Electric grids are immense machines that span counties, even entire states, bringing power to homes and businesses. So how do the electric companies know what’s happening on their lines? How much power is being delivered? What equipment needs to be replaced? These are important questions that electric co-ops spend a lot of time and money to answer.
For years, electric co-ops relied entirely on in-person inspections to determine asset conditions and calls from members to discover outages. During and after storms, this could mean lengthy recovery times as supervisors evaluated the available info and decided where to send line crews, who then searched for damaged lines to make repairs and restore electric service. Even normal operations required personnel to be sent into the field constantly to perform manual inspections.
Today, electric co-ops may choose from a variety of technologies that give near real-time feedback on the health of the grid. Monitoring and automation technologies are becoming more affordable and gaining more functionality leading to greater use in the field.
Two common technologies in this space are Supervisory Control and Data Acquisition (SCADA) and Automated Meter Infrastructure (AMI).
SCADA systems have evolved since their original development in the 1920s. Modern systems take advantage of communication, monitoring and automation technologies to give utilities a real-time picture of how substations are performing and make changes as needed. At the end of the line, AMI, also known as smart meters, report back to the utility how much energy consumers use, often on a 15-minute basis. Utilities can “ping” these meters to determine if they’re still receiving power during storms or other types of outages.
Beyond AMI and SCADA, utilities explore a host of other sensor technologies for niche applications including fault location, power theft detection and asset management. These applications are being enabled by a new wave of inexpensive sensors that cost one-tenth of what they did a decade ago.
When a fault occurs on a transmission line (the large power lines that carry power from plants to substations), they create transient waves on the lines. By placing special sensors on transmission lines and measuring the time that a wave reaches two of these sensors, the location of a fault can be accurately and quickly determined. This lets the utility know exactly where to send repair crews.
Across the U.S. electric industry, roughly $6 billion worth of electricity is stolen annually, which leads to higher prices for everyone. Traditionally, one of the best tools for identifying power theft is visual inspection of meters for signs of tampering, but with AMI systems, utility personnel aren’t visiting meters in-person as often.
Load-monitoring sensors—often called current transformers (CTs) or current sensors—can be placed on distribution power lines to help catch significant losses along a line, from theft or other reasons. Data gathered by CTs can be reconciled with meter readings to investigate discrepancies between the electricity passed through the line and the electricity measured by the meters. CT devices are valuable for diagnosing line loss due to other problems, such as conductor damage or aging transformers.
For members, these technologies provide three primary benefits: increased reliability, reduced outage times and lower prices as the utility manages employee time and resources more efficiently. As sensors continue to improve and drop in price, expect to see more real-time grid monitoring.
Source: NRECA
