BOSTON

...delivery. The West needs more points of sectionalization, more substations, on its lines, Mundy says. But transmission investment increasingly will go into technologies to improve efficiency. "The U.S. system has reduced 2.5% of summer peak demand�20,000 MW�via direct load control," says Arshad Mansoor, vice president of power delivery and markets in Knoxville, Tenn., for the Electric Power Research Institute. "Now you see the focus on advanced metering and high-speed Internet," he adds. These technologies would allow utility system operators to communicate directly with electric fixtures and appliances to turn down lights and manage demand, with prior customer agreement, via the Internet. So-called IP-addressable dimmers and IP-enabled appliances "are Websites," says Mansoor. "We can use technology to manage our demand more effectively."

Improving operating efficiency on the grid can have the beneficial side effect of reducing carbon-dioxide emissions�and not just through the direct saving of power not consumed, notes Mundy. Generating and delivering power entails inherent losses of energy in the form of heat from boilers, turbines, transformers, conductors and other system components. "You have to generate the lost energy in addition to what's used," he says. "If you control the loss, you don't have to generate." Down the road, utilities that do add transmission lines will maximize the use of existing transmission corridors. Advanced conductors using composite cores instead of steel cores will carry more current with less sag than conventional conductors widely used today. The new conductors allow higher operating temperatures, Mundy notes. "You pay a price for that," he says. "You have to take the line out of service" to replace the conductor.

Utilities also will replace conventional cables with high-temperature superconducting cable, which carries more current on fewer and smaller cables than the old ones, without "line loss" of transmitted power. These technologies already are being installed and planned in demonstration projects around the country.

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Electric Power Research Institute Integration of smart grid's power and communication systems allow utility to avoid power shortfall. 1. System operator integrates weather data from sensors on grid and calls for load curtailment and surplus generation. 2. Energy service provider communicates curtailment request to customers. 3. Industrial customer chooses temporary shutdown in response. 4. Commercial customer shifts to onsite backup generator, sells power back into grid. 5. Residential customers' programmed portals respond by trimming demand.

Responding in real time to line conditions as they develop is another research focus. A family of EPRI products known as Dynamic Thermal Circuit Rating (DTCR) technology will allow transmission operators to increase power flow of overhead lines because they will have accurate, current data on line conditions. Design assumptions of ambient conditions for transmission lines are normally conservative, leaving a sizable margin of unused capacity as a cushion for safe operation. With accurate, current data on line and ambient temperatures, sag and other conditions, operators can deliver power at rates closer to the design capacity. The video sagometer is one tool in the DTCR bag. An image-capture and processing unit mounted on a transmission structure monitors the position of a target attached to the conductor, interrogates the image at fixed intervals and sends the line operator precise information about the line's sag or ground clearance. This information allows the operator to adjust power flow as necessary for safe and optimal line operation.

DTCR software is used to process the data from equipment such as the video sagometer into information on which the operators can act. The output can be incorporated into SCADA operating systems. EPRI has developed it since initiating the project in 1993, and more than a dozen utilities throughout North America have tested and improved it. The software now is used for both overhead and buried conductors.

Advanced sensors also will allow more efficient line operation. RFID-based sensors have been in the laboratory for four to five years and now are going to the field, says Mansoor. The RFID tag, a "backscatter sensor," operates similarly to an E-Z Pass toll booth, he says. "The norm today is manual inspection," but a backscatter sensor mounted on a tower, insulator, wire, clamp or splice can be interrogated by a fast-moving truck or helicopter for data on temperature, current and other operating conditions, he says. It won't put the lineman out of work, only give him new tools, he adds. FirstEnergy Corp., Akron, Ohio, and New York Power Authority are using the video sagometer and both are planning to install a backscatter sensor for temperature measurement in the near future, Mansoor says.

The Tennessee Valley Authority has pioneered sensor technology. Mansoor calls a substation at TVA's Paradise coal-fired generating plant "the first living laboratory for advanced sensors." Terry Boston, TVA executive vice president of power systems operation, says wet scrubbing of emissions at the "fairly remote plant" in western Kentucky produced condensation on insulators and led to flashovers. Sensors enabled the operators to identify the location of the leakage currents. The station was able to respond promptly and dry off the insulators, he says.

Sensors called phasor measurement units (PMUs) use time-synchronized GPS clocks to compare phase angles of the grid from location to location, Boston says. Boston was on the international commission that investigated the 2003 blackout and says one of the most onerous chores was to establish the blackout's chronology by synchronizing the clocks of the different utilities in the areas around the point in Ohio where the triggering events occurred so the investigators could reconstruct the events. PMUs, recording 30 samples per second, would allow more precise synchronization than standard SCADA, which records at intervals of two to five seconds. "It's kind of like what MRIs did for medicine, compared to X-rays," he says.

Synchronized phasor measurement tools are the focus of one U.S. Dept. of Energy research and development project. DOE is working with independent system operators to demonstrate region-wide sharing of real-time information from phasor measurement technologies. DOE's Pacific Northwest National Laboratory is leading R&D for phasor technology in concert with several industry organizations.

TVA's Bradley substation, under construction in Chattanooga, is "probably the most sophisticated," Boston says. The monitoring system for the transformers, circuit breakers and other equipment is built in to bring the data into operation and maintenance staffs. The 500/161-kV station will be online next summer.

Sources agree that the 2003 blackout prompted many efforts to strengthen reliability. But utilities and researchers have talked for years about the "smart grid," or "intelligent grid," which would incorporate these technologies. "Utilities want the intelligent grid to be self-healing," says GE Energy's Lecours.

But definitions are loose. "The smart grid is in the eye of the beholder," says Mansoor. He defines it broadly as sensors and a communication backbone. The investment required on the distribution side, consisting largely of replacing customers' conventional meters with advanced meters that allow Internet communication, will be comparable to the investment for transmission growth, he says. Communication can be wireless or via broadband over power lines; either medium is good. "There's no right answer, and there shouldn't be any right answer," he says.

Every utility already has some elements of the backbone in place in telephone and fiber-communication networks, says Lecours. "Going forward it will be more of a hybrid," he adds. That means combining fiber and radio frequency with power-line carriers and more devices along the last mile. It will be a big integration job, he notes. "Utilities are approaching the point where a piecemeal upgrade [with smart meters and similar equipment] is too costly," says Lecours. "They are reaching the point where they need a system-wide integrated upgrade."

This trend has been evident, especially in the last six months, Lecours says. "The utilities used to say, 'OK, we get it.' Now they say, 'We want to know more, and how can we move forward quickly?'"

The common denominator in the developing trend is IT expertise, Lecours says. GE sells GIS to IT for distribution and operation management systems. "The IT community is challenged to have a more global solution. The push is for openness and standardization," as opposed to proprietary systems from vendors, he says. The key to succeeding is backward compatibility of systems to integrate them with what's in place.

Lecours cites automated meter-reading equipment as an example. Vendors were selling proprietary systems, but in the last three years, utilities have called for the ability to leverage the data for outage management. Where outage management traditionally took calls and plotted the source of an outage, meters now will alert the control room to identify a source. But as desirable as such systems are, immediate, wholesale deployment is not an option, Lecours says. Utilities want to invest in the right smart device, the right communication infrastructure and a whole IT infrastructure to support the data inflow. "Utilities have to modify their business case to bring data into the utility," he says. The lack of communication standards also hinders smart-grid development. The utility system still operates with 152 different communication protocols, notes Clark Gellings, EPRI vice president of innovation.

This summer, the North American Electric Reliability Corp., Princeton, N.J., passed a milestone in the industry's efforts to assure reliability of the grid. On June 18, compliance with NERC Reliability Standards for planning and operation of the bulk-power system became mandatory and enforceable under federal law. Since its founding following the 1965 Northeast blackout, NERC has established reliability standards, but compliance with the industry-based organization's standards was voluntary. The Energy Policy Act authorized the creation of an "electric reliability organization" with federal enforcement powers. NERC was certified as the ERO in July 2006 and assumed full authority of the role in June.

That development has kicked off "a tremendous review" within utilities to make sure they are compliant, says David Whiteley, NERC executive vice president. "They are reporting back with plans for compliance and dates." NERC's authority is restricted to ordering performance goals for the grid. The ERO cannot order construction of a specific transmission line or device. But implementation of technology to modernize the grid, such as demand-side management and "smart" applications for operation, tops Whiteley's wish list for assuring reliability. "That's more significant than putting in more wires," he says, while admitting that more transmission is required in some places.

Investment in the last five to six years increasingly has flowed into advanced technologies for automation, advanced power electronics and more intelligence in system control and communications, says Gregory Reed, senior vice president of power-system planning and management at KEMA Inc., Burlington, Mass. The U.S. grid as a whole remains robust and reliable, but "it varies regionally around the country," says Ralph Masiello, KEMA senior vice president of energy systems consulting. "Where the population is flat or declining, infrastructure tends to be in worse shape," he notes. "The coupling of deregulation and rate freezes will cap distribution monies." These trends have affected parts of New England as well as some other regions, he says.

Southern Co., Atlanta, has racked up $2.3 billion in transmission and substation capital investment over the last five years and plans to invest $2.7 billion more, says Billy Ball, senior vice president of transmission planning and operations. "There's really not been a lack of transmission investment" in the South generally, says Ball. Industry restructuring never took hold in the region, so "there has not been a period of questioning about how do you get cost recovery and how do you get accountability," he says.

Much of the investment has gone into new wires and stations but also into upgrades and improvements to increase throughput using larger conductors, advanced conductor designs and cutting-edge substation equipment. In March, Southern Co. demonstrated a new technology developed in-house with DOE co-funding. It consists of software to query, retrieve and analyze powerplant data to determine generator reactive power reserves. Reactive power is power generated to maintain system operation, not for delivery to a customer. As with other technology solutions, Southern's GenVARR technology will allow more efficient system operation by providing operators with precise measurements of the operating conditions of their systems.

In the last year, public awareness about global warming has risen, and KEMA's Masiello says the climate trend already is affecting the grid. "Hot spells have stressed the system, and it doesn't cool in the evening," he says. Pole-top distribution transformers heat up in normal operation. "If they don't cool, you get a rash of transformer failures," he says. "That's an early indicator of what global warming could mean."

Changes in electricity consumption also are stressing the system, adds KEMA's Reed. "Load profiles are flattening at a higher level with more direct-connected energy resources," such as distributed generation, photovoltaic installations and, soon, electric vehicles, he says. "That will keep the system at higher load during normal low-load periods."

These changes aren't right around the corner, Reed says. But they could affect the grid "in the next 10 years, if not sooner," he adds.