and complicated as the questions themselves. From the East Coast to the West Coast, the work of countless men and women has gone into our industry's collective reply to these questions.

THE PHASOR WORLD

Across the Eastern Interconnection, the integration of phasor technology and its use has been advancing, though slowly. Many utilities are still uncertain about the benefits of phasor measurement unit (PMU) systems. There is some general advice for utilities and independent system operators (ISOs) thinking of installing PMU systems.

It may take anywhere from eight to 12 months to get “iron in the ground” if you are installing new PMUs. Converting existing relays to dual-function relay/PMU devices can be faster; however, site selection and timing of conversion could delay the process.

Once PMUs are installed, it will take time to use, understand and manage your phasor data collector and PMU system. Plan on four to six months to set up the basic system protocols and put the system through several training and test exercises.

Several foundation studies need to be made for each utility/ISO system. A meter placement study will give insights into how many PMUs will be needed for your system to have redundant and optimal observability and where they should be placed.

Additional system examination will reveal normal phase-angle difference relative to PMU locations. Along with gaining a basic understanding of your PMU system, you can seek out applications that are ready for piloting or use. These include incorporating phasor measurements into state estimation, event triangulation, early warning systems, post-mortem evaluation using phasor data, and control applications. Overall, developing phasor systems takes time. The North American SynchroPhasor Initiative (NASPI) community is ready to assist utilities to make the journey one of learning and not frustration.

SUPER PHASOR DATA CONCENTRATOR

Today, there are approximately 75 PMUs installed on each of the Eastern and Western Interconnections. Most of these PMUs are networked to a central location for processing and redistribution of data back to the PMU owners. In the East, that central location is the Tennessee Valley Authority's (TVA) Super Phasor Data Concentrator (SPDC).

In the fall of 2003, TVA took up the challenge to design, manufacture and operate a system that collects data from PMUs across the Eastern grid, including more than a dozen utilities and regional transmission operators. With the SPDC, TVA archives more than 23 GB of phasor data daily. The initial objectives of the SPDC were to create a system with an open and completely scalable architecture that specifically supports the most popular phasor data transmission protocols, in particular PC37.118, IEEE1344, the BPA PDC stream and Ole for Process Control. In the current working implementation of the SPDC, all of these transmission protocols have been developed. The SPDC is now archiving more than 2.8 billion unique measurements per day.

LOOKING BACK

Following the Aug. 14, 2003, blackout in the Northeastern United States and parts of Canada, the U.S.-Canada Power System Outage Task Force's final report on the outage called for time-synchronized recording devices for better wide-area visibility of the grid and improved post-disturbance analysis of this type of event. In response to these recommendations, the U.S. Department of Energy (DOE), the North American Electric Reliability Corporation (NERC) and utility industry representatives met in the fall of 2003. Together, they agreed to accelerate the deployment of synchronized PMUs in the North American Eastern Interconnection and called the effort the Eastern Interconnection Phasor Project (EIPP).

PMU owners and charter members of the project included TVA, Entergy, American Electric Power, Ameren and the New York Power Authority/New York ISO. DOE led the EIPP and provided resources to facilitate meetings and coordinate technical expertise for the project.

EIPP became what could be called on-the-job research and development. The initial objective was to activate the dozen or so PMUs in the interconnection and link them into a network that would bring time-synchronized data to a central location to create a wide-area view of the grid. As specific issues and potential applications were identified, task teams were formed to address emerging issues such as equipment placement, data and communications management, standards, data sharing among participants, and data use in both operations and planning.

In the mid-1990s, DOE worked with the Bonneville Power Administration, Western Area Power Administration, the U.S. Bureau of Reclamation, Pacific Northwest National Laboratory and the Electric Power Research Institute to install time-synchronized recorders, including PMUs, in the Western Interconnection to assess their operating characteristics and create tools to record, archive, analyze and display phasor data. More recently, DOE has supported synchronized measurement work in the Electric Reliability Council of Texas through work at Texas A&M University and in partnership with the Center for the Commercialization of Electric Technologies.

With the enactment of the Energy Policy Act of 2005, and later the Federal Energy Regulatory Commission's designation of NERC as the new Electricity Reliability Organization, DOE and NERC agreed to transition to new roles in NASPI. In 2008, NERC will work with industry to lead the deployment of phasor measurement technology throughout North America, and DOE will focus on longer-range research and development for phasor technology, phasor applications and the analysis of phasor data. This change is reflected in the renaming of the EIPP to the North American SynchroPhasor Initiative.

NEAR-TERM CHALLENGES

Although NASPI has made steady progress in deploying a time-synchronized wide-area-measurement network prototype, significant needs remain to turn this prototype into an operational system. Among these needs are the design and deployment of the next-generation PMUs, which will build on the experience accumulated to date. There also is the need to implement a communications infrastructure to move sub-second data in real time across the grid.

Further regional studies to understand normal and abnormal phase-angle differences across the grid are needed. Field trials are needed as well to prototype interim communications infrastructures, early warning systems, dynamic line-loading technologies and event triangulation.

Additional utilities are needed to install PMUs across the North American grid. And most importantly, support from Congress and state legislatures is needed to fund these technologies (perhaps as part of grid modernization and the smart grid) and to demonstrate the infrastructure needed to make synchrophasor networks possible. Meeting these challenges will help our industry progress beyond the lingering uncertainty we face today.

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Floyd Galvan is senior project manager for research and development at Entergy Corp. His areas of specialization include phasor measurement and control, grid visualization, applications of phasor measurements, long-term planning and regional energy pricing. Galvan has worked throughout the industry in various areas including system planning, fuels procurement and wholesale energy forecasting. He has held leadership positions within the Department of Energy Eastern Interconnection Phasor Project and CEATI International, and has served on numerous panels and committees at the National Science Foundation. fgalvan@entergy.com

Lisa M. Beard has worked for the Tennessee Valley Authority for more than 27 years. She is currently a research and development program manager for transmission technologies. She also currently serves as the chair for CEATI International's Power System Planning and Operations Interest Group, is co-chair of the NASPI Research Initiatives Task Team and is a member of Power Systems Engineering Research Center's Industrial Advisory Board. lmbeard@tva.gov

John Minnicucci manages Southern California Edison's Research, Development and Demonstration program. In his 14 years in the electric utility industry, Minnicucci has also specialized in the areas of auditing and regulatory policy and affairs. He currently co-chairs the Research Information Task Team for the North American SynchroPhasor Initiative and coordinates advisory roles on various California Energy Commission Public Interest Energy Research programs. John.Minnicucci@sce.com

Philip N. Overholt is the program manager for Transmission Reliability Research and Development, managing electric power systems research and development in the Office of Electricity Delivery and Energy Reliability at the U.S. Department of Energy (DOE). His experience includes nine years as an electrical engineer at the Cleveland Electric Illuminating Co. and 21 years as a program manager at DOE. He was honored as the DOE 2006 Federal Engineer of the Year. philip.overholt@hq.doe.gov

ENTERGY PHASOR SYSTEM

In December 2003, Entergy became the first utility in the Eastern Interconnection to exchange sub-second phasor data with the Tennessee Valley Authority's Super Phasor Data Concentrator. Starting with just a handful of phasor measurement units (PMUs), Entergy now has 22 PMUs across Mississippi, Louisiana, Arkansas and non-ERCOT east Texas.

The Entergy PMUs communicate with the Entergy Phasor Data Collector (PDC) through an internal, secure fiber network used solely for operational data. In the last four years, we have worked to expand the reach and capabilities of this fiber network. It is the backbone of our phasor system.

The hardware infrastructure for the PDC includes 25 TB of disc storage — sufficient for three to four years of sub-second data storage from 40 PMUs. We have separate servers to send and receive data to and from TVA, to perform sub-second phase-angle differences and to line up all the sub-second data from the PMUs for use in real-time analysis such as integration with state estimation, event triangulation or frequency spike detection.

In the last year, Entergy funded a PMU placement study with Dr. Ali Abur of Northeastern University. The placement study provides Entergy the analytical support needed to determine the optimal sites for PMU placement on our system. The study also incorporates PMU redundancy to maintain system visibility during the loss of a PMU. In total, the study calls for 721 to 1300 PMUs (depending on the type used) to be added across the Entergy grid for optimal wide-area visibility.

Entergy also funded the initial phase of a study with Dr. Mani Venkatasubramanian of Washington State University for the determination of phase-angle differences across our service territory. This work provides us with an initial understanding of normal, stressed and critical phase-angle differences across the Entergy territory. This information is crucial for the understanding of potential problems with the grid. Subsequent phases of this work will provide neural-network-based identification of phase-angle differences in real time and early warning for the wide area.

Most recently, we have been successful in the development of new and modern visualization tools for monitoring the wide area. In an instant, the system operator can tell if phase-angle differences are normal, stressed or critical across wide geographic areas. In real time, the operator can see a frequency disturbance and see the effect of weather moving through an area. These modern visualization tools are being tested and tailored to fit Entergy's needs and are expected to be operational by summer 2008.

PHASORS AT SOUTHERN CALIFORNIA EDISON

Synchronized phasor measurement system (SPMS) technologies and the use of them are continuing to advance in the West.

Foundational research programs began in 1995 with the Bonneville Power Administration (BPA), the Electric Power Research Institute and Southern California Edison (SCE). These programs have matured with the involvement of the California Energy Commission, the Consortium for Electric Reliability Technology Solutions (CERTS), the California Independent System Operator (CAISO), the Department of Energy (DOE), Pacific Northwest National Laboratory (PNNL), Pacific Gas & Electric and San Diego Gas & Electric. With so many different groups working on these technologies, and others in the East, the creation of the North American SynchroPhasor Initiative (NASPI) was essential for communication and collaboration.

Significant achievements have included the creation of the BPA phasor data concentrator, the CERTS Real-Time Dynamic Monitoring System software, the SCE Power System Outlook studies software and the Synchronized Measurement and Analysis in Real Time (SMART) software. There are also many studies and papers done by PNNL, academia and others in support of this effort. The Western Electricity Coordinating Council, which encompasses the Western United States and Canada, has more than 77 phasors deployed. Even with these achievements, the West has only begun to scratch the surface of SPMS capabilities; much more work and collaboration is necessary.

R&D INITIATIVES

From SCE's perspective, SPMS technologies will play a crucial, if not defining, role in how its system is operated and controlled. The SCE research, development and demonstration (RD&D) portfolio includes six SPMS-related projects, using about one-fourth of SCE's limited RD&D budget:

• Power System Outlook enhancements

  This software conducts post-event analysis and has an interface with General Electric's Power System Load Flow software for model validation. SCE is currently developing analyses for voltage stability, angle stability, power/voltage and VAR/voltage curves, control capabilities for flexible ac transmission systems and high-voltage dc systems, and load models for power systems analysis.

• SMART enhancements

  This software provides real-time visualization and analysis capabilities (for example, currents, active and reactive power, frequency and frequency deviation, df/dt, percent deviation for voltage, current, and real and reactive power). SCE is currently working to incorporate more of the Power System Outlook off-line analyses into the real-time environment and incorporating more data points from other Western Electricity Coordinating Council (WECC) entities through the CAISO.

• Phasor black start capability

  SPMS technologies have proven their capability to diagnose the causes of system events. SCE is conducting research into using this same information for system recovery and intentional islanding strategies to protect critical components.

• Phasor enhanced wind integration

  SCE expects 4000 MW of wind generation near Tehachipi, California. The ability to reliably integrate relatively high amounts of wind generation supports SCE's commitment to meet California's mandated Renewable Portfolio Standard, while also meeting NERC/WECC planning and operating reliability criteria. Through the use of relative phase angles across the bulk power system — through direct measurement and software simulation — SCE will better determine the impacts of this relatively intermittent resource on the system and identify equipment upgrades and operational procedures to ensure system performance.

• Strategic Awareness and Analysis Center (SAAC)

  Under-standing the correlation between phasor measurements and electric system health is highly complex. Electric system operators need a commercial-grade software package, reliable phasor communications and a great deal of training to become proficient in operating with these advanced tools. To fully utilize existing capabilities, SAAC will provide advanced engineering support to operators during a system event. This will increase the quality of information available for decision making and control actions.

• Voltage VAR control

  The longer-term answer to grid reliability is wide-area information and optimized, intelligent control. SCE is currently using phasor voltages at its Big Creek Generating station and Rector substation to control a 120-MVAR to 200-MVAR static VAR compensator. The 100-mile (161-km) difference between the data inputs enhances use of the asset by providing voltage stability over the entire San Joaquin Valley during system events, instead of just at the localized substation. SCE is working to develop algorithms that incorporate phase-angle information into this process, as well as coordinate other VAR control devices (shunt reactors and capacitors) within the area.

ADDITIONAL PHASOR APPLICATIONS

In addition to the research, SCE and several other entities are using phasor technologies in their standard course of business. The WECC Disturbance Monitoring Working Group, chaired by Bharat Bhargava of SCE, is currently using phasor measurement data as part of its disturbance analyses. Within an hour of a system event, SCE is able to conduct an SCE-wide assessment (with one data point from BPA) using its Power System Outlook software. This assessment provides a basis for which to determine the initial causes and severity of the event. As SCE receives phasor data sets from other WECC entities, a more detailed assessment can be done to provide additional insight. The WECC System Modeling and Validation Group is also using phasor information from various system events to validate its models.