California recently made headlines after becoming the first state to require solar panels on all new homes. While the move seems at first glance as a major step in the right direction, it also poses a lot of questions regarding the feasibility of the move and its effect on existing distribution networks.
In order to meet the 2030 deadline by which they must receive 50 per cent of their energy from renewable sources, the state will need to track, measure, and value energy production and consumption from decentralized sources, such as solar and wind power, batteries, hydro-powered systems, and more. An inability to properly track and manage these sources could result in unreliable power delivery, outages, and overcharges.
Electrical engineers in the Marlan and Rosemary Bourns College of Engineering at the University of California, Riverside, published a paper in which they offered a viable method that would make it possible to account for uncertainties so that utility companies can balance the distribution grid and find the most competitive rates.
Typically, the market will ensure equitable distribution by offering incentives in order to motivate customers to reduce power consumption during peak hours. This allows customers to shift energy consumption to a distributed source, such as solar panels. Customers are also able to sell excess energy to the grid, making it available for distribution to other consumers.
While this is a viable method for regulating and distributing electricity, researchers have noted key problems. For instance, organizations overseeing the grid do not dispatch the location of network DERs (distributed energy systems). Rather, they only see transmission lines and resources connected to them, which means that they often determine market conditions based on data that does not reflect smaller, key details.
“ISOs (independent system operators) see the electricity up to the substation that feeds it into a consumer network but are blind to what happens among the thousands or millions of customers after that point,” said UC Riverside doctoral student Ashkan Sadeghi-Mobarakeh. “The demand of each customer at each location has a different local impact on the distribution network.”
California ISO introduced a new index for managing flexible and responsive loads according to market conditions, though it does not consider that market participation of DERs located in distribution networks may push network limits. Determining times to deploy electrical loads without accounting for variable on-site renewable resources and distribution network conditions, the network could become overloaded, resulting in outages.
Sadeghi-Mobarakeh modeled cost and electrical loads in various market scenarios using an algorithm that compares the cost and stress on distribution networks to conventional models, then tested them on a standard distribution network. He discovered that his model would result in much lower costs with less risk to the network.
Two new indexes were proposed, with the aim of helping utilities look beyond market conditions and identify feeders with increased performance. Using these indexes, DERs can participate in the electricity market by following market signals, making it possible for feeders to respond to market signals without having a negative effect on the distribution network.
According to Sadeghi-Mobarakeh, the indexes “can be combined with field measurements from smart meters at substations to measure in real-time the collective impact distributed energy resources have on distribution system reliability.”
