By Steven M. Brown, editor in chief, and Kathleen Davis, associate editor
The simultaneous construction of two substations in a space-constrained urban area, pioneering work in the area of wide-area measurement and monitoring, a partnership to meet the requirements of an aggressive smart metering mandate, and innovative use of technology to visualize conditions on the bulk power grid–all were named recipients of Utility Automation & Engineering T&D’s annual Projects of the Year awards during the DistribuTECH and TransTECH 2008 keynote session.
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Now in its fifth year, the awards program is designed to honor the most innovative electric power transmission and distribution technology implementations undertaken by North American electric utilities each year.
Winners of the 2007 Projects of the Year Awards were:
- T&D Engineering Project of the Year: Consolidated Edison Company of New York;
- T&D Automation Project of the Year: Entergy and Southern California Edison (co-winners);
- AMR/AMI Project of the Year: The Ontario Coalition of Large Distributors; and,
- Geospatial Project of the Year: California ISO.
Consolidated Edison Squeezes More Power into Tight Space
As the demand for power increases, all electric utility companies face a common challenge of building out the T&D infrastructure. That challenge intensifies greatly when the utility serves customers in a tightly congested urban area. The demand for power continues to grow, but the space available to upgrade the infrastructure doesn’t. That’s what makes a recent substation project by Consolidated Edison Company of New York so remarkable. The Mott Haven substation project is Utility Automation & Engineering T&D’s 2007 T&D Engineering Project of the Year award winner.
 The exterior of Con Edison’s Mott Haven substation blends into the surrounding Bronx, New York, architecture (page 16 and above).Click here to enlarge image |
On May 10, 2007, Con Edison energized two substations in the Mott Haven section of the Bronx, New York, that were designed, constructed and commissioned together. The project, which initially serves 40,000 customers, broke ground only 30 months earlier and includes a state-of-the-art 345-kV SF6 gas-insulated switchgear/gas-insulated bus (GIS/GIB) transmission substation, a 138/13-kV area station, 345-kV, 138-V and 13-kV transmission and distribution feeder work along with a pumping plant, two cooling plants and extensive communication work.
The $300 million dollar project was the largest substation project ever undertaken by Con Edison, and the first time a transmission station and an area station were constructed and energized concurrently.
One of the largest challenges when building within New York City is the shortage of space. Using Con Edison’s 2002 load forecasts, the need for increased capacity in the Bronx load pocket for summer 2006 was identified. An initial plan was to supply a new area station with four feeders from an existing substation. Although this would temporarily satisfy requirements, the initial plan would not provide for long-term growth in the area, and an additional transmission station would be needed in 2010. Another look at the data sent Con Edison toward the Mott Haven project, a combined transmission and area station housed together on one site.
In late 2004, Con Edison took ownership of the land for the project and began demolition of an existing structure. This phase was followed by construction by a general contractor. Over 500,000 man-hours of work later, the building was complete. To blend the structure into the surrounding neighborhood, it was built to resemble brownstone row houses. Con Edison dedicated many hours to coordinating forces onsite, with work being performed at times by more than 300 people, 24 hours a day. Sequencing an effort this large–on a limited site with an extremely aggressive schedule–was a significant construction management achievement in itself, according to the utility. Schedule and budget–as well as environment, health and safety issues–were always in mind.
Transmission street work, performed by Con Edison employees, included the installation of four 345-kV feeders tapped from existing feeders. The first area to become watertight was the 345-kV switchgear in September 2006. By November, four 345-kV gas-insulated breakers and associated bus/wiring were completed, tested and placed into service. The finished station consists of eight breaker 345-kV ring bus utilizing an SF6 GIS bus design. Four 345/138-kV 420 MVA transformers are fed from the GIS bus that energizes the area station.
Each transformer has the capability to supply four separate area stations. (The key feature of the GIS bus is that it allows the transmission station to be constructed on one-fifth the area that a conventional open-air bus would require.)
Con Edison also designed Mott Haven to account for future load growth. The final arrangement of the transmission station is a sixteen 345-kV circuit breaker double ring bus with ten 345-kV feeders supplying five 420 MVA transformers. The area substation has four 138/13-kV transformers fed from the transmission station via solid dielectric cables. The transformers then connect to eight sections of General Electric 13-kV switchgear through 4500A Calvert bus. The supervisory, control and monitoring system for the area station was designed and implemented by General Electric. The system is set up in a similar manner to the transmission station with similar principles for human-machine interface (HMI) operation, data collection, reliability and redundancy. Both the area station and transmission station are designed in a double-contingency manner so that the loss of any two pieces of equipment can be sustained on a peak load day without interruption of service.
Con Edison project engineer Steve Stroumbakis stated, “It is a privilege to be assigned as the project engineer on this huge, challenging and complex project. We had exciting times through the various stages of this project, and we engineered, designed and constructed two substations in record time, within budget, with an excellent safety and environmental record. The entire team is pleased with the end result.”
The project provided a number of benefits to the Bronx community and the Con Edison network:
- Increased capacity for load growth in the Bronx by 250 MW.
- Increased 138-kV bulk power transmission capabilities into the Bronx.
- Future expansion to supply two planned area stations in Manhattan.
- Future capability for transmission interconnections to Manhattan and Queens.
“It’s an honor to receive this award for the Mott Haven station,” said Larry Finer, substation operations project manager, after the award was presented to his team. “Particularly gratifying is that it recognizes the work of a gifted and dedicated team of individuals who worked together at the height of their talents to complete this ambitious, one-of-a-kind project.”
He added, “Even after over 30 years in the utility construction business, this project afforded me the opportunity to learn something new every day.”
Entergy, Southern Cal Edison Leading the Way in Wide-area Measurement
In many ways, the co-winners of the 2007 T&D Automation Project of the Year award are mirror images of one another. One is in the eastern interconnect, the other in the west. Both had wide-scale cascading outages as catalysts behind their development. Both provide a view of the bulk power system that is simultaneously broad and microscopic. And, both hold the promise to someday provide an early warning of and automated response to blackouts.
The similarities between the phasor measurement systems at Project of the Year co-winners Entergy and Southern California Edison are undeniable. Those similarities date right back to the origins of each project. SCE’s Synchronized Phasor Measurement System project got its start in 1995, but it was after a large-scale Western Electricity Coordinating Council disturbance in August 1996 that SCE began more aggressive research into wide-area-measurement technologies. After the 1996 event, SCE installed phasor measurement units (PMUs) at all of its major 500-kV and some 230-kV substations, enabling the utility to record data for most of the subsequent WECC disturbances. SCE currently has 19 PMUs installed in its territory, with two more set to come on-line soon.
Similarly, although Entergy had installed a wide-area measurement system in 1998 and had done small-scale research and development work with the Department of Energy on wide-area measurement, Entergy’s Phasor Project really took off after the Northeast Blackout of Aug. 14, 2003. In 2005, Entergy installed GPS-synchronized PMUs in 11 locations in its grid. On June 15 of that year, Entergy collected phasor data from a local outage, which included the richest set of phasor information ever collected. After these data were analyzed, Entergy realized the wide-ranging capabilities for phasor measurements, including the possibility of providing an early warning of pending system disturbances. Entergy has since expanded the number of PMUs installed across its territory to 22. The utility has PMUs installed in Mississippi, Louisiana, Arkansas and parts of east Texas. Entergy delivers electricity to 2.6 million utility customers in Arkansas, Louisiana, Mississippi and Texas.
Phasor measurement units like those installed at SCE and Entergy gather, store, transmit and make accessible data that utilities can use to keep T&D systems operating reliably. The devices can sample up to 120 distinct types of data values off one transmission line, and they sample that data at 30 times a second.
“That resolution of data, in real-time, is something we’ve never been able to get,” said Entergy’s senior R&D project manager Floyd Galvan.
It’s not only the richness of the data, but the instantaneous GPS-synchronized nature at which it can be gathered that promises so much potential to utilities in gaining a better understanding of system disturbances.
“Rather than having to wait several days to send out crews to collect data from the system, we can instantly–in minutes–pull data from our PMUs and begin to analyze an event,” Galvan said. “It’s opening our eyes to the system that’s all around us.”
SCE’s director of engineering advancement Mike Montoya agrees that the data provided by phasor measurement units gives a utility a much deeper understanding of how a T&D system is operating. He uses a simple analogy to describe the benefits of phasor measurement:
“We used to look at the system with X-rays; now we’re looking at it with an MRI,” Montoya said.
At this point, the systems at Entergy and SCE are primarily used for post-mortem analysis of system disturbances, but both Galvan and Montoya foresee a day when these types of systems can help provide an automated response to wide-scale outages.
“One of the most promising uses of this technology is, eventually, we’ll be able to anticipate a disturbance–an early warning system,” Galvan said. “Then, there will be an automated response to that event by the use of these phasors integrated with a control operation. If we get past the point of no return, there will be automatic islanding to minimize the event to a very small area, limiting or reducing the extent of wide cascading blackouts. Beyond that, you would also safely bring the system back together through the use of these PMUs.”
Automated system restoration through the use of phasor measurement systems is still a ways in the future. The step between pure post-mortem analysis and automated response lies in giving operators access to phasor data and educating them in how to interpret and respond to the data they see. Both utilities are hard at work on that next step in the use of phasor data.
SCE has developed an off-line analysis tool, called Power System Outlook, that uses data collected from PMUs for planning and operator training. The company has also developed a real-time operations tool SCE SMART (Synchronized Measurement and Analysis in Real Time) that provides operators and engineers with real-time (30 scans per second) synchronized data on system stress and stability. Both are deployed in SCE’s Grid Control Center.
Entergy implemented the first phasor display in its operator control center between December 2006 and June 2007. Both Entergy and SCE are currently working to educate grid operators to be able to respond to the rich set of data they have at their disposal.
“They (the operators) can see phase angles, but if they see something weird going on, they have to call Bharat (Bargava, consulting engineer at SCE) and he does the analysis. Where we want to go is where the operator knows the next step,” said SCE’s Montoya.
Galvan said a similar learning process is under way at Entergy: “A major focus right now is education of the operators and engineers. A lot of the research we’re doing is for us to understand how this technology can help us, so we can monitor the system and give the operators the actions they need to take [when a disturbance is detected].
“We have a great deal to learn,” Galvan continued. “We need more PMUs on the grid. Seventy across the whole Eastern Interconnect isn’t going to cut it. We need hundreds more.”
Besides the need for a greater density of phasor measurement units, Montoya and Galvan both agree that much more research and education is needed to tap the full potential of phasor measurement. Both SCE and Entergy are working to make sure that education takes place by spreading their wealth of knowledge across the power industry. SCE has freely provided its Power System Outlook application to electric utilities, independent system operators and universities to encourage the development of advanced technologies.
Similarly, Entergy is working with the Power Systems Engineering Research Center and Washington State University to deploy the industry’s first wide-area early warning system for instability anomalies using phasor measurements. Entergy is working with universities to incorporate event triangulation for loss of generation and transmission. Galvan and Entergy are also sharing the information they’ve gathered with the rest of the industry in the form of papers and presentations.
“Phasor technology is changing the potential for advanced grid measurement and management through wide area monitoring,” Galvan said. “We are committed to sharing best practices to ensure this technology will improve not only our own transmission and distribution systems, but also the North American power system as a whole.”
By working with leading-edge technology to ensure reliability of their own bulk power systems, and for sharing their knowledge for the betterment of the entire North American T&D system, Entergy and Southern California Edison truly embody the characteristics the Projects of the Year awards were established to honor.
Ontario Utilities Band Together to Meet AMI Requirements
The AMI Project of the Year Award was taken home not by a single utility, but by a group that came together to push through a very forward-thinking project–the Coalition of Large Distributors, who worked very quickly to advance Ontario’s Smart Metering Initiative.
Ontario is home to one third of all Canadians, and the province is facing a critical energy shortage–both in the short term and long term. With no new major generation under construction, rapid economic growth and the threat of rolling blackouts, the Ontario government has taken aggressive steps to develop a conservation culture in Ontario. One of these steps included Ontario’s Smart Metering Initiative (SMI), which began in 2005.
The goal of the SMI is two-fold: (1.) to enable customers to be billed at rates that reflect the true time-sensitive cost of energy, and (2.) to provide the incentive to reduce loads during peak periods. To further these goals, a provincial high-level advanced metering infrastructure (AMI) guideline was developed, requiring the collection of hourly data at every meter point and making that information available to each and every consumer the following morning.
The Ontario government set targets:
- 800,000 meters to be installed by the end of 2007,
- A total of 4.5 million meters by the end of 2010,
- A smart meter on every home and business.
All that was missing was an actual plan to achieve this massive undertaking.
Ontario is a deregulated province, served by more than 90 utilities covering a vast and diverse demographic and geography. Mobilizing all these utilities to do something that had never been done–on this scale to meet these targets–was a major undertaking. Throughout 2005 and 2006, a number of utilities started pilot projects across the province to explore various AMI technologies, but these pilots would not likely have met the looming target of 800,000 installed meters by the end of 2007.
Rather than sit back and wait for further directions and clarification of regulatory rules, Ontario’s six largest utilities took the initiative and formed what is known as the Coalition of Large Distributors (CLD). The Ontario CLD consists of:
- Enersource Hydro Mississauga Inc.,
- Horizon Utilities Corp.,
- Hydro Ottawa Ltd,
- PowerStream Inc.,
- Toronto Hydro-Electric System Ltd, and
- Veridian Connections Inc.
Together the utilities represent one-third of the province’s meter population. Despite competitive interests inherent in a deregulated environment, the CLD worked together at an unprecedented pace. While doing their own individual AMI technology trials with various vendors, they developed a comprehensive specification that would meet the requirements of Ontario’s Smart Metering Initiative. The specification was then issued to the AMI community. Under the guidance of a government fairness commissioner, the CLD team members sequestered themselves to undertake what was a massive evaluation process. As the largest AMI initiative in the world, vendor response was enormous. Collectively, the CLD identified five vendors of record, any of which each utility could contract with to meet their requirements. Ultimately, five of the CLD members elected to work with a single vendor, Elster Metering. Working in concert they were able to aggregate their meter requirements and maximize buying power to minimize cost to the consumer. Individual contracts with the vendor were negotiated to get things moving. But, the work wasn’t complete yet. Now the task of deploying 800,000 meters over about a 12-month window lay ahead.
Each utility worked to develop new automated installation processes required for such a massive effort. Billing systems were modified, and people trained to handle the AMI deployment. One of the CLD utilities, Toronto Hydro-Electric System Limited, challenged its own staff to begin installing 5,000 meters a week. Other CLD utilities hired contract installers.
As the group approached the end of 2007, the CLD had installed more than 800,000 meters alone. Furthermore, they encouraged other utilities to “piggyback” on their buying power, ensuring the province easily met its target. The CLD members have successfully exceeded the government goals in record-breaking time. In addition, they are currently bringing in hourly interval data from more than 500,000 endpoints daily.
In the end, Elster was selected to deliver its EnergyAxis System AMI solution and over 800,000 EnergyAxis meters to five of the six CLD utilities over an 18-month period, exceeding the Smart Metering Initiative’s target.
Jack Robertson, vice president of Elster Metering stated, “The milestones and pace achieved by Ontario’s CLD in 2007 make it the largest two-way mesh network AMI project in the world using smart meters to retrieve hourly interval data.”
“I was truly honored to receive the AMI annual award and accepted it on behalf of my amazing team that has installed over 420,000 smart meters and are transmitting data to 50,000 customer through the web,” said Susan Davidson, senior vice president, customer services, for Toronto Hydro-Electric System Limited.
She continued, “Our next milestone is to prepare customer bills on a time-of-use basis in 2008.”
Caifornia ISO Uses Google Earth to Visualize Grid Conditions
The California ISO’s job is not an easy one. The ISO is charged with ensuring the safe and reliable transport of electricity on the California power grid. Its control area includes more than 80 percent of the state’s total electrical load and serves more than 30 million residents. More than 90 transmission companies and generators participate in the ISO markets. What makes the ISO’s job even more difficult is the fact that transmission lines in California often operate at near congestion capacity.
But for every challenge there is a solution. Beginning April 10, 2007, the ISO began implementing technology that lets them visualize transmission line congestion in 3D on top of satellite imagery that shows natural events like wild fires and hurricanes as well as system outages. The innovative technology garnered the California ISO Utility Automation & Engineering T&D’s 2007 Geospatial Technology Project of the Year award.
Using a product called MAGMA from Enterprise Horizons, the Cal-ISO combines data from SCADA systems, weather data, forecast data, substation load data and wild fire information, to get a theatrical, time-animated, 3D view of congestion and consumption on the grid utilizing Google Earth.
The Cal ISO implemented this system in just over four months, going live in mid-August 2007, and it’s helping them ensure electrical demand is met around-the-clock for consumers and that reasonable wholesale costs are fostered. It also proved valuable during wildfires that occurred in Southern California during the fall of 2007.
Wildfires can pose a significant threat to the high-voltage transmission lines that the California ISO oversees. Knowing where a fire is burning in relation to the lines is critical. The California ISO used this new technology to merge four different information sources into one composite display to help manage the grid during fires. Google Earth’s satellite mapping system is overlaid with data that shows precisely where transmission lines are located in California. The system then blends in weather data–including temperature, humidity, wind speed and direction. The final piece is real-time information from California fire services that pinpoints active fires.
“With all four information streams merged onto one screen, we know where a fire is, how close it is to our lines, and we have a pretty good idea of how fast it’s moving and in what direction,” said California ISO director of grid operations Jim McIntosh. “Our guys put this together over several months last spring and it really helped during the Southern California firestorms in October (2007).”
The fires in Los Angeles and San Diego forced outages on several key transmission lines. The Southwest Power Link running between Arizona and San Diego was out for several days and other lines were also tripping in and out of service on a minute to minute basis due to smoke, soot and ash that can foul the insulators. “It was absolutely imperative to have good information about the changing threats to the lines that were still in service,” said McIntosh. “The system we developed delivered the information we needed to decide how to manage power flows and even to request fire retardant air drops in critical locations to protect threatened lines. It helped us keep the lights on.”
Several California ISO employees share the credit for developing the system; lead operations support specialist Steve Gillespie, operations support specialist Brian Murray, and from the Information Technology group, critical systems lead Eric Mscichowski, senior engineering specialist Devin Miroy, senior engineering specialist Jim Hiebert and engineering specialist Tim Willenberg.
