Sean Eade, Head of Innovation and Architecture, TRC Digital
In recent years, there have been growing discussions around the increased penetration of distributed energy resources (DERs) and their impact on the grid. The pressure and challenges will continue to rise for utilities and non-utility grid operators as the number of DERs increase due to factors including:
• State and federal clean energy mandates and emissions targets.
• Increased zeal for spending on grid modernization from the passage of the Infrastructure Investments and Jobs Act (IIJA).
• Increased pressure from more sustainability-minded consumers for low/no-carbon choices and options when it comes to energy.
The discussion of DER proliferation necessitates the conversation of how utilities will manage and integrate them into the grid. Two primary schools of thought emerge—via the advanced distribution management system (ADMS) or via a distributed energy resource management system (DERMS).
First, let’s define these systems and the current landscape a bit. Currently, we are in the beginning stages of utilities investing in either system, so the question of what system will ultimately control DERs is early days; however, given the implementation cycles of these systems, it is something utilities need to consider now.
“The ideal answer to managing DERs is through both ADMS and DERMS due to their different strengths.”
Typically, an ADMS manages all distribution network assets—switches, relays, caps, taps, and large renewable generation resources, including PV solar, storage and wind farms all directly connected to the grid. The vast majority of the larger front-of-the-meter (FTM) DER assets are connected and controlled by the ADMS. It thrives on larger asset data, or aggregations of data to large nodes in its network. It does not, however, adjust to monitor large sums of smaller assets, and the ADMS isn’t meant to manage real-time end-customer data or assets.
This consumer realm is where the DERMS thrives. A DERMS is meant to aggregate, simplify and forecast massive amounts of DERs, including small-scale residential or commercial solar and battery storage, and electric vehicles. DERMS is also the primary software platform for market participation, arbitration and customer-facing energy-saving programs.
The ideal answer to managing DERs is through both ADMS and DERMS due to their different strengths. ADMS and DERMS are typically both trying to control assets but for different reasons—grid reliability reasons vs. customer-facing reasons.
The ADMS helps utilities maintain resilient and reliable power to their customers. This software monitors the state of the grid, manages voltage and frequency, and enables utilities to optimize their operations. Optimized operations include forecasting and planning energy needs as well as better, more coordinated responses of field crews in multiple substations and feeders. DERMS calculates forecasting and other measurements, considering current conditions and constraints, and makes it available to the ADMS or other participating syemergencies and outages.
The DERMS helps a utility with their market participation and customer-facing programs and engagement. DERMS enables utilities to value stack the benefits of DERs by layering usages onto resiliency needs. It manages the multitudes of smaller customer-owned, or utility-provided assets and helps energy management programs to succeed. DERMS can streamline customer management and enrollments, program design, and energy transactions into the markets. Perhaps most importantly, DERMS can aggregate all the disparate customer data points into single nodes that the ADMS can incorporate into its grid management operations.
ADMS is the governing body for the large, grid-connected assets, while DERMS manages the FTM and behind-the-meter (BTM) assets. DERMS is responsible for managing aggregations of assets and for harmonizing DER orchestration in response to the dynamic aspects of the grid, such as when groups of DERs span across stems as needed.
There are still some questions that need to be answered when embarking down the road of automating end-to-end monitoring of all DERs on the distribution system. We need to understand how to prioritize DER schedules across grid services, market operations and customer programs. This includes aspects such as:
• Who will be the operator of the DERs, and have ultimate control over what the assets are used for and when?
• What prioritizes the assets If they are being used for market participation but are needed for grid reasons (stability or reliability)? What system will override the other when it comes to a conflicting assessment of the current energy demand?
Though both systems serve different and necessary purposes, these questions may create the biggest challenge for utilities as they choose to implement both technologies. But the fact that we are even to the point where we are having this conversation is exciting. It points to the shifting nature of the energy mix in the U.S. and the motivated interest of consumers to understand their energy usage and their impact on the grid.