The Political and Technical Advantages of Distributed Renewable Power

13 years ago John Farrell 2 Comments
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Distributed Generation and the Grid


While the distributed generation transformation of the grid is a political and economic one, the process also involves a significant paradigm shift in the operation and physical nature of the grid, as well. In the short run these challenges are minimal, and in the long run they are surmountable.

Integration of Distributed Generation

The spread and growth of solar PV and other distributed renewable energy in the United States has led to significant modeling and engineering analyses of distributed generation and the grid. The data shows that previous conventions may have been wrong, and that the grid is capable of absorbing significant amounts of distributed solar and other technologies without significant harm.

California, the leader in PV installations, has done the most modeling and empirical work on integrating distributed generation. Utilities in California generally agree that 15% distributed generation on a local distribution circuit is the threshold for any problems. This figure is reinforced by a distributed generation technical study in Nevada that suggested no significant impacts on the distribution network when distributed generation is 15% or less of the total generation. For reference, 15% of California’s peak summer demand would be equivalent to around 7,500 MW of distributed generation, more than is currently on the state’s grid, and much more than is present on the grid system in any other U.S. state.

Some studies are more conservative. A 2001 study by the Electric Power Research Institute suggested that integrating distributed resources larger than 500 kW on distribution feeders would require “utility system changes.”

Other studies and experiences suggest that the 15% convention may be too conservative.

However, a study by the California Energy Commission showed that over two-thirds of California substations could handle distributed projects of 10 MW or smaller. Also, distribution feeders could handle new generation of 15 to 50% of capacity depending on its distribution along the line, with higher percentages possible with smart grid and energy storage improvements.

In total, the Commission study suggested that the state’s grid system could handle 75,000 MW of distributed generation (under 20 MW) at the substation level and 113,000 MW (of sub-3 MW projects) at the distribution feeder level, far more than actual peak summer demand. Even in the short term (prior to 2020), the California grid system could handle enough DG to fill half of the resource gap toward the proposed 33% renewable standard.

California Independent System Operator: No new backup needed to reach 33% renewables by 2020.

 

A recent modeling exercise by the California Independent System Operator suggests that no new “flexible” (backup) generation will be needed to support renewables for the state’s aggressive 33% by 2020 target.

Several sites in the U.S. also offer anecdotal evidence that significant quantities of distributed generation will not be problematic:

Las Vegas, NV, has over 10,000 kW of commercial solar PV on a 35 kV interconnection (50% of capacity, 100% during low load) with no reported issue.
  • Kona, HI, has a 700 kW solar array that is 35% of the capacity of its distribution feeder, with no reported issues.
  • Lanai, HI, has a 600 kW solar array that is 12% of distribution circuit capacity (25% during low load), with no reported issues.
  • Anatolia, CA, has 238 kW of residential PV (4% of capacity, 13% during low load) with no reported issues.
  • Las Vegas, NV, has over 10,000 kW of commercial solar PV on a 35 kilovolt (kV) interconnection (50% of capacity, 100% during low load) with no reported issues.
  • Atlantic City, NJ, has 1,900 kW of commercial solar PV on a 23 kV interconnection (24% of capacity, 63% during low load) with no reported issues.

The strongest evidence may be from Europe, where distributed generation on the grid has already far exceeded the most robust distributed generation markets in the U.S. In Germany, with over 15,000 MW of PV (99% of it distributed generation), there have been no significant issues even though PV can at peak times meet 20% of peak demand (and German wind power, half in projects 20 MW and smaller, can meet nearly twice that at peak). Spain has 3,400 MW of distributed PV, enough to meet 15% of peak demand during the sunniest periods, and again without significant grid issues.

In a recent article on the Renewable Energy World website, Kelly Foley of Vote Solar suggested that the issue is not adding variable distributed energy generators, but rather grid protocols that enforce a paradigm of a centralized grid based on large, inflexible power stations. She notes that hourly scheduling and a fleet of gas turbines provide the regulatory and backup power required by centralized coal and nuclear power production, and that similar strategies could minimize any grid impacts from variable distributed resources.

By separating the impacts of solar variability due to the daily movement of the sun (called DMV – diurnal movement variability) from the weather change impacts (WBV – weather based variability), grid planners can begin to address their intermittency concerns. The former is predictable and known, such that it can be addressed ex-ante, meaning that its grid impacts can be effectively eliminated in a least cost manner. The latter, WBV, however, is more likely to require ex-post solutions, such as requiring grid operators to consider solar generation on a fleet wide basis, rather than assessing performance on each individual unit. Thus, while WBV cannot be entirely avoided, it can certainly be significantly minimized.

Again by way of example, the current California Public Utilities Commission (CPUC) long-term planning proceeding does not distinguish DMV and WBV from each other. This lack of separation could potentially cause the CPUC’s integration model to overestimate the amount of new gas resources needed to firm, follow or back-up solar generation.

[emphasis added]

Utilities are also developing (with regulatory nudging) public information access to their distribution grids. The interactive maps allow prospective developers to identify areas on the distribution system where their project can connect with a minimum of interconnection costs. Southern California Edison (SCE), for example, provides a map with this notification:

Based on initial screening studies, locating your [solar] project inside one of the identified areas could potentially minimize your costs of interconnection to the SCE system.

San Diego Gas & Electric (SDG&E) was required by the public utility commission to acquire 74 MW of solar via competitive solicitations and “create an interactive mapping website where Respondents can visit to obtain circuit-level information. Respondents can zoom to areas of interest to see circuit feeder routes and available capacities of the feeders. In addition, SDG&E will provide spreadsheets indicating available capacities of substations and circuits in local communities served by SDG&E.”

View Larger Map

Challenges remain for evaluating the impact of distributed generators on the electrical grid. In a 2010 study for the California PUC, the authors note that, “there are currently no distribution planning models that can accurately simulate the interaction of PV components such as the inverters with substation equipment.”

Thus, research continues. A number of regulatory agencies and utilities are continuing to explore the impact of high quantities of distributed generation on utility grid systems:

  • The National Renewable Energy Laboratory released a study in 2010 showing the technical potential for the western U.S. electric grid to integrate 35% wind and solar power.
  • The U.S. Department of Energy is doing a study of the impacts of large solar PV quantities on the distribution system.
  • An electric utility on the Hawaiian island of Kauai is testing a high penetration scenario for solar PV. A 1.2 MW solar farm has a peak load identical to the local circuit and has so far caused no major problems.

<<– Page 1: The Political and Technical Advantages of Distributed Generation

–>> Page 3: The Grid Benefits of Distributed Generation

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John Farrell

John directs the Democratic Energy program at ILSR and he focuses on energy policy developments that best expand the benefits of local ownership and dispersed generation of renewable energy. His seminal paper, Democratizing the Electricity System, describes how to blast the roadblocks to distributed renewable energy generation, and how such small-scale renewable energy projects are the key to the biggest strides in renewable energy development.   Farrell also authored the landmark report Energy Self-Reliant States, which serves as the definitive energy atlas for the United States, detailing the state-by-state renewable electricity generation potential. Farrell regularly provides discussion and analysis of distributed renewable energy policy on his blog, Energy Self-Reliant States (energyselfreliantstates.org), and articles are regularly syndicated on Grist and Renewable Energy World.   John Farrell can also be found on Twitter @johnffarrell, or at jfarrell@ilsr.org.

John Farrell has 518 posts and counting. See all posts by John Farrell