Power system analysis for DER – it all depends
by Tom Berry, Schneider-Electric
IEC TC 57 WG 17 is in charge of power system intelligent electronic device communication and associated data models for microgrids, distributed energy resources and distribution automation.
One of the challenges for distribution network operators is the need to analyze applications for connections of energy resources at LV and MV. Each connection request needs to be studied to determine whether there is any need for network reinforcement and/or to determine if the utility needs to define particular operating limits and operational modes. The studies require suitable data models that can hold the required parameters for the different types of study – energy forecasting, network analysis and perhaps dynamic analysis.
At the planning stage, engineers have some freedom to choose the appropriate level of modelling detail to suit what they want to study. Once a connection request is approved, the master network model will need to be updated to match the expected physical installation and provide the correct references for subsequent real-time monitoring, for example with IEC 61850 communications.
Choosing the right model involves a number of questions. One of the basic questions is “Where is the DER connected to the network?” This may seem obvious but can be contentious. In reality energy resources are connected to a private network, often LV, “behind the meter”. From the utility perspective, it is often sufficient to define a model of the energy resource at the point where its effects can be detected, the so-called “point of common coupling.”
The simplest model could be little more than a record of the energy resources connected to each meter point. This allows forecasting of aggregated load based on the connectivity model, or geographical regions. This needs basic nameplate data like the maximum capacity and the type of energy such as solar, wind. In some ways forecasting distributed energy production is similar to forecasting distribution loads with the important difference that there will not necessarily be good historical records.
As the ratio of generation versus loads increases on a feeder, it becomes important to study the effects of the DER on the feeder voltage profile. Modern power electronics can have sophisticated autonomous control systems. Standards like IEEE 1547 and IEC 61850-7-420 Ed2 provide a framework for defining control modes and settings of these “smart inverters.” Regional grid codes will provide rules on the range of the settings, but in general each distribution system operator will need to choose suitable setting values for their specific networks. Some academic studies have provided heuristic rules. Near the feeder head, the voltage is less affected by the energy resources, so constant power factor mode is sufficient. At the far end of the feeder, the voltage is more sensitive, and the energy resources need other control modes such as volt-var or volt-watt.
The most detailed form of modelling is required for dynamic studies that estimate the behavior of the frequency of the complete transmission system. This is computationally demanding and often studies use equivalent, aggregated models of the distribution feeders, include both the effects of the energy resources and the effects of different types of loads.
Tom Berry studied Electrical Engineering at Bath University, UK. For the last 25 years he has worked for Schneider Electric in the UK and France. Tom has worked on control center projects integrating SCADA systems within dispatch training simulators, transmission and distribution network management systems. He now works “closer to the edge” as a software architect for feeder automation RTUs. He is a member of several IEC TC57 WGs and the editor of IEC TS 62361-102 technical report on CIM-61850 harmonization.