Outage Management Systems: What Makes a Good OMS?

Outage management systems (OMS) have become standard for U.S. electric utilities.  These systems have historically been built either in-house or by deploying a third party solution. At its core, an outage management system is designed to analyze the location and extent of an outage, and has outage prediction capabilities enabled by a detailed representation of the distribution network.  This helps dispatchers and crews determine trouble locations. More advanced best-in-class systems take it to the next level by also enabling real-time ETR development, crew management, and outage statistics / restoration analytics.

A properly-configured OMS can significantly reduce the cost of emergency response, improve the quality of service for customers, and enhance restoration safety for everyone who uses or operates the grid.  For example, it can provide call-based and independently derived data, and in turn, display this data in useful forms to help facilitate resource allocation.  It can also record the time it takes to complete site-specific restorations, which can then help project restoration times.  In fact, several of the most successful deployments of outage management systems at large, multi-state utilities have been credited with reducing restoration times by a whopping 25%!

Integrating Outage Management Systems with Other Systems

The outage system must be fully integrated – in other words, it must have connectivity to operations centers and utility systems so that it can gather, compile, and display information from a variety of sources.  By connecting with other systems, the outage management system is able to access real-time operational data to facilitate a strategic, 30,000-foot view.

The systems with which it should interface provide helpful inputs into the restoration effort, even if not specifically designed for outage management purposes.  In the aggregate, this convergence is sometimes referred to as an Advanced Distribution Management System (ADMS).  These systems include, but are not limited to, the following:

• Customer Information System (CIS): Tracks customer information, generates bills, issues service requests, and provides information about each customer’s preferences.
• Interactive Voice Response (IVR): Answers calls, routes information, compiles data, returns calls, and calls back customers as programmed.  It can be linked to record customers’ locations and link these with locations in the distribution system.
• Call Overflow (COF): Redirects phone calls from one answering location to another when volume exceeds capacity.
• Supervisory Control and Data Acquisition (SCADA): Obtains data from devices like protective relays; provides breaker, switch, and re-closer statuses; provides a way to control these devices remotely; and displays the status of the monitored equipment graphically.
• Distribution Automation (DA): Monitors and controls devices on the distribution system (i.e., breakers, re-closers, distributed generators, etc.).
• Automatic Meter Reading (AMR): Remotely reads meters and automatically records the results.
• Advanced Metering Infrastructure (AMI): Encompasses all the same components as AMR, plus two-way communication to allow remote customer disconnects and other methods to manage demand.
• Geographic Information System (GIS): Collects, records, and displays geographically-referenced or spatially-oriented information to show the exact locations of utility infrastructure.
• Automatic Vehicle Locator (AVL): Automatically records and displays in near real time the location of vehicles in a utility’s fleet.

Outage System Challenges

Like anything, outage management systems have certain challenges.  First and foremost, achieving the optimal level of integration is difficult.  It’s far easier for decision makers to opt for a less-comprehensive solution.  Achieving full integration is particularly difficult when it comes to SCADA and DMS systems – these systems tend to be designed as closed loops due to their mission-critical nature, and as such they are typically not built with integration in mind.  These complexities often result in unforeseen integration shortcomings which can lead to information gaps that undermine the restoration process.

Another challenge is that underlying distribution systems typically undergo frequent changes from activities ranging from network enhancements to switching and maintenance tasks.  This fluidity complicates the process of providing real time information about the system.

Finally, the outage system must interface with wireless networks in order to access information in near real time, and if this connectivity is interrupted, the entire platform could be rendered useless.  A wireless outage would hinder the OMS ‘ ability to track and report information and updates.

Best Practices

• An ADMS configuration is optimal as it can help plug information gaps by combining the OMS, DMS and SCADA systems onto a single technological platform and user interface.  This allows for a more comprehensive view of the distribution system during an outage, which improves overall efficiency and effectiveness.
• An outage management system should provide only relevant and useful information in a simple and intuitive way, and avoid providing too much information or otherwise complicating the display of the information.
• Because the system is dependent on wireless communications networks, a wireless network outage can render it useless. Therefore, communication network redundancy should be built into the system.
• Since switching is often required in the service restoration process, the OMS should include switch scheduling and switch management functions.
• Finally, utilities should strive to continuously learn and enhance their expertise by incorporating the outage management system into all drill and training simulations, and after actual events, discussing what went right and what went wrong from an OMS perspective during the debrief process.

For more information on best practices, checkout this great article from ELP on OMS lessons learned from Hurricane Sandy.

Bottom Line

Technology has obviously improved and evolved over time, so if your company’s OMS is more than 20 years old, it’s probably a good time to conduct a full evaluation.  This involves determining “future state” system and integration requirements, evaluating the current outage management systems weaknesses or gaps relative to this future state, and creating a business case to see if the level of effort and investment necessary to plug the gaps is worthwhile.