For the minimum 12-hour threshold, the options with the lowest costs are compressed air storage (CAES), lithium-ion batteries, vanadium redox flow batteries, pumped hydropower storage (PHS), and pumped thermal...
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National Renewable Energy Laboratory researchers have studied which tech offers the lowest levelized cost of energy to provide the US Western Interconnection grid with electricity when wind and solar are not available. They assumed 85% renewables penetration and determined that geologic hydrogen storage and natural gas combined-cycle plants with carbon capture storage are the cheapest options for 120-hour discharge applications.
The US Western Interconnection is the area marked in yellow.
Image: Fjbfour, wikimedia commons, https://bit.ly/3kqG6NX
Researchers at the US Department of Energy''s National Renewable Energy Laboratory (NREL) have assessed the cost and performance of most long-duration energy storage (LDES) technologies. They have also looked at flexible power plants to help electricity systems to deal with extremely high levels of renewable energy penetration and have found that, given current and future capital cost scenarios, that geologic hydrogen storage and natural gas combined-cycle (NGCC) plants with carbon capture storage (CCS) technologies offer the lowest levelized cost of energy (LCOE) for 120-hour discharge applications and that pumped hydro, compressed air, and batteries are the cheapest solutions for 12-hour discharge.
“Since energy storage technologies will compete with low-carbon power generation technologies such as NG-CC with CCS to provide the grid with electricity during times when wind and solar are not producing electricity, we compare them all together within this paper,” researcher Chad Hunter told pv magazine. “This allows for a quick comparison of technologies that have not all been looked at in the same analysis before our paper.”
The techno-economic analysis considered the LDES and flexible power generation technologies in the US Western Interconnection, which is a wide-area synchronous grid stretching from Western Canada to Baja California in Mexico, with an 85% share of renewable energy in the area''s electricity mix.
“LDES requires large energy capacities so that a typical rate of charging or discharging can be sustained for days, weeks, or even longer,” the scientists explained. “In this study, flexible power plants and LDES system power generation equipment are sized at 100 MW, in the range of peaking and load-following plant sizes today.”
Through their analysis, the academics found that, for the maximum duration of seven days, NG-CC plants with CCS are the cheapest solution. For the minimum 12-hour threshold, the options with the lowest costs are compressed air storage (CAES), lithium-ion batteries, vanadium redox flow batteries, pumped hydropower storage (PHS), and pumped thermal energy storage (P-TES), which they said is mainly due to their moderate power-related capital costs and high round-trip efficiency.
“Batteries will likely play a large role in grid energy storage moving forward, especially if battery prices continue their strong decline as we have seen over the past decade,” Hunter explained. “Shorter-duration battery storage will be complemented by low-cost, longer-duration storage technologies, such as geologic hydrogen storage.”
For more than four days of storage, the least-cost solutions are diabatic compressed air energy storage (D-CAES), NG-CC, NG-CC with CCS, natural gas combustion turbine (NG-CT), and hydrogen storage in salt caverns with re-electrification in heavy-duty vehicle proton exchange membrane (HDV-PEM) fuel cells. They also determined that pumped hydro storage and the HDV-PEM fuel cells with salt cavern storage offer the lowest LCOE for the 12-hour and 120-hour durations, respectively.
“Although hydrogen systems with geologic storage and natural gas with CCS are the least-cost technology options to support high variable renewable energy (VRE) grids at durations beyond 36 h, several challenges are associated with them,” the NREL research team said. “First, neither technology offers the lowest cost for short-duration storage (12 hours), which will likely dominate the storage market until high VRE penetrations are reached; thus, market adoption and learning must be driven by other sectors or use cases, such as using HDV-PEM fuel cells in heavy-duty trucking or deploying CCS for industrial applications.”
The NREL group said that minimizing storage capital is economically convenient at durations longer than approximately 48 hours and that the LCOE is more sensitive to storage energy capacity costs than storage power capacity costs. The team presented its findings in “Techno-economic analysis of long-duration energy storage and flexible power generation technologies to support high-variable renewable energy grids,” which was recently published in Joule.
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The new U.S. storage strategy includes plans to shift new tech from the lab to the marketplace. It also focuses on ways to manufacture at scale and ensure supply chain stability.
Department of Energy/Quentin Kruger
The U.S. Department of Energy (DoE) has released a new energy storage strategy that aims to accelerate the transition of technologies from the lab to the marketplace. Its “Energy Storage Grand Challenge” plan focuses on ways to manufacture technologies at scale in the United States, while ensuring the security of supply chains to enable domestic manufacturing.
The government also hopes to develop and domestically manufacture energy storage technologies that can meet all U.S. market demands by 2030. In addition, the DoE has released two companion storage-related reports: the “2020 Grid Energy Storage Technology Cost and Performance Assessment,” and the “Energy Storage Market Report 2020.”
By offering six use cases that identify energy storage applications, benefits and functional requirements for 2030 and beyond, the storage strategy identifies cost and performance targets. These include:
The 117-page technology cost and performance assessment found that the dominant grid storage technology, pumped storage hydro, has a projected cost estimate of $262/kWh for a 100 MW, 10-hour installed system. The report said the most significant cost elements are the reservoir ($76/kWh) and powerhouse ($742/kW).
The cost assessment also pegged 2020 battery grid storage costs for fully installed 100 MW, 10-hour battery systems:
The report says that for lithium-ion and lead-acid technologies at this scale, the direct current storage block accounts for nearly 40% of total installed costs. Compressed air energy storage (CAES) is estimated to be the lowest-cost storage technology ($119/kWh), but depends on siting near naturally occurring caverns to reduce overall project costs.
For 2030, the assessment says that CAES is projected to remain the most cost-effective energy storage system on a total installed cost basis, as well as an annualized cost basis, for a 100 MW, 10-hour system. A steep drop in hydrogen energy storage''s price could enable these systems to be competitive with CAES in future scenarios. Lithium-ion battery energy storage systems may be more cost-competitive with pumped storage by 2030 for 10-hour duration, the report said.
The report was prepared by researchers at the the Pacific Northwest National Laboratory and a private consulting firm, Mustang Prairie Energy.
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