Outage management systems (OMS) have evolved from a basic prediction solution to a platform for smart grid operations. While hard to imagine, there was a time when integration between OMS and other operational systems was limited. For example, once upon a time, OMS did not receive real-time status of breaker operations from SCADA, which caused delays in response during large event management.
Driven by the market demand to get more out of their investment, utilities have played a key role in helping vendors with their product roadmaps. As an industry professional, I have watched outage management systems develop over the last 20 years. From that experience, I have complied and ranked a list of enhancements to OMS that have revolutionized the way utilities operate in every scenario from day-to-day operations to large storm management.
In part one of this two-part series, I will take a look at OMS enhancements ranked 10 through six.
10. Consolidated Environment for Outage and Mobile Workforce Management
When outage management was first conceptualized, it was intended to automate the prediction of outages, based on trouble call input. Until that point, phone calls were mostly answered by customer services representatives who created an immediate need order. These were then handed over to the dispatch team, who used paper maps to determine need based on addresses and transformer locations, over what current protection device was likely to have operated. But even as OMS systems matured, there was still no integration with systems that performed mobile workforce dispatching. A few vendors realized the power of consolidating OMS with mobile workforce into a single, end-to-end workflow. This enabled dispatchers to assign work orders electronically out to mobile devices directly from the same platform that performed the prediction. Then when field workers had restored power, they were completing the required documentation using a single system. This eliminated the need for integration with a separate mobile workforce management system. Today, it is a standard feature of every outage management system to incorporate dispatching workflows and crew management into outage systems.
9. Geospatial Mapping of Events, Crews, and the Electric Grid
Outage systems have always leveraged a model of the electric grid to perform prediction. The relationship of the customer to the transformer, then the transformer to the feeder is the backbone of the solution. But the early systems were strictly tabular based with no map visualization. Outages were sorted be substation and feeder, but unless the local operator knew where the over current protection device was on the network, it made for difficult times to develop an overall restoration and response plan. Once vendors began offering embedded maps that displayed the electrical grid and the street network in a GIS manner, it opened the door to centralized dispatching. No longer did the operator need intimate knowledge of the local area to dispatch outages to crews. They could know see a spatial representation of the remote area containing the outage and depict the proximity of the workforce for the fastest response. Utilities began to consolidate dispatching from local office into centralized facilities, enabling the local employees to focus on construction and customer service. Now with a world where everything is spatially enabled with location-based services, it is difficult to image dispatching virtually from a spreadsheet, but those days existing!
8. Single-user Interface to Operate Telemetered Devices
As noted in the introduction, early outage management systems had no integration with SCADA systems. For example, when a telemetered breaker would operate, a system operator would have to contact a dispatcher to manually inform them of the status. In the meantime, the outage system would be flooded with trouble calls, but depending on the time of day, may be slow to predict the correct device. Most utilities deploy crews with specific skill sets to outages, depending on the type of event. Before SCADA integration, it was common to send out several different crews to respond to events on a single feeder, when it fact it was all part of the same event and most likely required a different crew type all together. Once industry standards were leveraged to integrate SCADA to outage management, it linked together a real-time environment with one that relies on input for prediction. Dispatchers would immediately know the magnitude and scope of the outage, and could deploy the right crew to the right location, the first time. But quickly vendors realized that they could do so much more than just a one-way feed from SCADA to OMS. This integration then evolved to a bi-directional interface where the operator could directly issue commands out from OMS, via ICCP or other standards, to SCADA for direct control of the telemetered devices. This single-user interface concept enabled utilities to consolidate separate functions of operations and dispatch into a single power user who had control and authority over the management of the grid. Out of this bi-directional integration grew advanced outage management systems and ultimately advanced distribution management systems.
7. Thin Client Platforms for Outage Management
The move from thick client installations to thin client browser-based applications has been a key innovation from OMS vendors. Today, utility operations are mobilized, often managing storms from places other than the office. So, it was a logical step forward to provide the industry with a way to maintain the same level of operational response, but to decouple from an outage management system that was installed on a PC in the control room. Many other applications have trended toward cloud or web-based, so it was no surprise when OMS vendors began to develop browser-based solutions for outage management. These grew from the initial offerings that were often compatible with only Internet Explorer from Microsoft, to know where most browser-based OMS solutions will work with other popular web browsers such as Google Chrome, Mozilla Firefox, and Safari from Apple. Typically, with just a required VPN back to the corporate network, managers, occasional storm dispatchers, and others can quickly access OMS functionality from the comfort of a quiet conference room or from the confines of their homes. While the method of licensing needed to change, the option for utilities to dispatch and operate the network via laptops and web browsers has changed the way business is done during large storms.
6. Integrated Switch Planning
As utilities began to use outage management for network operations, they quickly learned that there were other non-outage impacting actions taking place that impacted the core prediction ability of the system. Every day, dozens if not hundreds of planned switching procedures were taking place to alter the flow of power, and in some cases create planned outages. This created issues because now the physical state of the distribution system differed from the IT system of record and outages began predicting to incorrect overcurrent protection devices. Crews were dispatched to the wrong devices, which added time to response, creating unnecessary additional outage duration. This workflow issue was addressed when vendors incorporated the ability to write, test, and execute planned switching procedures directly within the outage management system. Pulling from prebuilt templates or writing ad hoc plans, engineers could then plan switching procedures and test them in simulation, long before they were ever executed in the field. Complete workflows to manage the different levels of approval were included to ensure that legacy processes associated with routing of paper-based plans and approval schemes were taken into consideration. The real value then became when the plans were logged or executed. Using tools within an OMS, each step would be issued, and executed in real time, as either the operators were controlling telemetered devices, or field crews were operating manual switches. These step operations then altered the virtual state of the distribution grid so that it matched the physical state in the field. Outages that occurred during altered states of the grid once again predicted to the correct devices, and the utility has a consolidated system of record for switching actions that had been logged. Now, switch plan editors are standard features in any advanced outage management system, as well as distribution management system.
Stay tuned for the conclusion of this blog post where I will discuss the remaining top five enhancements to outage management that have revolutionized the solution in the past 20 years.
Eric J. Charette currently serves as Technical Manager of Business Development for Utilities, Communication and Transportation with Hexagon Safety & Infrastructure in the U.S. He is responsible defining long-term organizational strategic goals and provides technical direction, leading all marketing and presales efforts, maintains relationships with business partners and serves as product manager. Eric previously served as Executive Consultant for outage, mobile workforce and distribution management solutions. Prior to joining Hexagon in 2006, Eric worked for Wisconsin Public Service Corporation as a distribution field engineer where he was responsible for ensuring safety and reliability of the electrical distribution system by providing engineering support for design, construction, operation and maintenance. Later promoted to Senior Outage Management Engineer, he was responsible for all outage management at WPSR, providing technical and strategic expertise and setting policy. He also successfully led the client-side implementation of the corporate OMS project including serving as the system administrator and client lead responsible for change management and end user training. Eric has been recognized as an industry expert in utility operations with several industry publications and presentations. He also serves on the Advisory Committee for the DistribuTECH conference. Eric graduated from Michigan Technological University, in Houghton, Michigan, where he earned a Bachelor of Science degree in Electrical Engineering, with an emphasis in Power Systems. Eric is a registered professional engineer in the states of Wisconsin and Alabama.