Hardware in-the-loop testing for microgrids

Author: Kati Sidwall, RTDS Technologies, Canada

Microgrid Control Testing - de-risking the Deployment of New Technology in a Complex System

Borrego Springs, a small community located at the end of a single transmission line in southern California subject to extreme and volatile weather conditions, has experienced many power outages historically. For this reason and the fact that the community already had a high concentration of resident-owned rooftop solar PV plus nearby commercial PV systems, it was chosen by the local utility, San Diego Gas and Electric (SDG&E), as an ideal location for a renewable energy-based microgrid to increase the community's energy resiliency. Involving a utility substation, two substation batteries, a large ground-based solar PV array, megawatts of customer-owned rooftop PV, three distributed battery energy storage systems, and about 2,500 residential and 300 commercial/industrial customers, the goal of the microgrid is to provide uninterrupted energy to the community.
Real time simulation played a major role when SDG&E decided to upgrade the microgrid to involve an advanced microgrid controller. Implementing the controller enabled them to control the microgrid both locally and remotely from their distribution control center, increasing both the reliability of islanding/reconnection and their Electric Distribution Operation (EDO) department's capabilities in managing customer-owned distributed resources. EDO did not have significant experience with this prior to the project.

Both control hardware in the loop and power hardware in the loop techniques were used to interface the simulated grid to physical PV and battery inverters, lower-level physical distributed generation controllers, and a substantially similar copy of the centralized microgrid controller installed on site. The testbed allowed for the functional testing of the microgrid controller. This is an example of a sophisticated testing setup, made possible by a real time simulator, but complex to execute for many reasons, including a high penetration of PV and the potential for interaction between parallel converters (now characteristic of many systems worldwide). (Figure 6).

A data manager gateway, which also acts as a communication protocol converter, was used to create an interface between the simulated grid and the microgrid controller. The data manager was compatible with both DNP3 and MODBUS protocols and as such was able to communicate between the microgrid controller, distributed controllers, and simulated system, all of which are compatible with either DNP3 or MODBUS. The real time simulator in this case was equipped with Ethernet-based communication capabilities to allow it to communicate to external devices in real time via DNP3 or MODBUS (among other protocols).

Various scenarios were simulated, sending microgrid values to the controller and interfacing its responses, such as open/close breaker and real/reactive power setpoints, back into the simulation. Individual asset tests were performed in order to determine the response of each asset to changes in voltage and frequency. In this way, the functional requirements of the controller were evaluated, and the SDG&E team became more familiar with the remote control of distributed assets.
Southwest of Borrego Springs at the University of California San Diego (UC San Diego), another microgrid control testing project took place. UC San Diego has an advanced campus microgrid including a diverse generation portfolio including a megawatt-scale fuel cell, solar array, gas-turbine cogeneration plant, energy storage system, chiller plant, gas and steam plants, and emergency diesel generators. With centers for medicine, science, and engineering as critical loads, the campus is required to provide reliable, undisrupted power if necessary. A microgrid monitoring and control system, consisting of controllers, protective relays, meters, and visualization tools, was put in place with expected functionalities including contingency- and frequency-based load shedding, peak shaving, generation control, adaptive protection, and islanding detection and decoupling based on synchrophasor measurements.

Dynamic performance testing of the control system was performed with a real time simulator. The system put in place protects the UC San Diego microgrid at wide-area speeds of less than 25 milliseconds.
To mimic the field setup, the campus microgrid model was connected in a closed-loop with load-shedding controllers, asset controllers, and protective relays. The controllers involved use a range of non-wires communication protocols such as DNP3, MODBUS, IEC 61850, and IEEE C37.118 for synchrophasor measurements - all of which were compatible with the real time simulator to enable bidirectional communication between the power system model and the external control hardware.  Conventional analogue output was used to interface values from the simulated instrument transformers to the relays, as well as digital input and output to handle breaker status and command signals between the simulation and the relays.

The system events simulated in real time - and which the microgrid controller proved to fulfill its operational requirements successfully - included:

  • Decoupling of the microgrid due to a frequency disturbance with a decay rate of 2.5 Hz/s:  As the utility grid frequency decayed past the defined threshold, the microgrid successfully decoupled from the utility grid and loads were shed on the megawatt scale. Gas generators switched to isochronous mode
  • Loss of generation within the microgrid at the gas plant:  When the gas plant generator was tripped within the microgrid, power flow increased to the utility breaker (exceeding the normal rating). In response, the controller shed loads to prevent overloading and tripping of the utility transformer tie and the microgrid continued normal grid-connected operation
  • Loss of intertie breakers within the microgrid, producing islands:  A disconnection of intertie breakers created two islands within the microgrid. When a gas plant was then tripped under load, causing a contingency event, the controller was able to shed loads based on priority within the required island
  • Three-phase fault on the utility tie and loss of generation:  A chain reaction of closely timed contingencies was simulated. A fault that tripped utility tie breakers caused the fuel cell, one steam generator, and one gas generator to also trip within thirty seconds.  Load shedding was initialized and the microgrid was able to stabilize and continue to operate as an island (Figure 7)

Looking Ahead
It is clear that more engineers are using real time simulation as a tool to support their work with microgrids and distributed energy resources. As more microgrid operational and control standards, specialized microgrid communication protocols, and hardware options become available, the potential need for hardware in the loop testing will grow, and the demand on real time simulator providers to equip their products with sufficient facilities will be high. As we continue to understand the benefits of hardware in the loop testing in this space and the situations where it is a particular advantage or requirement, we will have a better idea of where real time simulation sits in the microgrid engineer's toolbox. For now, we must share information between not only technology leaders, but also policy makers, regulators, and thought leaders as microgrids continue to push the envelope of what we demand from our power systems.

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