Microgrids: Building Block of the Grid - A Perspective on the Evolution of the Grid

Microgrids – Building Blocks of the Grid

There has been much discussion over the past years regarding microgrids and intentional islanding.  Much of the talk results in polarized viewpoints regarding the development, implementation, usefulness and practicality of renewables based locally controlled distributed microgrids. Microgrids have evolved from practical, mobile and reliable power networks and from pockets of consumers around a consistent power source to distributed models using virtual power plants and distributed generation together with designed for purpose equipment on traditional distribution networks.  However, the underlying theme appears to be reliability and resilience – even for utility owned and implemented systems. As microgrids and DERs in general continue to proliferate, how will the grid evolve to be able to best capitalize on the features provided by these building blocks?

Up until recently, the integration of renewable energy sources has been sporadic and opportunistic relying on utilities or independent power producers (IPP) to develop large utility scale power plants with longterm power purchase agreements.  With the increased availability of technology coupled with reduced manufacturing costs and pricing in addition to utility and government incentives, the integration of renewables has penetrated the Commercial & Industrial (C&I) and Residential sectors. With the additional advent of advances in battery and storage technologies, paradigms such as time shifting allow renewables to be at par with other dispatchable resources in terms of both demand and price. Many jurisdictions have mandated the combination of renewables and storage so that third party prosumers can take advantage of concepts such as time-shifting to be able to supply the distribution utility with a reliable source of dispatchable power. This combination coupled with its profit making potential has been the catalyst required to increase the level of DER penetration.

The questions still remains, how does the utility manage the increasing level of renewable resources within its service area?  How does it know how much to dispatch and when?  And How does it know which resource is most valuable or profitable at a given point in time, based on system characteristics? Currently there are a number of DER Management System (DERMS) products on the market which have features such as self-registration on the part of the DER owner and which also provide SCADA like visibility of DER resources along with the ability to dispatch the resources as desired to the utility.  These systems are mostly built on a centralized controller gathering information from many distributed sources and communicating through a, mostly insecure, communications network.  The load forecasting is rudimentary at best and is still heavily dependent on historical usage and manual communications.  Often traditional processes of reserving capacity on feeders are also still used. Of course the means by which this is done varies between service areas as various utilities have implemented different solutions to empower DER owners to provide power to the grid. What would happen if utilities had access to realtime information on supply and demand?  How would this change the operating practices?

Many utilities use power system simulation software to create a model of their system and subsequently calculate power flow, constraints and demand.  This software is typically configured independently of the operating system model and is also only run infrequently and only updated quarterly to reflect implementation of capital projects.  Lately, there are some SCADA and Advanced Distribution Management System (ADMS) vendors who have overlaid a power flow model with their existing SCADA or DMS system.  Similarly, ADMS vendors have also created modules for DERMS so that their ADMS offering can have a wider application and appeal. While all of these advances are promising and provide valuable contribution to the industry, the final piece of system wide optimization based on a used configurable objective function has not yet been integrated. More sophisticated ADMS have integrated GIS information with SCADA, power flow, Customer information (CIS) and sometimes even billing information all in one view.  As DER owners develop and connect projects then they are added as assets to the system. Utilities will wish to know what the power flow is at each node in their system in realtime so that locational pricing can be established and active renewables and storage can be prioritized and dispatched to accommodate load variances. They will wish to know how best to alleviate constraints profitably while satisfying the regulatory requirements of the distribution system operator (DSO). This arrangement of a large number of small generation assets scattered through the service area is not the historical normal for most utilities. Most utilities are used to having an unlimited supply provided from the grid at one or multiple points from which it can distribute to the individual ratepayers within the service area.  Behaviour and attitude is starting to shift as the utility increasingly has to act as a balancing authority at the distribution level in addition to being the distribution system operator and potentially a DER owner, the utility needs realtime visibility into the distribution system in order to accomplish these tasks.  This realtime visibility and powerflow must be combined with network models, GIS systems SCADA functions and customer information for the operations staff to have true grasp and insight into the current and forecasted states of the distribution system.  Control room operations need to have confidence that the optimized state of the system consists of the ideal combination of traditional resources, DERs and switching to satisfy the objective function, whether optimized for profit, minimal constraint or maximum use and deployment of DERs.

When the utility has empowered and enabled prosumers and DER owners to deploy their resources and when it has the ability to dispatch and monitor the system in realtime so that not only has visibility but also control, it will have the ability to start combining the strategic priorities and objectives with the tactical deployment of its resources.  The natural evolution of DER penetration is that once DER levels reach a threshold point then it will be appropriate for the utility to set up a distribution level market and for the utility to manage the new role of distribution system operator. Distribution level markets will enable DER owners, aggregators and other purveyors of generation capacity to provide their services in the market where pricing is locational and dependent on demand, capacity, supply, constraints and other system related parameters.  The market and subsequently the demand in the market will drive the transition and implementation of physical assets.  The utility will have to continue to be innovative in its approach and the market will provide a new venue for the utility to demonstrate its customer-centric approach. Renewable DERs and particularly renewable based microgrids will be the basic building blocks of the new grid – taking a grid or grids approach which has resiliency designed into its basic form.  Decisions will have to be made either privately or in the newly developing marketplace as to how resources would be shared across the boundaries of the individual microgrids and who manages the service area as a whole.  As utilities continue to adapt and evolve, they continue to empower the integration and penetration of renewable DERs whether as a part of a microgrid or on a stand-alone basis and they will eventually enact the new business model of enabler of renewables, manager of grid assets, overseer of grid of grid operations and ultimately as the distribution system operator.

Microgrids are evolving to be complex DERs on their own, capable of providing a multitude of services to both utilities and owners.    As renewable based microgrids continue to be deployed and connected, the role of the utility will continue to evolve from a primarily asset based organization to that of a Distribution System Operator. While the utility will likely still maintain the wires and interconnectivity of the system, its primary concern will shift to balancing the excesses and shortfalls of each of the individual microgrids in the larger “grid of grids” scenario. DER owners will provide both system power and system support, regulators will adapt the rules to ensure that rates are reasonable and that utilities and DSOs operate efficiently. Consumers will have choice as to how and to what extent they are able to participate in the evolving transactional distribution marketplace. Customers and ratepayers will be comforted and confident that they have control over their power sources, that the power is as inexpensive as possible and that power is available to them when they need it. 

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