by Bert Williams, Tropos Networks
Every year, power outages disrupt businesses and incite domestic upheaval by interrupting a prime time football game or impeding homework completion.
For decades utilities relied on customer phone calls to identify outage areas, and often callers gave delayed and imprecise information about outages. Customers often viewed utilities’ slow resolutions and reactive responses negatively.
Smart grid implementation lets utilities improve customer satisfaction by deploying software, intelligent devices and network communications. These technologies can minimize the scope and duration of outages and enable proactive engagement with affected customers.
A key element enabling proactive outage management is real-time, bidirectional communications to utility devices in the field. Communications permit outage management systems (OMSs) and other utility software systems to collect up-to-the-second information from the distribution systems, adjust system operation and provide information to customer service systems and personnel for proactive customer engagement. OMSs could predict failures, which would enable scheduled preventative maintenance and reduce unscheduled maintenance under outage conditions.
Enhancing Outage Management Using Smart Grid Infrastructure
Smart grid devices can enhance outage management. Utilities can leverage advanced metering infrastructure (AMI), faulted circuit indicators (FCIs) and distribution automation (DA) installations to improve their outage responses.
Leveraging AMI to Enhance Outage Management
AMI can assist outage detection and isolation.
Smart meters with last-gasp capabilities alert OMSs the moment an outage occurs.
Because all affected meters issue a last-gasp message when an outage occurs, utilities get timely outage notification and an accurate picture of outage location.
“If a house loses power, we don’t have to wait for a customer to call us,” said Darren Grile, network supervisor at Anderson (Ind.) Municipal Light & Power.
Restoration notifications from smart meters can help avoid OK-on-arrival dispatch of line crews.
When time-stamped, they also help utilities accurately calculate customer average interruption duration index (CAIDI).
Automated FCI Monitoring
Traditional FCI-monitoring entails having a lineman drive along a distribution feeder to visually inspect whether each FCI has tripped.
By integrating communication capability with FCIs, an OMS can perform this from a central location.
Automated FCI monitoring can hasten fault detection and location and eliminate driving power lines to look for tripped FCIs.
Enhancing Outage Management With DA
Advances in communications have enabled smart DA.
Intelligent switches, reclosers, sectionalizers, capacitor banks and transformers can be actively monitored and remotely operated from substations and utilities’ data centers.
With smart DA devices, utilities quickly and automatically can pinpoint distribution network faults, reducing the scope and duration of outages and protecting critical assets. Smart DA devices automatically isolate faults and enable electricity restoration with no operator intervention, reducing outage duration from hours to minutes.
During normal operation, the neighborhood is served by distribution feeders from three substations (see Figure 1).
In Figure 2, a fault occurs, perhaps because a car hits a utility pole. The fault causes all customers normally served by substation A to lose power. Without smart reclosers and switches, this condition would remain until trucks with line crews arrive to restore power.
With smart reclosers and switches, service between the fault region and substation A is restored by automatically closing the reclosers upstream from the fault (see Figure 3).
Similarly, service between the fault and substations B and C is restored by closing the switches serving as tie points between the distribution circuits and the reclosers, between the tie points and the fault (see Figure 4).
The outage is contained to the area between the accident site and the nearest recloser in the direction of each substation.
Without smart DA technology, isolating the fault is a manual process. Manipulating switches requires truck rolls, which can take hours. With smart technology, the process is automated and requires little or no manual intervention and is accomplished in minutes.
Utilities are deploying functionality, as evidenced by Avista’s smart grid projects in Spokane and Pullman, Wash.
Outage management is enhanced further when the network used for machine-to-machine communications also is used for mobile work force automation. Providing access for mobile workers enables them to access all information in the data center without leaving the field.
Jimmy Bagley, deputy city manager of Rock Hill, S.C., expects good results.
“The practical application of this system will be the ability of the utility workers during an outage event to access real-time outage data from their vehicle in the field,” Bagley said. “Direct access to data ensures the utility crew will know that customers have power before leaving the area.”
Proactive Customer Engagement
With smart grid technologies’ detecting, locating and minimizing faults, utilities can turn the traditional customer engagement model during outages on its head. Instead of waiting for customers to inform them of outages, utilities can notify customers about outages and their scope, cause and expected duration by phone, email, text, the Web and social media. Customer service representatives can be better prepared to respond to inbound calls.
Eliminating Outages With Predictive Maintenance
The best outage is one that doesn’t happen. Intelligent distribution equipment with high-speed communications can help a distribution management system (DMS) identify likely failures and allow a utility to replace components before they cause an outage.
Various techniques can predict potential failures. For example, a transformer’s temperature and kilovolt-ampere load are good predictors of pending failure. Transformers with sensors and communication capability can provide temperature and loading data to the DMS, which can identify a potential failure point before an outage. A more complex method requires intelligent electronic devices (IEDs) throughout the distribution system to collect large amounts of oscillography data and to send it to the data center to detect patterns that indicate pending failures.
Wireless Distribution-area Communication Networks Key to Enabling Advanced Outage Management
Wireless distribution-area networks (DANs) provide the communications needed by OMSs and other utility software systems to collect up-to-the-second information from the distribution system, adjust system operation, proactively engage affected customers and predict failures. DANs links smart meters and IEDs in the distribution system to the data center. IEDs usually connect directly to DANs. Smart meters generally use a lower-bandwidth neighborhood-area network (NAN) to communicate with an AMI collector that aggregates data from many smart meters. The collector then connects to the DAN. The DAN transports information among NANs, IEDs and the utility’s core Internet Protocol network. The core Internet Protocol network connects to the data center, where the OMS and other smart grid software systems are located. The OMS shares information with systems such as the geographic information system (GIS) and interactive voice response (IVR) via the utility’s enterprise network with workers and systems in the field, communicated using DANs (see Figure 6).
One Network, Many Applications
Enterprise networks deploy one network for all applications. The same network is used for email, printing, file sharing, Internet access, etc.
Many utilities implement single-purpose communications in their distribution systems with one network serving AMI, another serving DA and yet another 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 result of standardizing on fewer hardware and software products, ability to manage the network centrally to increase reliability, ability to enforce consistent security and quality of service policies and efficiencies that accrue through any communication. Utilities can reap similar benefits if they adopt the one network, many applications model in their DANs.
Distribution-area Network Requirements
To support many applications concurrently, DANs must meet the requirements of all current and future applications:
à¢— High capacity. Traditionally, utility applications sent and received little data. Consequently, utilities generally installed low-capacity networks. As IEDs proliferate, become smarter and gather more information, capacity needs are changing. High-capacity networks are required because more applications and devices use DANs, and they send and receive more data.
à¢— Low latency. Many applications in the distribution system are not latency-sensitive. The few that are, including protection and safety applications, tend to be critical. Because a unified DAN must support the requirements of all deployed applications, low latency is essential.
à¢— Application prioritization. Low latency is essential but doesn’t help if traffic for safety and protection applications are stuck in a queue behind less important traffic such as AMI interval reads. Application prioritization is required to ensure time-sensitive traffic gets to its destination in time.
à¢— High availability. Communications are most critical during outages. DANs 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 and weatherized and supply battery backup.
à¢— Scalable. DANs must scale to cover large geographic areas, potentially the utility’s entire service territory. They also must scale to support directly or via NANs millions of connected devices.
à¢— Secure. As utilities adopt Internet Protocol in DANs, fear of cyberattacks increases. Internet Protocol-based architectures, however, 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 DANs include Internet Protocol Security virtual private networks, firewalls, Radius authentication and Advanced Encryption Standard.
à¢— Flexible. To support the widest variety of applications and devices, DANs must be built on industry standards such as TCP, UDP, IP, 802.11 (Wi-Fi) and 802.3 (Ethernet). To best integrate IEDs, DANs also must support secure network connections to devices that use RS-232 or RS-485 links and automation protocols such as DNP-3, Modbus, SEL Mirrored Bits and IEC 61850.
As outage management evolves, the vision of a self-healing distribution grid that predicts failures comes closer to reality. Intelligence and bidirectional communication are key enablers. Using wireless DANs, OMSs in utility data centers can collect up-to-the-second information from distribution systems, adjust system operation, proactively engage affected customers and predict failures, enabling preventative maintenance.
Bert Williams is marketing director for Tropos Networks. He has more than 25 years of experience in high-speed wireless and wire-line networking, including more than five years in smart grid communications. He has a bachelor’s degree in electrical engineering from Carnegie Mellon University and an MBA from Harvard Business School. Reach him at 408-470-7397 or email@example.com.