In part one of this two part series, I wrote about vendor enhancements to outage management systemsOutage Management (OMS) that have revolutionized the way utilities operate in every scenario from day-to-day operations to large storm management. In my professional career, I have witnessed outage management evolve from manually intensive paper-based systems to where they are today, serving as a platform for smart grid operations. In this article, we will look at the top five enhancements to outage systems since inception.
First let’s recap numbers 10 through 6.
10. Consolidated environment for outage and mobile workforce management
9. Geospatial mapping of events, crews and the electric grid
8. Single user interface to operate telemetered devices
7. Thin client platforms for outage management
6. Integrated switch planning
Now let’s move on to the top five enhancements.
5. Integration with AVL for GPS-based Vehicle Location Services
As we move into the top 5, we see several IT system integrations that have added tremendous value beyond core OMS. The first one to discuss is how Automatic Vehicle Location (AVL) can supply near real-time vehicle location via GPS signal. Integration of AVL with OMS is often viewed as non-essential and not implemented during the first phase deployment, as other integration points, such as CIS and SCADA, are deemed to have more value. So what is the real value of being able to see the location of the response crews in the same OMS/dispatch environment? It begins with the obvious; being able to quickly, and visually, locate the closest crew to an emergency event equates to faster response. Getting a set of eyes on the problem quicker to diagnose the problem leads to a shorter outage duration and increased customer satisfaction. AVL systems are in place at most utilities as they are not as expensive as other utility IT systems and the integration with OMS is not complicated. Sending in a location signal based on configurable settings is a one-way push containing a small packet of data but has a big value to dispatch. Without AVL, time is wasted to determine via radio or phone who the closest crew is to the location, as dispatchers have to rely on the last known position of a crew. In a business where minutes matter, if seeing the truck positions can trim one to two minutes off of an average dispatch time of seven minutes, then you are reducing the time to get the work out the door by 25 percent, which is a tangible benefit. On the soft side, with something that is harder to quantify, safety increases with the integration of AVL into OMS. Ensuring that crews are in the clear with a visual inspection during switching operations, routing crews around closed roads, or locating crews to assist other crews during an emergency all have value beyond dollars and cents.
4. Distribution State Estimation and Load Flow Calculations
With the transition toward using outage management as a platform for smart grid operations, the need for more proactive applications became much more important. Outage management by nature is a reactive approach to grid management, because it waits for input from customer calls to perform core functions such as device prediction. But by definition, using outage management to manage the distribution system requires operators to get ahead of issues before they turn into outages. One primary indicator of a device failure or the need to transfer load via switch plan management to alleviate overloads can be achieved with integrated load flow calculations. Load flow and distribution state estimation produce a real-time unbalanced, phase-based solution for voltage and current flows on the distribution network. Calculations are based on load profiles, SCADA measurement points at the substation, as well as any known customer load values. The more data points that are available, the more accurate the calculations can be to match real-time measurements taken in the field. Typically load calculations are triggered in a manner of ways, including predefined time period, by change in network configuration, manual request to solve, and by detecting change in real-time loading. The presentation of violations or exceptions is key to notify the operators via range alarms and geospatial visualization of conductor segments that may have loading issues. Integration of load flow transforms a basic OMS into an advanced operations platform for distribution management. This is because many of the advanced applications such as fault isolation, service restoration, volt-var control, and feeder reconfiguration are dependent upon accurate load flow calculations. Successful implementations are highly sensitive to quality data, so much attention should be devoted to ensuring that the metadata exists and that processes are in place to ensure the data remain quality. But once the systems are up and running and a trust factor is built between the calculated values and the control room operator, seeing network conditions in the same environment as outages has tremendous value to quickly locate cause locations and get ahead of problems before they occur.
3. Consumer Map Integration
As noted in #9 of our list, it was a tremendous breakthrough to add a geospatial component to outage management. Having a GIS-style map integrated with outage management moved the industry beyond tabular based dispatching to geo focused. For many years, having outages displayed on a basic road map in a computer-aided dispatch (CAD) environment was “good enough.” But then in the mid-2000s, Google, then Bing, released their mapping applications through basic web browsers which sparked the geospatial revolution. The need for spatial awareness has now become mainstream for everything from house hunting to route planning for oversize/overweight loads in the transportation sector and supported by all device types from the desktop, to the tablet, or smart phone. In the control room, dispatchers began to use Google and Bing to see overhead images, including aerial photography in separate browser windows with no direct integration to outage management. This helped the dispatcher to spatially understand the work environment from a line crew perspective, but was cumbersome to navigate between the browser and the OMS application. The early integration that vendors created to sew together commercial mapping into the fabric of outage management permitted users to see outages and crews on top of the Google or Bing map, but the core network map was still needed to see and operate the network. Once OMS vendors began publishing web services of network data that could be consumed via OGC standard web services as a layer on top of the commercial map, it opened up so many doors for more efficient dispatch. The use of the GIS-style map for network visualization gradually decreased and dispatchers began to use the commercial maps more and more; after all, commercial maps are used in all other walks of life and have a high acceptance factor. Then added features of commercial mapping such as Street View from Google, terrain maps and advanced zoom/pan/rotation controls provided greater flexibility for visualization. It is now an expectation that outage management systems have the ability to operate from a commercial map basis and there is no looking backward to the maps of yesteryear.
2. Service Restoration Schemes
As a young field electrical engineer, the maintenance and operation of the distribution system in Oshkosh, Wisconsin was my primary responsibility. That including writing, verifying, and executing switching efforts during planned and emergency situations. I relied on a geospatially correct one-line map, real-time loading conditions from SCADA, and my experience to know where I could move load around on the distribution system. This worked just fine during those planned scenarios when I had plenty of time to conduct load studies, write out the steps in detail, and even take point measurements in the field to validate my approach. But during the middle of the night when large scale outages required emergency switching and time was of the essence, I relied on my gut feel for what I could do to restore power as quickly and as safely as possible. There are still engineers all over the country who still operate this way and more often than not it results in success. But why not consult with a load flow calculation based restoration scheme if it is available? That is where our #2 enhancement comes into play. Automatic switch plan generation capability added to outage management systems has helped to validate what was done manually for a hundred years. Acceptance of the recommendations are still a work in progress, as engineers we tend to be stubborn when a calculation indicates something different than our experience, but the trust factor is improving. Where I see the real value is how quickly a restoration scheme can be generated when compared to manual techniques. Even if that means isolation on both sides of the fault and partial restoration by closing a feeder breaker and picking up load from an adjacent circuit via telemetry within minutes, this can restore power to a large number of customers much faster than I can draw up on paper. By leveraging an immediate response plan recommended from outage management, engineers can then follow up with further partial restoration via manual techniques, then after the fault is cleared, returning the system back to normal.
Before we get to the top of the list, there are a few enhancements that did not quite make the top 10, but were worth an honorable mention.
- Dynamic Colorization Schemes:Early OMS network maps featured GIS network facilities with static coloring, typically based on the voltage level, or uniquely by feeder to quickly locate open points. The addition of dynamic colorization schemes meant that when outages occurred, either predicted or confirmed by SCADA or the field, the user could quickly see the area impacted by the outage spatially.
- Substation One Line Diagrams:With the use of advanced OMS for distribution network control, the addition of substation one line diagrams gave system operators a user interface that they were used to seeing from SCADA systems.
1. Integration with Smart Meters
When smart meters were first deployed, the return on investment was based on elimination of manual reads, providing capability to perform remote disconnects and greater visibility of demand data. But some early visionaries were looking at the real-time operational benefit of knowing the status of the meter, through either polling the device or with more advanced meters, having them provide an unsolicited status. The integration of smart meters into outage management tops my list as the most beneficial enhancement of all time. That is because it has completely revolutionized the core function of outage management, which is to predict probable devices that may have operated to clear faults. No longer does OMS have to wait for customer phone calls to predict outages, which at an average call rate of 20 percent during daylight hours and sparse at best overnight, can take 10 or more minutes to accurately predict locations. Now with the last gasp capabilities of smart meters to provide notification that they no longer have source power, the integration with OMS can interpret that as an outage. Most utilities that have implemented this integration, have configuration schemes in place to avoid false positives, but requiring two or more signals per transformer. This results in the utility often responding to outages occurring during typical low call volume hours without requiring any customer phone calls. Now outages are reaching their final prediction in a manner of minutes, saving 80 percent or more of the time to predict. This translates into getting the right crew type to the outage location the first time. The value of AMI integration does not end there; dispatchers can also manually ping meters from the desktop or crews from the field, when trying to troubleshoot the full extent of an outage. Then, when restoring power, a sampling of meters can be pinged automatically to verify restoration, a process that was formerly manual phone calls. No one likes receiving a phone call in the middle of the night from the utility asking if your power is back on. “You mean you don’t know that my power is on or off,” is a common question from the weary consumer. Having the ability to know that all power has been restored before a crew leaves the scene means fewer return trips with dissatisfied customers. Now the visionaries are eyeing how to get even more out of the integration, which includes closing individual outage call when receiving a power restoration message, validating the restoration time provided by the crew with the times from the meters and checking power status of individual outage reports before responding. There are so many facets to the two way integration of smart meters into outage management with tangible benefits that it is clear to see why it tops the list.
The good news for outage management system owners, is that vendors continue to enhance their offerings to provide more value for these mature systems. I suspect that even as outage management becomes part of a larger advanced distribution management system, that it is the most valued component in power restoration and key to maintaining customer satisfaction.
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.