BY ADAM GUGLIELMO, ABB
Electric power distribution systems historically have incorporated little automation. Power equipment, after being installed along a feeder, was expected to function independently with occasional manual adjustments. Capacitor banks might attempt to compensate for reactive loads based on time of day and day of week. Reclosers would attempt to close a set number of times before locking out. Linemen would drive along feeders to read faulted circuit indicators. Such was the state of grid automation–there wasn’t much.
Now, in response to growing demands to improve reliability and efficiency of the power system, as well as advances in technology, more automation is being implemented in power distribution systems. With smart grid implementation, utilities can automate applications that improve distribution system reliability, lower costs, increase efficiency, enhance security and achieve other diverse benefits.
A key element in enabling automation and smart grid applications is real-time, bidirectional communications among the utility’s data center, substations and utility devices in the field. Communications permit utility software systems to collect up-to-the-second information from the distribution system, adjust system operation, automatically read utility meters, proactively engage customers, predict pending failures and provide timely information to utility workers in the field.
Next-Generation Grid Automation, Control Applications
Grid automation and control are broad terms that describe efforts to modernize the electrical distribution network. Distribution automation and outage management projects are among those efforts but are bundles of various grid automation and control applications.
This section examines some of the distribution automation, outage management and other applications that can be combined into a grid automation and control application portfolio.
Automated Feeder Reconfiguration
Technology advances have enabled automated feeder reconfiguration. Intelligent switches, reclosers and sectionalizers linked to a communications network can be monitored and remotely operated from substations and utilities’ data centers.
Using these assets, utilities can pinpoint distribution network faults quickly and automatically and isolate them.
Service between a fault and the substations that can serve the feeder can be restored by automatically manipulating feeders’ reclosers and switches.
The outage can be contained to the area between the accident site and the nearest recloser in the direction of each substation, and repair crews can be dispatched to clear the fault and make repairs.
This helps reduce the scope and duration of outages and protects critical assets.
For utilities looking to improve System Average Interruption Duration Index (SAIDI) numbers either by choice or because of regulatory pressure, this can limit liability and improve customer satisfaction.
Traditional fault circuit indicator (FCI) monitoring requires a lineman to drive along a distribution feeder and inspect each FCI to see if it has tripped. By integrating communication capability with FCIs, the outage management system can perform this task from a central location. Automated FCI monitoring can hasten fault detection and location while eliminating driving power lines to look for tripped FCIs.
Conservation Voltage Reduction (CVR)
Utilities can make certain that voltage remains within specification along their distribution feeders by installing voltage measurement points. These measurement points can be monitored remotely via a communications network. By monitoring the voltage along feeders, the utility can implement a feedback system that enables CVR while ensuring customers at the far end of feeders receive voltage that conforms to specification.
Distributed Energy Storage
Distributed thermal energy storage units also can be automated and integrated into the distribution network. Equipped with networked sensors and controls, these units can be instructed to store power at off-peak times of day and shift critical kilowatt-hour consumption to off-peak hours. This can allow utilities to defer or eliminate capital expenditures they otherwise would need to make to keep up with peak demand.
Utilities are deploying additional applications that are part of grid automation and control. These include services such volt-VAR optimization, asset health management, leveraging advanced metering applications to assist in functions such as outage detection and isolation, and demand response applications (i.e., adjusting smart thermostats or making other adjustments in response to a shift in the supply-demand balance). All these applications require communications. For many reasons, wireless field area networks make sense as a medium to carry data to and from the distribution network.
Wireless Field Area Communication Networks Key to Grid Automation
Wireless field area networks (FANs) link meters and intelligent electronic device (IEDs) in the grid distribution system to substations and the utility’s data center.
IEDs usually connect directly to the FAN. The FAN then transports information between distribution automation equipment (i.e. reclosers, switches, capacitor banks and meters) and substations where remote terminal units (RTUs) typically exist to provide a localized layer of grid automation control.
From there, data typically flows from a FAN aggregation point in the substation to the utility’s core Internet Protocol network.
The core Internet Protocol network carries data from field systems to the operations center, where the distribution management system (DMS) and other software systems provide a more centralized view and an aggregate layer of automation control and coordination.
One Network, Many Applications
Enterprise networks deploy one network for all applications. The same network is used for email, printing, file sharing and Internet access, etc.
Yet, many utilities have implemented single-purpose communications networks in support of grid automation with, for example, one network serving advanced metering infrastructure (AMI), another serving distribution automation and another used for mobile work force automation.
Enterprises moved to one network for all users and applications as the advantages of a unified network became clear.
These include better return on investment, lower operating costs as a resilt of standardizing on fewer hardware and software products, ability to centrally manage the network to increase reliability, ability to enforce consistent security and quality of service (QoS) policies and efficiencies that accrue through any-to-any communication.
Utilities can reap similar benefits if they adopt the one network, many applications model in their FANs.
Grid Automation Networking Requirements
To support many applications concurrently, FANs must meet the requirements of all current and future applications.
High-capacity. As IEDs proliferate, become smarter and gather more information, capacity needs change. High-capacity networks are required because more applications and devices use the FAN and send and receive more data.
Low-latency. Many applications in the distribution system are not latency sensitive; however, the few that are, including protection and safety applications, are critical. Because a unified FAN must support the requirements of all deployed applications, low latency is essential.
Application prioritization. Low latency doesn’t help if traffic for safety and protection applications is stuck in a queue behind less important traffic, e.g., AMI interval reads.
Therefore, application prioritization is required to ensure time-sensitive traffic gets to its destination in time.
High availability. Communications are most critical during outages. FANs must operate even when events disable the electric grid.
High-capacity mesh networks that automatically use multiple paths, channels and frequency bands to route around failures and congestion are especially reliable. Individual communication devices must be ruggedized, weatherized and supply battery backup.
Scalable. Distribution area networks must scale to cover large geographic areas, potentially a utility’s entire service territory.
They also must scale to support, directly or via neighborhood area networks, millions of connected devices.
Secure. As utilities adopt Internet Protocol in distribution area networks, fear of cyberattacks increases; however, Internet Protocol-based architectures also bring security advantages. The tools used to thwart cyberattacks in enterprise networks have been honed for years and constantly are being updated.
Enterprise security tools that should be leveraged in FANs include IPsec virtual private networks, firewalls, RADIUS authentication and AES encryption.
Flexible. To support the widest variety of applications and devices, the FAN must be built on industry standards such as TCP/UDP/IP, Wi-Fi and Ethernet.
To best integrate IEDs, the FAN also must support secure network connections to devices that use serial links and automation protocols such as DNP3 and IEC 61850.
As the modern distribution network evolves, the vision of an automated system that effectively and efficiently senses and responds to real-time conditions comes closer to reality.
Intelligence and bidirectional communication are key enablers.
Using wireless FANs, smart grid systems in utility data centers and substations can collect up-to-the -second information from the distribution system, adjust system operation, automatically read meters, reduce peak loads, integrate distributed generation and energy storage systems, proactively engage customers and predict pending failures, enabling preventative maintenance.
Adam Guglielmo is a director of business development for ABB Wireless Communication Systems (formerly Tropos Networks) with a focus on electric utilities. He is based in Raleigh, N.C., and has 14 years of experience in the telecommunications industry in product management, marketing, sales and business development.
To support many applications, FANs must meet the requirements of all applications.