by Richard Schlottmann, Senior NERC Reliability Specialist
Well, it’s that time again! PRC-019 re-validation is underway or has been completed for most folks and there are some interesting things coming to light. It seems there is a trend for facilities having to file self-reports after the re-validation efforts have uncovered instances of non-coordination. This is especially surprising given the initial studies showed limiters and protection elements were coordinated. How can this happen? Well, as time goes by, the industry continues to learn more about what components need to be considered in the coordination process.
The coordination issues are occurring across AVRs, relay settings and even plant equipment. Not only do limiters have to be coordinated but other protections such as Volts/Hertz and Stator over-current protection elements need to be considered. The 59S for example is the only protection available during a load-shed event since the Volts/Hertz protection moves with generator frequency and can move out past safe operating zones and so the Stator 59S element is critical to generator protection.
Another thing that has been observed is that Facilities with similar generators are seeing non-compliance issues since they are only performing the coordination study on a single unit and then finding out later that the AVR settings are not the same from AVR to AVR. Some of those self-reports are going all the way back to the first study that was performed for initial compliance with the Standard. The lesson learned here is that if you try to use the “like kind” methodology you need to review the AVR settings for all the units to ensure that the settings are in fact identical. If the AVR settings are not identical, you will have to either make them the same or perform coordination studies for all the AVRs and associated generator protection relays.
Traditional generators aren’t the only ones experiencing issues. Inverter based technologies are learning how to consider equipment that only provides reactive power support. For example, if a solar facility has both static and dynamic var compensation devices that are connected to the GSU or to the line connecting to the grid, do they need to be coordinated per the PRC-019-2 Standard? It can be inferred from the standard that as these devices are not affecting inverter output and only serve to support system voltage, they are then excluded from needing coordination per PRC-019-2. The same thing would apply to a wind farm that uses a synchronous condenser for reactive power contributions to the grid. Most facilities that have these devices are also locking the inverters to hold reactive power to a constant value between 0.95 and 1.0 PF and then calculating the amount of VAR support that is needed at the POI to maintain the voltage schedule provided by the Transmission Planner.
In closing, when reviewing or performing the re-validation of coordination for PRC-019-2, use up to date AVR and relay settings, compare all the AVR settings for all units, and determine if equipment included in the evaluation truly needs to be included. Should a self-report need filed, it is just another step along the path of continuous improvement to enhance BES reliability.