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The Struggle for Distributed Energy Resources Control: New ways to manage an expanding landscape of energy generators

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As the energy industry shifts toward cleaner and more sustainable models, it becomes increasingly critical for utilities to be able to manage and control the customer side of the power grid. One proven way to do that, Demand Response (DR) programs, have been common for many years. These programs typically incentivize participants to shift their energy usage away from peak consumption times, in order to reduce dependence on costly and inefficient peaking power plants and to overcome weaknesses in transmission and distribution systems. In most cases, DR programs use either direct energy reduction/increase requests or variable price messages to attract customers to participate.

Distributed Energy Resources (DER), however, now vastly increase the complexity of demand-side control by introducing more generation assets at the expense of grid reliability and power quality. Industry communications and connectivity standards, like OpenADR, which have long helped utilities manage DR resources, can now also play a similar role with the growing pool of diverse DERs. The latter not only includes renewable energy but also energy storage, electric vehicles (EV), and EV charging – as well as traditional DR targets.

But how much control do utility operators need to effectively manage all the resources in their power grid? This question still seems open ended at this point in time, though there are some use cases and models available that can help establish some ground rules.

In our view, DERs can be categorized in two groups based on size and ownership. However, there is a gray area between the two that will have to be addressed in the future as well.

  1. Large, utility-controlled systems

It makes sense that distributed power generators, battery storage, and resources of any kind with capacities larger than a certain (as yet undefined) threshold need to be controlled by the utility operator. Just like a fossil fuel or nuclear power plant, the generation capability of these large-scale DERs is and will be vital for the grid stability – and we can assume that there are not too many of these resources around. Therefore, tying them into the control network of the utility appears to be the right thing to do. Cyberattacks can also be kept in check with this limited number of endpoints.

  1. Small, customer-owned systems

On the other side of the scale, we find the (truly) distributed resources, such as privately owned residential solar, EVs, home batteries, and the like. These DERs, taken together in functional or geographical groups, will also represent a large percentage of future generation and will somehow have to be managed by the grid operator. However, there are several challenges. Such resources are not owned by the utility but by the customer, so full access to the controls may not be readily granted by owners. Further, we are now talking about thousands, if not millions, of small-scale systems. Addressing and controlling every one of them will be challenging from a data connectivity, analysis, and cybersecurity perspective.

On the horizon

Moving forward, utilities and grid operators will generally have to decide which resources fall into which of the above categories. There are also some regulatory efforts currently being explored on how to manage smart inverters (for example). One such regulation is California Rule 21 CSIP (Common Smart Inverter Profile - http://www.cpuc.ca.gov/general.aspx?id=4154). Rule 21 requires that smart inverters open up their control interface, either using the framework’s default interface based on the IEEE 2030.5 control standard, or using other established standards upon mutual agreement between utilities and resource owners. One of these alternatives can be OpenADR.

As a comparison, IEEE 2030.5 provides direct device control functions to set parameters like Volt/VAR curves and many other values in each inverter. OpenADR, on the other hand, enables grid operators to use a standard to communicate higher-level requirements, objectives, and incentives (not unlike DR programs) to aggregators, control systems, consumers, and – if really needed - to inverters directly, to empower them to modify their associated DERs and contribute to the grid’s stability. Rather than directly controlling DER resources, OpenADR informs the customer and motivates them to act, based on pre-programmed or dynamic sequences of operations. Many of the Rule 21 CSIP requirements can already be covered by OpenADR 2.0b in this fashion, and the OpenADR Alliance is developing additional extensions where needed. 

Another much discussed (but not yet too commonly implemented) aspect of DER control is Transactive Energy (TE) messaging. There are many definitions for TE, but the basic premise remains the same in most of them: DRs and DERs can trade their energy generation or usage with utilities, or, in an even more distributed future, among themselves. Utilities can offer spot prices for energy just like other product retailers and see if specific customer segments will buy or sell energy into the market.

A recent, almost-completed California project successfully demonstrated its technical implementation and the willingness of customers to react to price offers (albeit in a system-to-system communication scenario based on preset price levels and actions). More information can be found at https://rates.energy/. Several other similar projects are in the works, many of them using OpenADR.

So what’s next? The OpenADR Alliance is closely following emerging use cases and business models for Distributed Energy Resources and Transactive Energy. While the base specification OpenADR 2.0b (also known as IEC 62746-10-1: 2018) will remain unchanged, the Alliance is working on extensions for additional DER management, grouping, and TE messaging.

Rolf Bienert's picture

Thank Rolf for the Post!

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Discussions

John Benson's picture
John Benson on February 7, 2019

Hi Rolf:

Several things:

I have been aware of Open ADR for several years, and have been on your Newsletter distribution for this time. As far as I know it's the only communication infrastructure that provides all of the functions required for current DR plus is extensible to meet any conceivable future requirement.

In one of our genesis documents for my firm, Microgrid Labs, it is prominently mentioned twice. One in conjunction with PG&E’s Automated Demand Response Program, and then in a later section, “Specific Mechanisms for Collaboration” (between utilities and large facilities), it is described in detail.

If you look at my CV you will see that I have experience in DR (no I'm not fishing for a job, I'm semi-retired and very happy with what I'm doing now).

The link below will take to a recent CPUC staff proposal. They are doing a major overhaul of the Self-Generation Incentive Program, and also moving it into the residential market. I'll let you read the proposal for the gory details, but the whole idea is coupling a tariff with a peak rate starting at 4:00 with PV + storage to reduce greenhouse gases.  This program will use the PV to charge the storage before 4:00, and use the storage to service peak demand thereafter (until 9:00). This will avoid the use of combustion turbine-based peaking resources during both the charging time and the peak.

http://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M226/K975/226975698.PDF

Roughly every week or so I post an "educational" paper on Energy Center. In about 2 weeks I will post an update on PV plus energy storage systems (I've done a couple of earlier ones), and it will include a section on this proposed program.

-John

 

John Simonelli's picture
John Simonelli on February 13, 2019

Solving the communications medium issues is just one part of the equation. In order to successfully control and manage DR & DER the “rules of the road” need to be established, similar to the wholesale market rules that have been created. Essentially this means the money end of things needs clarity as well as the age-old issue of state versus federal jurisdiction. Then operational control needs to be established.  An entity that has the tools in place (an energy management system) similar what is currently used at the wholesale level must be given operational control over the resources. Last, necessary standards for all of this must be developed, implemented and audited for compliance like those standards currently developed by NERC and endorsed by FERC. Much of this is covered in the various industry proposals to create a Distribution System Operator (DSO).  This will be a long uphill climb.  

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