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Ten Questions on Digital Grid Management, Answered

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Gary Rackliffe's picture
VP Market Development & innovation, North America Hitachi ABB Power Grids

Gary Rackliffe is Vice President for Market Development and Innovation, North America, leading Hitachi ABB Power Grids' smart grid, grid modernization, digital transformation, and energy...

  • Member since 2004
  • 4 items added with 10,369 views
  • May 2, 2019

In October I hosted a webinar on distribution grid management that focused on some of the challenges, trends and technologies facing the utility industry, in particular the growth of renewables and the digitalization of distribution grid operations. Following are some of the questions that came up during and after the session, along with brief responses.

1. Will ADMS become more distributed in the future, or will these systems remain centralized?

Generally, ADMS – Advanced Distribution Management Systems – are centralized and combine distribution management systems for control room operations, outage management, SCADA, distributed energy resource management, and advanced applications such as automated switching and volt/var optimization. ADMS systems are also integrated with customer information systems, geographic information systems, advanced metering systems, communications, and mobile workforce management systems. Some functions, such automated switching and volt/var control, can be performed at the grid edge and the status change updates communicated to the central operations. There may be other opportunities to automate certain grid functions via ADMS, but I expect most of the things a distribution management system does will continue to be managed in a centralized control room environment.

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2. Islanded operation of microgrids is quite challenging when compared to grid connect mode—what is the best way to manage voltage levels and maintain reliability?

Operating a microgrid in an islanded mode does create challenges in managing voltage and frequency for the microgrid, particularly if operating with 100% renewable generation. ABB controls for battery energy storage systems or flywheel energy storage systems enable the storage systems to be the grid-forming devices for islanded microgrid operations. When installed as part of a microgrid that can be islanded when there is a grid disturbance, DERs can improve reliability for critical loads or remote locations.   

3. What is the outlook for storage with regard to its role in microgrids and as an enabler for renewables?

A key driver to answering this question is regulatory policy. Utilities will not invest in grid resources unless there is clear cost recovery and return on investment, which in turn must be justified by the improved grid reliability and resilience. DER developers will invest in microgrids and storage behind the point of grid interconnection to complement renewable resources, comply with grid codes, provide capacity firming, and shift generation to align with peak demand.  

There are operational challenges, too, of course. Storage de-couples generation from demand and increases the flexibility of the grid, but it increases the complexity of grid management because the storage system has to be modeled and controlled like any other resource. Storage is different, of course in that it can operate as either generation or a load. Also, customers might operate behind-the-meter storage resources in a manner that supports their interests but not necessarily utility operations. For this reason, energy storage works best as part of a microgrid.

4. How will deep learning impact the utilities?  

Deep learning is an application of artificial intelligence and a subset of machine learning. It refers to neural networks with more than one hidden layer. More layers allow for the neural network to fit more complex functions. For example, utility load forecasting has been based on neural networks for some time, but distributed energy resources are making the forecasting more complex. Future distribution grids will have connected renewables, EV charging, and energy storage. AI can use second-generation neural networks to predict generation and demand based on historical energy data, weather data, date-time aspects, and other factors.

5. What exactly is the difference between ADMS and DERMS?    

An Advanced Distribution Management System (ADMS) combines distribution management system functions for control room operations, storm response and outage management, SCADA, distributed energy resource management, and advanced applications such as automated switching and volt/var optimization. A Distributed Energy Resource Management System (DERMS) addresses grid operations with DERs including control of smart inverters, volt/var optimization, and protection and control. DERMS also manage the virtual power plant (VPP) functions of registration, forecasting, aggregation, dispatch, and settlement for services provided by DERs. This could involve utilities or third party aggregators. A full-function DERMS is best deployed as an integrated part of an ADMS to leverage the network model and power flow in the ADMS to validate DER dispatch schedules.

6. Can you discuss the challenges of restructured systems with competitive generation and retail with regulated wires companies (e.g., ERCOT) vs. vertically integrated utilities?  

There are a lot of challenges and discussion regarding restructured grid systems versus vertically integrated utility systems. One challenge that I think needs to be addressed is the underutilization of utility assets. In a deregulated market, a wires company has limited (maybe no) incentive to reduce system peak demand. Reducing peak demand reduces generation capacity costs (and T&D costs). In the ERCOT market, retailers can take advantage of lower cost off-peak generation and make it available to their customers who in theory will shift demand to off-peak. Texas has the advantage of smart meters in place to measure when and how much energy is consumed.

Another challenge is that while renewable generation can be curtailed, it is only dispatchable when the sun is shining or the wind is blowing. As a general statement, the market mechanisms are not in place to encourage consumption when renewable generation (with near-zero marginal cost) is available and to avoid consumption during peak load periods.

7. What do you mean by “transactive energy?”   
There are many available definitions for transactive energy, but this definition is from the GridWise Architecture Council: “The term "transactive energy" is used here to refer to techniques for managing the generation, consumption or flow of electric power within an electric power system through the use of economic or market based constructs while considering grid reliability constraints.” A layman’s definition might be “a distribution-level energy market that enables energy transactions for suppliers and consumers at the grid edge.”

8. Do you envision any challenges for the transmission network with rising DER penetration?

The challenges of increasing DERs (and renewable generation) are often discussed in terms of impact to centralized generation resources. Germany and California are well documented examples. From a transmission perspective, California may have challenges in capacity requirements to export available solar PV power when solar energy peaks in the state, and similar capacity requirements to import power in the evening to meet peak demand.

More broadly, renewable resources—especially wind—are often located far from load centers, which could require investment in transmission to bring their output to market. This is not so much a technical challenge as it is a financial, logistical, environmental and regulatory one.

9. Is there a DSP solution available yet?

“DSP” or distributed systems platform is part of the NY REV initiative and refers to a distribution or grid-edge market to facilitate participation by DERs. New York is currently piloting DER technologies and DSP specifications are evolving. Current focus of the industry is mainly on DERMS pilots and specifications and ABB is addressing this market with our ADMS/DERMS product. We also have economic dispatch and optimization software and microgrid controls for behind-the-meter or islanded systems with renewable generation, storage, CHP, thermal generation (such as diesels or natural gas), and controllable loads.

10. How do you define "grid analytics" vs. “utility analytics”?

Today, grid analytics focus on 1) demand or load forecasting, which is critical for generation economic dispatch and grid security; 2) grid performance such as storm impact, outage assessment (cause, extent, and estimated time for restoration), and post-event grid hardening; and 3) asset performance management based on analysis of sensor data, loading information, nameplate data, inspection and maintenance reports, peer group comparisons, etc. Utility analytics are broader in scope incorporating meter data analytics to investigate load patterns, demand response, meter connectivity, grid loading, and fleet management.


Gary Rackliffe's picture
Thank Gary for the Post!
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Matt Chester's picture
Matt Chester on May 2, 2019

This is great, Gary. Thanks for sharing for those of us unable to attend the webinar.

Another question I'd add-- are there specific geographies, demographics, or regions that you think would benefit the most from the integration of ADMS? What types of areas should be looking into this most critically?

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