Advanced metering infrastructure and intelligent appliances are opening the door to a new market for utility services. But in-home services are a completely different ball game. Going beyond the...
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override the remote control. The availability of these PCTs is tied directly to the explosion of smart meter programs throughout North America that use a standard wireless Zigbee radio chip to communicate from the utility-owned smart meter to customer premise devices. These home area network (HAN) solutions leverage the Zigbee radio and smart energy profile message standardization to enable communication with PCTs, in-home displays (IHDs) and customer energy management solutions. The incremental cost of the imbedded radio chip and the end-to-end solution is a relatively small part of the overall project cost, but has significant implications for enabling a truly system-wide and eventually continent-wide demand response solution.
While this demand response capability offers benefits for normal system operations, regardless of generating type, its potential value increases as the dependability of the generation sources decreases. DR can be thought of as a negative load or a pseudo-generation source, and depending on its cost and the rules under which it’s called, the DR resource can be used to balance unexpected or sudden reduction in overall system supply, or can be scheduled when there’s a high likelihood of forecasted shortages—for example in summer months in the Southwest, when conditions are easily identifiable for potential shortage conditions. Advance customer notification and preparations can contribute to the impact. Numerous studies of the results of DR programs have shown a per-customer potential load reduction of up to 1.4 kW when the primary appliance is an A/C unit.
A challenge facing many of the demand response programs being deployed today is that they are operated as stand-alone solutions, dispatched as economics or reliability requirements are defined in the energy control centers of the utilities or the regional independent system operators (ISOs). For the modern distribution grid, the next step forward will likely entail integrating a distribution management system (DMS) with a demand response system. This will allow the DMS to do load forecasting, distribution generation forecasting, take inputs from the load control authority and decide when to invoke a given DR program on a specific area of the distribution grid. This integrated approach allows the DMS to measure instantaneously how effective the actively running DR programs are at shedding the anticipated amount of load, and allows the distribution operating company to safely operate the distribution grid during peak loading conditions without having to coarsely shed load at the substation or feeder level, which might contain valuable DG resources. The integrated DMS-DR-DG approach also allows the distribution company to optimally reconfigure systems to support short-term anomalies as well as anticipated longer duration changes in either load or generation, based on forecasts.
Emerging DMS Technologies
State-of-the-art DMS, coupled with system-wide communication networks, are transforming how utilities operate their distribution networks. The DMS applications can aggregate load and status information, access current state electrical models, run real-time power flow studies, and remotely engage generators or call load shedding solutions. The goal of the DMS implementation is to migrate the operation of all aspects of the grid from isolated, highly interactive processes into an integrated, proactive and automated solution set (see Figure 2)