# Valuing Resilience Benefits of Microgrids for an Interconnected Island Distribution System
## 4 Proposed Nested Microgrid Concept  
The preliminary microgrid studies suggest a major leap in technology adoption and modernization. The designs are executed so that the resilience valuation presented herein will be realized at least cost to the utility ratepayer. The valuation metrics guide the design, in that they require a highly robust and resilient design to hurricanes to achieve the calculated benefits, and the stated annual expected avoided loss can be a baseline for the cost-benefit comparisons for the design. When planning the execution of this project, it is understood by the authors that it may need to be staged in three phases. The first phase will focus on delivering resilience benefits quickly by upgrading existing assets and their controls and protections, along with the integration of a microgrid controller to enable island-wide microgrids to provide autonomy to each of the two islands in the event of a power outage. The system will be planned and studied with Phases 2 and 3 in mind to consider how the microgrid controller, protection scheme, communication requirements, and distributed controls will evolve under each of the phases. This staged approach includes energy efficiency measures, the placement of automated switches and sensors, and the development of an evolving operations concept. Phase 2 will integrate new renewable technologies into the control architecture, developing resilient layers within each microgrid. Finally, Phase 3 will endeavor to operate the two island microgrids in parallel, maximizing benefits under both blue sky and black sky days. Phases 2 and 3 will enlarge the scope of the microgrids by incorporating a layered community microgrid concept, that considers the behind-the-meter (BTM) microgrid-- residential or commercial/facility level--as the fundamental building block of a resilient grid architecture, shown conceptually in Figure 6. Each BTM microgrid is then added to form community microgrids at the level of the service transformer and extended further to the feeder and substation level as part of the substation microgrid commissioned in Phase 1. This system of systems architecture breaks down the complexity of the problem and can be dynamically managed to scale to hundreds of DER assets, including BTM and front-of-the-meter (FTM), utility-owned, or third party owned assets. These DERs can even include mobile assets, such as existing mobile diesel generators or mobile energy storage systems (MBESS) to quickly optimize the system following a major event. All systems are integrated to microgrid controllers by implementing monitoring and controls over a field message bus, with automated discovery and standard data models to favor interoperability and rapid reconfiguration of the system, as illustrated in Figure 7. The island microgrid controller will also provide integration to the SCADA system and can coordinate with back-office applications, such as energy management system (EMS). Resilient operation of the microgrid following major events will also depend on the availability of both DER resources and communications for data exchange between different microgrid components. The BESS will provide the appropriate energy during and immediately following the event together with the diesel generators, when PV generation may be non-existent or minimal. A couple of hours following the event, available PV generation will then replace the diesel generation and can provide significant diesel offset should outage of the substransmission connection persist for multiple days or weeks. With regard to communication network resilience, cellular, meshed network and even low-earth orbit (LEO) satellite communication options are being considered for redundant