A Useful Thing Happened on the Way to the Smart Grid: An Agile Grid, Part 5

Stephen Hadden | Aug 31, 2010

When Will the Smart Grid Be Available?

The concept of an intelligent electric utility infrastructure or "smart grid" is attracting wide interest among utilities, consultants, regulators, and other utility stakeholders. This interest, however, is accompanied by widely differing expectations about when the smart grid will emerge. Some confidently proclaim that the smart grid is here or "just around the corner." But utility management and staff responsible for operating real electric systems are understandably cautious. They realize that the smart grid will not suddenly become available in a suite of closely bundled technologies and applications. And they are pragmatic about the technology needed today to improve distribution operations for the next few years.

We Can Make the Grid Smarter Right Now

The concept of intelligent infrastructure will continue to evolve, but utilities have tangible choices now, and they do not have to wait passively to provide practical solutions as the smart grid develops. Utilities can begin using existing and emerging technologies and applications to create something we call an "agile grid," on the way to creating a smart grid. Many utilities already have deployed, or are planning, key elements or components of an agile grid. There are numerous examples of these technologies and applications that can be part of the agile grid. Some of the most common involving Advanced Metering Infrastructure (AMI) are illustrated in Figure 1 below. Several examples explaining how AMI can be used to better leverage these other technologies and applications have been the subjects of past articles in this series. However, in this article we discuss just one: using AMI with supervisory control and data acquisition (SCADA) to implement and operate a conservation voltage regulation (CVR) program enhanced by employing distribution efficiency improvements -- known as Voltage Optimization (VO).

Voltage Optimization

Standards of the American National Standards Institute (ANSI) require that most utilities provide voltage levels no lower than 114 Volts and no higher than 126 Volts at customers' meters during normal operating conditions. Utility staffs have traditionally achieved this by programming the utility's substation transformer load tap changers or voltage regulators and down line regulators and capacitors to maintain voltage in the upper part of the ANSI voltage range. This avoids low end-of-line voltages at customers' meters during peak load conditions. In other words, utilities have designed their distribution systems for peak load conditions and set regulated voltage levels accordingly. This operating practice, however, may result in voltage levels in the upper part of the ANSI voltage range during off-peak times.

VO is a concept to reduce demand, reactive needs, and energy by improving the efficiency of the distribution system and maintaining distribution voltage levels in the lower part of the ANSI voltage range. Voltage reduction has traditionally been used exclusively by some utilities as a peak shaving tool. However, VO is increasingly seen by utilities and some regulatory authorities as part of a broader energy efficiency strategy. By performing cost effective system improvements, a utility can achieve 0.5 to 1 percent additional demand and energy reduction where most of these additional savings are on the utility side of the meter in the form of loss reduction. For example, a voltage reduction in the 1 to 3 percent range may yield roughly the same reduction in demand, reactive needs, and energy on both sides of customers' meters. The actual size of the demand reduction, however, depends on the types of loads controlled, the load mix, and down line voltage regulators and capacitors.

A variety of voltage control schemes has been used to monitor distribution loads and change the voltage level settings on substation voltage regulators or transformer tap changers as needed to maintain voltage levels in the lower part of the ANSI range. Today, many utilities have communication interfaces on their substation voltage regulator or transformer load tap changer controls, enabling system operators to use SCADA to download new bus voltage set-points and send step level voltage reduction signals. However, relatively few utilities use CVR except as a tool to perform load reductions during system emergencies.

Staffs at many utilities are reluctant to use VO as an ongoing load management or energy conservation tool because they perceive the disadvantages of VO outweigh the advantages. One disadvantage cited by utility staff is that it might affect the quality of power to the customer, or it might make the distribution system more susceptible to voltage flicker. Either of these might require significant capital investment in distribution improvements before implementing and operating a successful VO program. Utilities should perform a detailed per-phase analysis of their distribution systems to calculate anticipated voltage levels throughout the distribution at various load levels and substation voltage settings before implementing a VO program. Some distribution improvements may be required anyway, such as re-balancing of per phase loads, capacitor additions to improve power factor, and local improvements like correcting overloaded distribution transformers, secondary, and service drops. Also, VO may not be practical under all load or voltage reduction settings. But significant savings may nonetheless be achievable with small voltage reductions in the 1 to 3 percent range. For example, distribution transformer no-losses will be reduced by the square of the change in voltage so a very small reduction in voltage will have a significant impact on the transformer losses.

A second disadvantage cited by utility staff is that distribution studies used to evaluate a proposed VO program represent only a snapshot based on a variety of modeling assumptions. Utility staffs are concerned that implementing VO may cause voltage levels at some customers' premises to fall too far below ANSI minimums and possibly damage customers' appliances, lamps, or other equipment. So, utility staffs are understandably reluctant to implement CVR unless distribution voltage can be monitored throughout the distribution system. This can be mitigated by performing system studies, performing system improvements, and installing low cost end-line metering.

Some equipment vendors mitigate these concerns by marketing VO systems that monitor substation loads and use line voltage measurements as control-loop feedback via radio from sensors installed at desired distribution points. These closed control-loop VO systems provide utilities an important and productive option, but these systems will not satisfy utility staff anxious about voltage levels at other distribution locations as load and circuit switching configurations change throughout the day or seasons of the year. Also, these systems require additional capital investment ($250,000 to $400,000 per substation) for the controller, voltage sensors, and radio communication.

AMI Improves Agility of CVR

AMI can help utility staff implement and monitor a VO program for load management or energy efficiency without adversely affecting customers. "Smart meters" at customers' premises are capable of monitoring voltage levels and using the two-way communication capability of AMI to send an alarm to the AMI master station if voltage excursions occur outside a desired range. AMI voltage reports available from all customers' meters and alarm data, if any, provide system operators useful feedback on voltage conditions throughout the distribution system. System operators welcome this information when they use SCADA to monitor distribution substation loads, download new voltage set-points, and send step-level voltage reduction signals to substation voltage regulators or transformer tap changers. System operations can modify or tailor the amount of voltage reduction based on voltage level feedback they observe from all customers' smart meters as load and switched configuration of circuits change throughout the day or seasons of the year. This approach is illustrated in Figure 1 below.

Figure 1: System operators can implement CVR by using voltage information from AMI and SCADA or DA to adjust voltage settings as needed on regulators, capacitor banks, or transformer load tap changers.

Using AMI and SCADA to implement, monitor, and control a VO program provides utility staff several advantages:

  • VO may be implemented to reduce peak load demand, or to maintain distribution voltage levels in the lower part of the ANSI range as part of a broader energy efficiency strategy.

  • Smart meters may be remotely programmed with a variety of low-voltage alarm threshold values, enabling system operators to tailor VO to individual distribution substations and feeders. Also, system operators may "ping" individual meters to closely monitor voltage levels at specific locations.
  • AMI systems can identify specific problem areas that are limiting the amount the voltage can be reduced. By fixing these low voltage areas the entire substation system will benefit from the additional voltage reduction.
  • Many system operators may be more comfortable implementing VO in measured voltage reduction steps and using AMI to monitor the distribution system for signs of low-voltage problems. (This is why we illustrate this iterative process as a bold dashed line in lieu of a solid arrow depicting software interfaces and information flows in the above diagram.)
  • As previously mentioned, some low-voltage alarms may identify problems that should be corrected anyway, including, but not limited to, overloaded distribution transformers, secondary, and service drops. AMI can provide meter level voltage measurements including data on voltage sags and swells. Also, whether VO is implemented or not, all utilities have to respond to "low voltage" claims of appliance damage sometimes reported by customers. Today, many utilities rely on on-site voltage measurements or even temporary "leave-behind" voltage recorders to satisfy customers that there is (or is not) a voltage problem. Remotely gathered AMI data will verify the presence/absence of a voltage problem with certainty, and will avoid field service checks or investigations that consume valuable staff time.
  • Capital investment already made or planned for AMI may be leveraged to yield further significant savings in addition to many well-documented AMI benefits involving meter reading, back office functions, operations, demand response, and several others developed in a typical AMI/smart grid business case.

    Agile Grid Today -- Smart Grid Tomorrow

    Using AMI with SCADA to implement and operate a VO program may not seem as elegant a solution as a control feedback system or a future smart grid application that is envisioned by some in the utility industry. Widespread automation throughout a typical distribution system may someday be available and affordable including automatically changing substation voltage regulator or Load Tap Changer (LTC) voltage settings based on voltage data provided by AMI. One of the many deliverables envisioned to be provided by smart grid applications is information about critical distribution functions. AMI available today can provide near real-time voltage alarm data from all active meters. System operators can use this AMI information with SCADA to implement and monitor a VO program to achieve additional savings for the utility and customers. This may not be considered smart grid by some, but it is part of an agile grid that's readily available to utilities today and is a capability that did not exist just a few years ago.

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    Certainly some significant proportion of a utility's load (and therefore its billings) rise and fall directly proportional to voltage delivered to the meter or point of use. Industrial not so much since motors and temperature controlled resistance heaters etc. will continue to try to draw the kwh required to accomplish the task assigned regardless of voltage, but residential and commercial, a large part. It seems strange to me to expect a utility to voluntarily invest significant amounts into systems which primarily reduce their billings. Improving the "smartness" of the grid should be mandated by regulation, over the objections of the usilities.

    All state-of-the-art smart meters being rolled out across North America can report on demand the current measured instantaneous voltage at the meter. In essence every smart meter is a precision digital voltage and current meter at every cutsomer site. Utilities could use this capability for the type of VO in real time that this article describes. All it needs is a software application that continuously talks to the meters for voltage monitoring, but the trouble is most AMI wireless networks and their management software are not designed for continous requests sent out to meters to obtain frequent data packets, nor could they handle the massive volume of data packets.


    As a semi-expert in smart meters, and an electronics design engineer, I can tell you that you are generally correct and your numbers are believable.

    The sobering truth about smart meters is they are an electronic device run by an embedded microcontroller (computer) chip with embedded software, and are read by a larger computer system with software at the utility office known as the meter administration system. The meters and the administration system can have software and/or hardware bugs. What you are hi-lighting is that in mass producing the meters by the millions there is always an expected small percentage number that may function but have defects that are difficult to detect. Depending on how frequently or infrequently the meters are read, and how the billing is calculated at the utility office computer system, the defective ones may only show up later as defective when erroneous energy data is detected after billing.

    Another limitation of electronic meters is their measurement accuracy. The electronic voltage and current sensors they use are limited in their accuracy resulting in a few tenths of a percent error of the total energy logged. But so too were the old mechanical service meters limited in accuracy to typically 0.5 percent error. In essence the new electronic smart meters are designed for somewhat better accuracy than the old electromechanical ones, but the defect rate when produced by the millions, and lifetime expectancy (or long-term reliability) of smart meters are generally poorer than the old electromechanical ones. An electromechanical one typically lasted for decades on a house before needing replacement, whereas the new smart meters likely will fail within one decade and need replacing.

    Of course the benefits of electronic smart meters, e.g. enabling Time-Of-Use billing, voltage quality and power factor monitoring, etc., outweigh their poorer long-term reliability over the old electromechanical ones.