• Distribution Feeder Automation

    Feeder networks are direct lines to customers. Power outages are more than inconveniences. Businesses go down. Customers complain. Crews work overtime. Every minute is critical and costly. Hence, automation of feeder networks are required. Distribution Feeder Automation is the monitoring and control of devices located out on the feeders themselves such as Line reclosers, Load break switches, Sectionalizers, Capacitor banks &  Line regulators. Building a feeder automation system often involves multiple IP-based networks that make use of both wired and wireless architectures to construct many distributed systems based on Feeder Terminal Units (FTUs). Unlike traditional systems that rely mainly on manual operations, a feeder automation system can enhance the reliability and quality for electric power feeder systems, reduce downtime when the system is out of order, and monitor the real-time operation status, reducing both risk and maintenance costs.

    DFA minimizes feeder down time by quickly and automatically restoring operation to serviceable feeder sections, while isolating those requiring repair. This results in minimal outage time, fewer service calls, and reduced monitoring and management demands. In its simplest configuration, DFA consists of two or more Automation Controllers and a high-speed, IP-based network that allows for IEC 61850 peer-to-peer communications between controllers. Optional system components include all types of switchgear, wireless communications system, and PC-based and substation-hardened Human Machine Interfaces (HMI).

    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 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. 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. 

    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.

    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 DERs require a separate SCADA system for distribution, and we call that DMS.