Brad Roberts, S&C Electric Co.
The concept of storing electricity generated in a utility grid has been tried since the beginning of the power industry. In the U.S., large-scale storage projects flourished in the 1960s, “Ëœ70s, and “Ëœ80s as utilities added 18 GWs of pumped hydro facilities to support the rapid build out of the fleet of nuclear power plants across the nation. Nuclear plants run best at higher power ratings, so pumping water in these hydro plants presented ideal off-peak loads during nights and weekends when customer demands are lowest. This method of grid storage has been improved during the past two decades, and today these plants provide more than 2 percent of the total capacity of the national grid.
Now, as the grid faces a rapidly growing component of renewable energy sources (wind and solar), the job of balancing generation sources and load demands is becoming more challenging. With most regions of the U.S. trying to achieve renewable portfolio standards (RPS) of 20 to 30 percent in the next 10 to 20 years, stable and reliable control of grid voltage will be a bigger task for utilities and system operators. Utilities and regulators know they must deal with this, and major changes are in the works. The biggest steps started in 2009 with massive stimulus investments by the U.S. Department of Energy (DOE) to accelerate the development of smart grids throughout the nation. Demonstration projects totaling more than $1.6 billion were announced with implementation occurring in 2010 and 2011. The projects cover every aspect of smart grid technology, from intelligent meters in homes to automation of distribution circuits to energy storage devices such as flywheels and batteries at different levels of the distribution network.
Battery Power in Substations
Starting five years ago, American Electric Power (AEP) took the lead in determining the value of adding fairly large amounts of battery energy storage in substations. The distributed energy storage system (DESS) approach was used to test peak load management and improvement of system reliability by deploying systems in sizes of 2 MW with seven hours of support time. Figure 1 shows one of the systems installed in an Ohio substation.
|System Installed in Ohio Substation|
Battery systems like the one shown in Figure 1 provide a new alternative for utility power management in a distribution substation. By having a fixed amount of clean peaking energy in the station, a utility can delay capital upgrades by several years and provide reliability improvements to customers served from that station. In the example in Figure 1, a 2-MW sodium sulfur (NAS) battery is used to support hundreds of homes and businesses connected to many miles of distribution circuits. Should the transmission line feeding this station experience an outage, the customers have power restored when the station automatically runs in an islanded mode using battery energy to power the customer loads. Any problems downstream of the battery, however, can be fixed only by dispatch of repair crew. If a limb falls on an overhead line, some customers will lose power. In addition to losing power, the issue of load growth must be addressed, and eventual upgrades of circuits are planned based on load forecasts. Dealing with ways to continually improve service reliability and load growth led AEP to tackle placing energy storage closer to the edge of the grid where power is finally delivered to customer meters.
Community Energy Storage
The term community energy storage (CES) defines an approach where smaller packages of battery energy storage, typically 25 kW with one to two hours of back-up time, are deployed in neighborhoods on street corners or along backyard utility rights-of-way. Figure 2 shows a depiction of a CES unit of this type adjacent to a standard utility transformer feeding six to 10 customers.
The CES units are connected on the low-voltage side of the utility transformer and protect the final 120/240-volt circuits to individual customers. Placing a utility-controlled device at the edge of the grid allows for the ultimate in voltage control and service reliability. Meeting this challenge of even greater control of voltage at the point of customer use is a major departure for traditional utility system control philosophy, but it’s needed to deal with a rapidly changing customer load profile. While customers are adding more sophisticated electronic loads (computers, appliances, etc.) requiring greater service reliability, new, even larger loads—such as plug-in hybrid electric vehicle (PHEV) charging units—will be added randomly in the grid. On top of these changing load patterns, more solar arrays on rooftops will introduce a growing amount of energy flowing back into the grid when solar generation exceeds the power demand of the specific customers. Today, a neighborhood with a significant number of solar roofs can generate a fair amount of energy that dissipates back into the utility network during the solar peak period, which precedes the customer load peak by two to three hours each workday. CES units located throughout the network would allow that excess energy to be captured locally with less line losses and re-dispatched back to the same customers when needed. Another problem the CES units could deal with during the solar peaks is precise control of the local voltage as clouds pass over. As more customers add solar, the voltage can be impacted as clouds pass by. As clouds shadow a large number of arrays, the power output drops quickly and results in sudden voltage drops. The power electronics used in the CES devices have the ability to act as an instantaneous capacitive volt-ampere reactive (VAR) compensator to maintain proper voltage in the local area. The sun can re-appear quickly and result in the voltage’s attempting to rise fairly rapidly. The CES electronics would counter this the same way as a reactive VAR compensator to prevent a voltage sag.
The addition of more PHEV loads will affect load demands. Most vehicle charging should occur slowly at night, but the pattern will be hard, if not impossible, to control. If an abnormal amount of quick charges were to take place in a given area, there could be stress on local distribution transformers.
Utilities have tended to oversize these small distribution transformers to control voltage and compensate for the starting inrush current of air conditioning compressors in homes and prevent resulting voltage flicker. Having extra utility capacity available in local CES units will alleviate this contingency. There will be even greater dynamics in local distribution circuits. The solution will be truly smart grid where improved load management will start to occur with smart meters and better-educated consumers caring more about energy consumption. Eventually, CES units might communicate directly with meters in each home and advise customers of any abnormal condition in their local network and provide a recommended action in their own use of power.
Controlling Power on the Edge
The CES concept is only possible because of tremendous advancements in remote-control capability coupled with newer power electronics and advanced battery technologies. Utilities are accustomed to managing vast networks with many electrical distribution boxes installed in thousands of uncontrolled locations next to end users. In a typical utility grid, the supervisory control and data acquisition (SCADA) control devices stop at the substation and few devices beyond that point are monitored from the central control facility. Optimizing the performance of many CES units requires new control and communications techniques.
Figure 3 depicts how a local area network of CES units will be integrated into the grid. Functionally, these units will communicate by radio, and their performance will be controlled by the utility. Their combined outputs can be aggregated into the utility’s advanced metering infrastructure (AMI) or directly from the local SCADA control at the nearest substation. In this fashion, 80 CES units distributed in a local grid could provide the same functionality as the 2-MW substation battery shown in Figure 1. The CES approach would provide a more effective solution by relieving overloads in the branch feeders and provide better protection from outage, including the ability to communicate specific locations of customer outages, which would minimize service crew response time.
|Local Area Network of CES Units|
Continual improvement in lower-cost, wide-area communicating will help make the deployment of thousands of CES units possible. Another potential benefit that should help is that CES battery technology is almost identical in power range to the batteries being deployed in PHEVs. Mass production of batteries will lower the cost for both applications.
The CES concept will be tested extensively in 2010 and 2011. The DOE energy storage and smart grid demonstration stimulus contain two projects that should deploy more than 200 CES units in the next two years. A small demonstration project in Australia has been initiated as well, plus numerous utilities worldwide have expressed interest in the CES concept as a part of smart grid development. Taking control of utility power to the edge of the grid is the next logical step.
Study Finds Increased 2010 CAPEX and O&M Budgets for Smart Grid Tech
Initial findings from the January 2010 Newton-Evans global tracking study of electric power transmission and distribution investment are somewhat positive, compared with the most recent tracking study (July 2009). Each of five smart grid component areas, plus transmission and distribution infrastructure development, has been reported by utilities located in more than 25 countries to more likely be “increased” or “unchanged” rather than “decreased” from January of last year.
The highest percentages of officials reporting increases were in protection and control and transmission infrastructure CAPEX budgets. The biggest decrease in CAPEX outlays for 2010 is reported to be in distribution infrastructure, based on the first 50 replies received and tabulated.
O&M budgets reflect a different story. Most categories of O&M spending were less likely to see an increase from the budgets of a year ago. Distribution appears to be the key victim, with 17 percent of the respondents indicating a lower figure budgeted for 2010 O&M expense or distribution network operations and engineering. The survey also requested that utility officials provide the reasons for their CAPEX plans, looking into the rationale for change in year-over-year budget plans. In summary, smart grid initiatives were cited as being more important factors than regulatory mandates or government stimulus programs.
Likewise, decreases in CAPEX budgets were reported to be caused first by the economic outlook for 2010, a more important factor than regulatory mandates. With the recent example of Florida Power & Light Co. pulling back some $10 billion in multiyear CAPEX spending because of unfavorable regulatory decisions, however, these can become influential in states with key rulings this year.
More information on this report and others by Newton-Evans Research may be found at http://.newton-evans.com.
EYE ON EUROPE
ENTSO-E Releases System Adequacy Forecast 2010-2025
The balance of electricity generation and demand in the European power system should not be at risk up to 2020 thanks to current and ongoing investments, according to a recent report from ENTSO-E, a European transmission system operator association. Without additional investments, however, the margin between generation capacity and demand could begin to narrow from 2015. European generation capacity would then have to increase by about 70 GW by 2020 to maintain current margin levels.
|Average annual energy consumption growth rates 2010-2015|
Meanwhile, the electricity consumption growth is foreseen to accelerate after 2015. Energy demand would reach about 3,700 TWh by 2015 and possibly more than 4,300 TWh by 2025. Highest growth rates are expected in eastern and southern Europe (see map). Despite much progress in energy efficiency, the small positive growth rates for electricity demand are foreseen because of more electric devices in households, new uses of electricity in industrial production and services—and especially in the later years because of technology and policy developments shifting some current oil and gas uses to electricity at overall improved energy efficiency (such as heat pumps and electric vehicles).
ENTSO-E became fully operational in July 2009, replacing six predecessor European transmission system operator associations. More information is online at http://entsoe.eu.
Governing Board of Smart Grid Standards Panel Announces Officers
The National Institute of Standards and Technology (NIST) launched the SGIP in November to sustain and coordinate development of interoperability standards for a modernized electric power grid. McDonald is general manager of marketing for GE Energy’s transmission and distribution business and an IEEE Fellow.
The unanimous choice of governing board members, McDonald will serve as the board’s chief spokesman and will have primary responsibility for organizing its meetings and activities. As required by the SGIP bylaws, McDonald’s selection to lead the board was confirmed by George Arnold, NIST’s national coordinator for smart grid interoperability.
The board also chose John F. Caskey, senior director of the Power Equipment Division at the National Electrical Manufacturers Association, to be vice chairman and George Bjelovuk, managing director for marketing, research and program development at American Electric Power, to serve as secretary. All three officers will serve one-year terms.
NIST established the SGIP, which now has more than 450 participating and observing member organizations, to help it fulfill its smart grid responsibilities under the 2007 Energy Independence and Security Act.