• x

    Investor-Owned Utility in Illinois

    Electric distribution utility | 1.2 million customers | 43,700 square miles

    Investor-Owned Utility in Illinois case study

    The biggest benefit of this solution is that it enabled the electric provider to augment the FLISR functionality to its existing SCADA system, eliminating the need to make sweeping changes to the existing system and provided a very scalable approach to distribution automation without making a cost-prohibitive investment.

    The Challenge

    The investor-owned utility was looking to improve upon its manual outage restoration processes which caused their customers to experience sustained outages. Locating a fault or loss of voltage and sending the repair team to fix it manually could take six to eight hours to complete. One-third of that time was typically spent determining the fault. Often, the source of an outage was not known until a customer reported it.

    The utility company was looking to improve its power reliability on multiple existing 69 kV circuits and reached out to one of its long-time equipment suppliers. As the vendor did not manufacture sub transmission equipment to serve at the 69kV voltage level, the vendor’s engineering team worked with the existing SurvalentONE SCADA system to provide fault location, isolation, and service restoration (FLISR) functionality at the 69kV voltage level – something that had not been done before as, typically, FLISR was used at voltage levels of 5kV to 38kV.

    The Solution

    The utility selected SurvalentONE FLISR for two reasons – its ability to integrate with the existing SurvalentONE SCADA system and its option to operate in three modes: automatic, semi-automatic, and manual mode, while most other solutions offered only automatic and manual modes.

    SurvalentONE FLISR software was installed on a server in a secure location. The server processed all the information it received from the SCADA system and, in semi-automatic mode, advised operators on the best actions to minimize the impact of an outage. Operators were then able to implement the suggested actions.

    Initially, the utility incorporated 12 switches. Over the next two years, they scaled to 44 switches across six 69kV circuits that provide real-time and critical data that can be analyzed, acted upon, and corrected. Once the solution proved itself in semi-automatic mode, the utility also switched the fully automatic mode for all events.

    Request More Information