Discussions about grid modernization and resilience are spurring people inside and outside the utility industry to scrutinize technology. For example, the National Commission on Grid Resilience, a group co-chaired by former NATO commander Wesley Clark and former congressman Darrell Issa (R-Calif.), issued a report last month stating, in part, that America’s search for energy efficiency has exposed vulnerabilities from outside threats.
On another front, activists are pushing policy initiatives such as Connecticut’s “Take Back Our Grid” legislation to push utilities to rely less on contractors and more on employees to speed up response to outages. Although I believe contractors will remain a critical piece of the puzzle for utilities during blue- and gray-sky days, speeding up restoration will reduce costs and benefit all.
Add to these forces an array of burgeoning distributed energy resources (e.g., wind turbines, batteries and solar) and increasingly complex operations, and it’s clear the voices are growing for more safety and better reliability. Achieving these goals takes a unifying technology that serves up one source of truth for utility managers. In spite of the technology utilities own — both internally developed and external software — few organizations can link their disparate systems and get one operational picture.
Southern California Edison is an example of a utility aiming to replace its legacy outage management and distribution management systems with a grid management system (GMS). The GMS is a “system of systems” to meet the complexities of a changing distribution environment. As early as 2016, SCE began publicly talking about the concept for an IT architecture to meet the growing number of distributed energy resources (DERs) and calls for greater reliability.
Once implemented, SCE’s GMS will consist of an advanced distribution management system (ADMS) and a platform for managing DERs. The GMS will: get information as it happens from field devices and DERs; crunch data; and help managers prepare for (and respond to) outages and load transfers. SCE hopes its ADMS will be a single source of truth for dispatchers, control center managers and others who oversee operations.
Picking one system, or linking them all
Which tool is the linchpin as utilities look for one, technological source of truth? Is it a resource management system, work management system, or, in the case of SCE, a GMS? No matter what direction a utility moves, utility managers should consider linking these systems by developing an application programming interface, or API, that enables each system to communicate with the others. Think of an API as triggering a message to take one person’s request and deliver it to another person who fulfills the request and returns the message with answers or options. Imagine using an API to share workers’ schedules with an ADMS, so managers can see, for instance, the availability of crews, IT staff or control center operators at a moment’s notice. That link would tell managers who is available to work and which available employees were closest to the trouble or nearest to a service center.
How one source helps customers
Customers benefit when their utility is able to ascertain one source of truth across systems. One view across systems provides managers with the situational awareness to make accurate decisions that improve safety, reliability, grid stability and even customer satisfaction. That single view of events at the moment things happen means the consumer of electricity will (in the long run) get less costly energy because the utility is more efficiently deploying resources and managing load. That, in turn, can delay rate-increase requests, provide better reliability and reduce the number and length of outages.
One source of truth safely speeds up restoration
With distribution automation, there are monitoring devices beyond the station breakers and automation of the isolating devices (i.e., switches and protective devices). With a device on the line that notes a fault current and a device down the road that indicates no trouble, control center personnel can identify that the outage occurred between a particular mile span or an even smaller distance. Without that automation, a utility would have to patrol, say, two miles of circuit instead of one mile. Automation lets a utility isolate and back-feed a line. If the outage affected 1,000 people, the utility could restore power to, for example, 900 customers in approximately 15 minutes via a quick analysis.
An API would then make it possible to immediately distribute a message from patrollers in the field via dispatchers to crews on the road. That message would tell crews the system restored power to approximately 900 customers and include a map of the outage and directions to the isolating device. Control center operators could also rely on APIs to pull information from resource management systems into a GMS to determine who’s closest to the outage and further speed up response. If utilities begin widely adopting APIs like these, managers can extract one source of truth from what is often a confederation of IT systems. That, in turn, promises to improve reliability, safety and satisfaction.