Manual <strong>systems</strong> had been embedded in many of the business processes, which were, in turn, embedded in proprietary <strong>systems</strong>. As a result, even a simple change in market rules meant going back into the core computer software programs and altering code to match the new requirements. “Our focus is taking the opportunity to enhance IT <strong>systems</strong> using market design, replacing some things that had been in place since start-up,” Yee said. That also includes taking some functions that have already been automated and changing them so they interact with other <strong>systems</strong>. “If <strong>automation</strong> is taking something manual and using computers to do it, we’ve achieved most of the <strong>automation</strong> necessary,” he explained. “Now we’re in transformation.” Examples of these changes include automating both the real-time economic dispatch of generation and the process of making sure that generators follow the dispatch orders. Additionally, the complex structure for financial settlements are more fully automated. Finally, when changes to market rules become effective, they can be implemented without having to alter the basic algorithms built into the software <strong>systems</strong>. The hoped for results are lower wholesale energy costs, improved coordination and management of resources and improved grid reliability. Building the Self-Correcting Grid Grid reliability is, of course, job number one for ISOs, and many current trends in <strong>automation</strong> are geared toward improving system reliability and security. Terry Winter, recently named a vice president of American Superconductor, was a transmission controller for decades — first at San Diego Gas & Electric and then as chief executive officer of the California ISO. “Automation is going to be our only solution as we move to bigger and more complex grids,” Winter said. He identified three major areas in which <strong>automation</strong> is improving the system: Gathering information for operators to act upon; Automating controls to better run the system; and Protection schemes in the event of system faults or severe voltage frequency fluctuations. Utilities and grid operators have long been able to collect data from key power transfer points at substations and switchyards. One of the most important sets of data provide a picture of the physical state of the system — not just the balance of demand and supply, but rather voltage levels, phase angles and the flow of current. There are many different pilots and demonstration projects meant to improve operators’ ability to see what’s going on, he added. He cited the use of “state estimators” or <strong>systems</strong> that offer a comprehensive view of the network at a particular point in time. The current trend of <strong>automation</strong> is to 44 ENERGYBIZ MAGAZINE January/February 2005 connect the <strong>systems</strong> that gather various system metrics into the state estimators. One of the granddaddy <strong>systems</strong> for monitoring the health of the grid has been in place at the New York Power Authority for more than a decade. It is known as Phasor Measurement Unit (PMU), explained Shalom Zelingher, NYPA’s director of research and technology development. “Back in the early 1990s, we looked at a common hardware platform that could provide information on a number of functions, dynamic monitoring of the system, harmonic measurements over a wide area and levels of geomagnetic current,” he said. One of the key features of the PMU project is combining various functions into a common system. “If we went to do each one of the functions, it would have required three sets of hardware and software <strong>systems</strong>,” he said. Measurement of phase angles is “the window to everything else,” Zelingher said. As with other types of energy management <strong>systems</strong> (EMS), the project relies on monitors—in this case a phasor measurement unit or PMU—located strategically on the system. But an early problem was detected in synchronizing the internal clocks of the remote units. Even a tiny shift in the display of frequencies would render the entire exercise useless. That led to an early innovation in using the Global Posi- Automation is going to be our only solution as we move to bigger and more complex grids. tioning System (GPS) of satellites run by the Department of Defense, which vastly improved accuracy. Right now, there are six PMUs installed at substations on the New York State grid that have been in place since 1992. Currently, the project is moving away from dial-up connections to a local-area network (LAN) to provide a live stream of data flow and allow for multiple user access. Connecting the system to the state estimator run by the New York Independent System Operator is another project that’s underway. Full integration is expected a year from now, Zelingher said. “It’s not to the point of using it for a self-healing grid, but that’s where we’re heading,” Zelingher said. A somewhat different take on monitoring the health of the grid has been developed by the Bonneville Power Administration for use in the Western Interconnect. The Wide-Area Measurement System (WAMS) was conceived after a massive blackout in August 1996 cascaded throughout the Western grid, cutting power to about 7 million people. More advanced than a dedicated SCADA system that takes measurements every two to four seconds, WAMS’ sensors monitor the transmission network 30 times per second and report real-time data that’s been synchronized via GPS. Phase shifts and loop flow are also problems in the West, said Bill Mittelstadt, a former BPA engineer who helped develop WAMS, but it incorporates other measurements as well. There are three steps on the ladder of WAMS’ usefulness, he explained. After-the-fact check of computer models and validation of information; (Continued on page 45)
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