Smart grid substation and feeder automation
Bringing operations and IT together
By John McDonald
IEEE's John McDonald
One of the most common definitions of Smart Grid is that it will bring together the operational and information technology infrastructure of a utility to create a more intelligent, efficient and reliable grid. Substation and feeder automation technologies will play important roles in bringing operations and IT together to create better and smarter grids, but utilities must deploy the technologies effectively to fully realize these benefits.
The purpose of this article is to describe the benefits that substation and feeder automation will provide to the Smart Grid and to highlight key implementation factors utilities should keep in mind if they want to make the best use of these very important technologies.
The electric utility substation is extremely strategic to utility operations and business. Compared to other systems in an electric utility network, the substation has the highest density of valuable information needed to operate and manage a Smart Grid.
A typical substation has many, many microprocessor-based intelligent electronic devices (IEDs) that send and receive data. Every IED has two types of data: Operational data and nonoperational data. Utilities can use both types of data to improve reliability, create new operational efficiencies, and provide more overall benefits to the organization. The data can also enable new asset management programs, including predictive maintenance and equipment life extension, and it can help improve planning. But despite the value of this data, information generated by IEDs is vastly underused. In fact, a typical utility realizes no more than 20 percent of the potential benefits of a substation IED investment because of the way the IED is architected and installed. Eighty percent of the potential benefits are not realized.
I've conducted several projects proving that IED installations deliver 20 percent or less of their potential benefits. The problem undermines Smart Grid's promise of bringing together the operations and information sides of a utility and perpetuates traditional utility culture in which the two sides of the business don't work together. This disconnect prevents utilities from realizing more benefits from their substations and their investments in substation IEDs.
I've identified several steps utilities need to follow to effectively address the 80 percent of untapped benefits that substation automation can provide.
First, when buying IED devices, make sure that all the devices and the valuable data in the devices are known by the different stakeholder groups in the utility. The usual practice today, when devices are being put in the field, is for an individual group in the utility to become the primary owner of the device.
For example, the protection group buys a protective relay that will be connected to a circuit breaker in a substation. The relay has information for that circuit breaker-such as the number of times the breaker operates and the magnitude of the fault energy it interrupts-that maintenance personnel must have to determine when maintenance is required on that device. But the protection group may not want anyone else involved with its IEDs and may not share IED information within the utility. Even though the device can facilitate the exchange of very important data between utility business groups, access to the data is restricted and the benefit of using the device is limited.
So the first step, when deploying IEDs, is making sure everyone is familiar with the devices that are in the field, determining the operational and non-operational data contained in the devices and identifying the primary stakeholders who may benefit from the data.
The second step is to look at the operational and non-operational data within the devices and determine which particular data points could help other business groups in the utility. Examples of these data points include digital fault recorder records (waveforms) for protection; circuit breaker contact wear for maintenance; and dissolved gas/moisture content in oil for maintenance. I have found that in addition to the operators in the control center, there are 20 to 25 different business groups in a utility that could provide more value to their organizations if they had access to this data. It's tremendous.
And then there is an important, third step, and that is to determine the architecture in the substation. The architecture must support extracting operational and non-operational data, concentrating it, and sending it out of the substation and to the control center for operational data and out of the operations infrastructure and across the firewall into the corporate IT network for non-operational data. Once it enters the IT system, the data should be sent to an enterprise data warehouse where the different business owners can have desktop access to that data via the corporate network. But to make all of this happen, operations and IT have to work together, which gets back to the original definition of Smart Grid.
Smart Grid spending is shifting away from smart meters and into the distribution system, and feeder automation is driving much of this shift. Feeder automation has a primary role because it provides the strongest business case for utilities compared to other Smart Grid technologies. Feeder automation provides benefits that are six to eight times the cost of the technology, and the payback period is well under three years.
There are three applications for feeder automation. The first is voltage control. By controlling the voltage on the feeders, utilities can control the demand or load. This can be done during on-peak times for peak load reduction, and it can be done during off-peak times to reduce electricity consumption.
Voltage control has always been used during peak periods because it reduces the need to deploy peaking generation plants, which are very expensive. A typical utility is in peak load periods for less than 100 hours in a year, and the last thing it wants to do is build a very expensive plant or purchase expensive power for this short period of time.
Off-peak voltage control, which hasn't been used by utilities, would save utilities a tremendous amount of money. In the United States, the average voltage at a person's home is 122.5 volts, however the ANSI standard is 114 to 126 volts. The higher the voltage at a home, the higher the home's electric bill will be. But because utilities make revenue based on how much electricity they sell, most utilities have no incentive to conserve. They make more money if they deliver electricity at higher voltages.
We've done studies showing that if you could lower the voltage by 4.5 volts to 118 volts, for example, customers would not notice any difference at their homes. Yet the change would free up a tremendous amount of infrastructure so a utility could better support load growth without building new substations. Revenues would decrease, however.
Decoupled rate policies, which decouple utilities from having to sell electricity to make money, are needed to motivate utilities to employ voltage control to conserve energy. There are fewer than 10 states in the U.S. that have these policies. In these states, the public service commissions have allowed decoupled rates to encourage utilities to conserve and implement energy efficiency programs. The states compensate the utilities in various ways for any revenues they give up through energy conservation, so the utilities are not affected at the bottom line when they implement these programs.
The second application for feeder automation is reactive power control. Reactive power takes up space on the electric system but it is not used. We want our electric system to have a power factor of 1.0, which means all we have is real power (watts), and no reactive power (VAR). We can eliminate reactive power by employing automation technologies to switch capacitor banks on the feeders. The technology will improve the power factor, which reduces losses.
The third application, called Fault Detection Isolation Restoration (FDIR), is used to improve the reliability of the system. When a disturbance occurs in the distribution network, the technology automatically detects the disturbance and locates it. The system will open up switches on either side of the faulted segment to isolate it and restore service around that faulted segment, which improves the reliability of the system.
Improving reliability of the system is important for consumers, of course, but utilities have strategic reasons to do this too. Utilities must report reliability performance to the power pools they're part of and their performance is ranked according to various reliability indices. That's why this is important. If a utility is not doing well it's not a secret. A lot of people know about it.
There is a fourth part of this that involves adding a distribution management system (DMS) in the control center. The DMS manages the increasing complexity of the distribution system, not only for these three applications, but also for integrating renewable generation into the distribution system. The system was designed for power flowing in one direction, from source to load. It was not designed, for example, for homeowners to put solar cells on their houses, generate power and feed power back into the grid. Integrating renewables requires a separate SCADA system for distribution, and we call that DMS.
About the Author
John McDonald is an IEEE Fellow, a past president of the IEEE Power & Energy Society (PES) and past chair of the IEEE PES Substations Committee. He is director of technical strategy and policy development at GE Energy's Digital Energy business.