Navigating the DERMS Landscape

How to Prepare for ADMS Implementation

by Travis Rouillard


Navigating the ‘DERMS’ Landscape

One of the things I do as an industry consultant is teach courses on ‘Distributed Energy Resource Management Systems’ (DERMS) for DistribuTECH, EUCI, and utility clients.  Last week I presented at the CEATI General Meeting in Anaheim, CA to a group of utilities seeking more clarity on the business value of DERMS and confusion over similar functionality offered by ADMS (Advanced Distribution Management Systems) or DRMS (Demand Response Management Systems) vendors.  The discussion echoed similar conversations I’ve had recently with a variety of different audiences, all asking the same basic question – “What is the difference between ADMS, DRMS, and DERMS… and which one(s) do we really need to handle higher penetrations of Distributed Energy Resources (DERs)?”

While this is a question that can take hours to answer comprehensively, I figured it was worth a short article to scratch the surface.

What are the differences between an ADMS, DRMS, and DERMS?

For those not familiar with the acronyms or these systems, a brief primer –

  • DERs – Small scale generation like solar panels and wind turbines connected to the utility distribution system, usually behind-the-meter at a customer. Could also include intelligent loads, batteries, electric vehicles, microgrids, etc.
  • ADMS – A control room application for distribution operations that includes SCADA, grid management, outage management, and other ‘advanced’ functionality for powerflow analysis, volt-var automation, and fault isolation.
  • DRMS – An application used to manage demand side load curtailment programs. It keeps track of all the individual customer air conditioners, water heaters, lighting, or machine processes that could be interrupted by the control room to reduce energy demand during peak load periods or emergencies.
  • DERMS – An emerging application category that promises to help the control room predict the grid operational impacts of DERs at high penetrations, and potentially help mitigate reliability issues by interrupting or adjusting the DER real or reactive power output.

What do we need to handle our growing DER problem?

The simple answer for most utilities with modest DER penetration levels is ‘nothing’ – at least to handle DERs.  At low penetration levels they shouldn’t cause too many problems that would require you to run your control room any different.  Though there are lots of other non-DER reasons why a utility should consider an ADMS or DRMS.  ADMS can improve distribution grid reliability, improve energy efficiency, reduce outage durations, automate switching, etc.  DRMS allows customer load flexibility to be used to reduce peak power demand, replace emergency reserves, or avoid capacity upgrades.  But a DERMS is not necessary if you don’t have DER penetration issues.

For those utilities starting to see DER penetration impacts, the ADMS and DRMS solution vendors are keeping pace with market requirements and evolving their products to include more DER prediction and control functionality.  Leading ADMS products can use DER forecasts in powerflow studies, and interrupt DERs behind automated switches.  Most DRMS products can already handle real power control of distributed generators and batteries, and some are now enhancing their solutions to support the four quadrant control capabilities of modern smart inverters.  If one or both of these systems are already on your roadmap, then you are probably moving in the right direction.

The need and role of DERMS is a more complex question.  To some extent, the existing DERMS market solutions are hybrid subsets of ADMS and DRMS.  They include some features of both (ability to do a distribution feeder powerflow, or send a dispatch schedule to an individual customer side asset), but are not really good substitutes for either.  They also include some new features that don’t really exist yet in most ADMS or DRMS products – like calculating solar forecasts or optimizing battery charging schedules.   DERMS are thus a great short-term option for utilities seeking to do a small scale DER pilot, or addressing specific problem areas on their networks with a DER-enabled non-wires alternative solution.  But it is left to be seen whether a utility will ultimately need all three systems (ADMS, DRMS, and DERMS), whether DERMS vendors will steal some ADMS/DRMS market share, or whether the existing ADMS/DRMS vendors will eventually add missing ‘DERMS’ features and close any remaining gaps.  Only time will tell.

How do we decide what and when we need to do something?

One approach is to use the DER Operational Maturity Model framework that GridBright developed in collaboration with CEATI International.  It is a variation of the Smart Grid Maturity Model published by the Software Engineering Institute (SEI) at Carnegie Mellon University (CMU).  It describes the evolutionary steps of DER operations at most utilities, identifies the key processes, capabilities required, and technology needed at each step.  A summary presentation is available here.  In the next few months we will be publishing our latest CEATI report, a distribution operations case study using the methodology at a large Canadian utility – “A Roadmap for Improving Maturity of DER Management at Distribution Utilities”.   The roadmap specifically outlines the business drivers, triggers, and timing for DER management technology upgrades.

Of course, GridBright also offers custom training and consulting services to help utilities create their own Grid Modernization strategy and technology roadmap, especially in the areas of ADMS, DRMS, and DERMS.  Read here for more information about how we can help.
Travis Rouillard, GridBright CTO

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