Why Autonomous Network Management Is Key to Electricity Network of the Future
After a century of near stasis in the industry, global changes in the way electricity is generated and consumed are accelerating. The traditional method of generating electricity — burning hydrocarbon deposits such as oil, coal, and gas — is contributing to climate change. Nuclear power plants have become increasingly expensive to build and operate, even if we ignore the potential for catastrophic accidents like those in Chernobyl and Fukushima. Also, the best and most accessible places for large-scale hydropower production are already in operation, with limited availability for new sites.
Simultaneously, the levelized cost of energy (LCOE) of intermittent renewable resources, such as solar and wind power, has now become competitive with traditional fossil fuels and nuclear, without subsidies. What’s more, major vehicle manufacturers have announced the elimination of gas-powered cars within 10 years, leading to major innovation in the field of battery storage technology.
The result of this is that there is now a lot of pressure on electrical utilities to adopt ‘green’ distributed energy resources (DERs) and adapt to this changing world. On the legislative front, many countries and states have set target dates and percentage goals (up to 100%) for a carbon-free grid. There is multiple state and national mandates, climate accords, and individual cities hoping to become ‘smart,’ leading to an accelerating uptake of renewables and the early and extensive retirement of nuclear and coal facilities.
In addition, the increasing threats of fires and storms, and the need to mitigate the widespread power outages these create, are driving factors for more ‘microgrids,’ beyond their traditional domain of critical infrastructure and campuses. Microgrids are able to disaggregate and then reintegrate with the main grid as required. A centralized grid used to be by far the most economic approach, but today the collapse in renewable and battery costs is increasingly making a main grid — formed from a collection of microgrids — look like an attractive structure to governments and utilities themselves.
“Wind projects like Lake Benton II are a great example of innovation—leveraging the latest technology to produce energy at lower wind speeds than 20 years ago when the projects were originally built,” said John Di Donato, vice president of development for NextEra Energy Resources. “This approach extends the benefits of renewable energy over a longer period, including payments to landowners, additional jobs and tax revenue to the local community, as well as more clean, cost-effective energy for customers throughout the region.”
For example, in response to recent catastrophic fires and resulting blackouts, California’s regulators are proposing a new role for the Self-Generation Incentive Program (SGIP), which has been the state’s primary driver for distributed solar and other DERs. They now want to shift a majority of the SGIP’s roughly US$815 million budget through 2024 away from standard behind-the-meter battery systems and toward its “equity resilience budget” — giving battery solar backup systems to those at greatest risk of wildfires and blackouts.
Time for Autonomous Network Management
There are several issues around the uptake of these new, grid-edge connected clean energy sources for utility providers to consider. Firstly, how can we use existing distribution infrastructure to interconnect all of these DERs without incurring huge new costs to upgrade the grid?
Traditional utility planning models have taken a very conservative approach to the addition of new generation sources on distribution feeders. The cost of upgrading the grid (a “wires” upgrade) to allow a new wind or solar farm to be connected can destroy the economics of the project, making it financially unfeasible. Conventional planning models consider the worst case scenario for potential issues like power back-feed and voltage instabilities that could result in annoying things like “flicker” on customers’ power supply. These situations might typically be encountered on only a few days every few years, but nevertheless the project developer (or the utility) has to pay for the system upgrade to be sure this doesn’t happen.
By contrast, an autonomous network management (ANM) system manages the interconnection point by looking for any voltage or thermal issues (or whatever else you want it to watch) and backing down the generation just enough to mitigate the problem or by sending the energy into a local battery or hot water system instead of the grid. ANM operates within the limits of the protection equipment, so that the wind or solar farm can keep producing, but at a reduced level. As soon as conditions return to normal, the project is released (carefully) back to full capacity.
The deployment of ANM allows the project developer to connect to existing infrastructure, but at a price — you get what is called a “managed interconnect,” which means the solar or wind generation may be curtailed when the situations described are encountered. The cost of ANM interconnect is far less than the wires upgrade and can be done in a few months, instead of waiting for possibly years for the grid upgrade. This very often allows a project to proceed when it otherwise cannot.
In fact, studies at the National Renewable Energy Laboratory (NREL) have shown that as much as 200% to 300% more DERs may be connected than the utility might normally allow by using ANM. Interestingly, the deployment of ANM to manage constrained grid capacity then opens up a whole host of other potential benefits.
A second issue for utilities to consider around ANM is how is it possible to operate and maintain the stability and reliability of a new grid like this, if we do connect all intermittent and uncontrollable DERs out at the grid edge? To answer this, we need to first look at how traditional grid control systems work.
EMS and SCADA systems use a predefined, centralized model of the whole power system (what is connected to what), and then every few seconds collect whatever telemetered measurements are available — voltage and current readings, switch settings, breaker positions, and so forth — from various points out on the grid to see what is going on. They then try to create a picture of what the grid looks like at a given moment in time. By using a forecast of the pending demand (load) and running various power flow analysis tools on the grid model, they decide if anything needs to be done, such as an increase or decrease in generation, to keep everything balanced.
This works well for bulk, high-inertia, centralized power production at a high voltage (transmission or ISO) level, but not for all the newly connected DER generation (and load) out at the grid edge. There is often little visibility from the limited telemetry that exists and things happen very quickly and unexpectedly with localized wind and solar generation, much too quickly for an operator to intervene.
One way to solve this is to place some of the centralized control system intelligence out to the point of interconnection of DERs, and to have it take action quickly and autonomously when it needs to. In the new architecture, smart ANM software is deployed at the distribution substation or right at the point of interconnection of DERs.
This approach does not replace the traditional control approach, it supplements it. The ANM system works in consort with the utilities’ centralized systems to handle the intermittency, lack of visibility, and sheer number of DERs through fast and autonomous action at each location, executing preplanned (or quickly calculated) courses of action when needed to maintain system stability.
A key feature of this architectural approach is that it enables local optimization without requiring a complete and accurate model of the entire distribution network. The ANM system uses whatever it can see and act on in a limited location to both keep the system operating within required limits and optimize use of the connected assets.
The Added Value of ANM
The architectural flexibility of ANM systems allows DERs of any type, size, and location to be brought together into different optimization and control methods to provide various levels of security, safety, and revenue acquisition on the distribution grid. Once a solution is in place to solve the constraints blocking renewables from grid connections, grouping, optimization, scheduling, and dispatch of DERs become available for multiple aspects of grid optimization.
Use cases include mitigation of solar and wind intermittency through the use of local batteries to shift power to when it is most useful. This includes smoothing wind farm operations to deliver predictable and steady supply, and similarly adjusting solar output to reduce the steep gas-fired generation ramp in the evening as the sun goes down (the “duck curve” problem in California).
Then there is the ability to enable local distribution grid support combined with operational optimization (revenue stacking). In this case, merchant deployment of batteries in ISO markets can provide frequency support, with values added from the ability to provide service via override use by the local utility in emergency situations.
ANM can also be deployed to create microgrids for cyber and geo-physical resilience and to support remote communities. Another use case is for home-of-the-future or smart cities, when cities want to coordinate energy assets (for example, street lighting, heat networks, batteries, PV, BMSs, and so forth) to balance local energy and maximize revenue streams.
It should be mentioned that regulators have still not aligned utility incentives in many places away from building more assets that they can add to their rate base to increase revenues and returns, thereby keeping them in the position of being the only industry in the world that is negatively incentivized from squeezing more use out of their deployed physical assets. Regulators should change this quickly.
The implementation of an ANM system benefits both renewable project developers and utilities. The time has come for the traditional conservatism of utility operators to end and for the potential of ANM solutions to be fully embraced.