About 1,800 sites in Alaska are suitable for the development of closed-loop pumped storage hydropower projects, and many more are suitable for open-loop pumped storage, according to a study by Argonne National Laboratory and the National Renewable Energy Laboratory.

Alaska is warming faster than any other U.S. state, per the U.S. Department of Agriculture. The result is coastal erosion, increased storm effects, sea ice retreat and permafrost melt, among other impacts.

The state’s massive size and diverse landscape have created unique energy needs and challenges. Alaska is not connected to a large interstate energy grid. It consists of two larger transmission systems and more than 150 small, isolated systems serving remote communities.

Alaska is primarily powered by fossil fuel-based power that emits the carbon dioxide that drives climate change, according to Argonne. The state gets roughly 30% of its power from renewable energy, including wind, solar and water. To integrate those zero-carbon energy sources into the electric grid on a larger scale, scientists are seeking cost-effective ways to store energy to provide constant power when solar and wind are scarce. In Alaska, the sun might shine 24 hours on some summer days and barely at all in the winter.

Scientists at Argonne led a study to determine the potential of pumped storage hydropower as an efficient way to store large amounts of energy and improve grid resiliency throughout Alaska. Argonne partnered with NREL for the project funded by the U.S. Department of Energy’s Water Power Technologies Office.

Scientists collaborated on mapping and geospatial analysis to identify Alaska locations feasible for pumped storage hydropower. The result: About 1,800 sites are suitable for the development of closed-loop pumped storage and many more are suitable for open loop pumped storage.

Argonne researchers evaluated pumped storage hydropower potential in Alaska’s integrated Railbelt system. The transmission grid comprises five regulated public utilities that extend from the cities of Fairbanks to Anchorage and the Kenai Peninsula. About 80% of the Railbelt’s electricity comes from natural gas.

Argonne scientists created detailed models using A-LEAF (Argonne Low-Carbon Electricity Analysis Framework), an integrated national-scale simulation framework for power system operations and planning. Argonne scientists studied past and present energy transmission trends. They analyzed overall growth in electricity demand expected in the next 25 years. A-LEAF also considered retiring existing generators as they reach their economic lifetime.

“One of the key findings of the A-LEAF modeling is that the Railbelt system will need both short- and long-duration energy storage in the future. That storage will balance the operational variability of wind and solar generation and provide reliability and backup capacity for longer periods,” said Vladimir Koritarov, director of the Center for Energy, Environmental and Economic Systems Analysis (CEEESA) in Argonne’s Energy Systems and Infrastructure Analysis division.

Pumped storage hydropower provides roughly 10 or more hours of energy storage. The study showed that lithium-ion batteries were feasible for short-term (four-hour) energy storage in the Railbelt system.

NREL scientists evaluated Alaska’s remote areas that are powered by small isolated electrical grids, or ​microgrids. Using the HOMER (Hybrid Optimization Model for Electric Renewables) model, researchers analyzed the viability of small-pumped storage projects in rural communities with at least 250 or more residents. The team identified 18 remote communities with potential for smaller pumped storage projects. Scientists determined that in most cases, pumped storage hydropower may not be economically feasible for remote areas due to the high investment cost of small-size projects. Lithium-ion battery storage may be more economically beneficial in rural areas seeking to lower electricity costs but will not provide longer duration storage economically.

“In addition to identifying remote communities with optimal pumped storage hydropower resources and characteristics, the study included a sensitivity analysis of pumped storage hydropower capital costs and the price of diesel fuel,” said Rebecca Meadows, an NREL senior engineer. “The goal was to determine at what point distributed scale-pumped storage hydropower projects could become economically viable. For larger remote communities with higher diesel costs, … pumped storage hydropower could be a cost-effective option depending on site-specific considerations such as renewable resources and constructability.”

Along with validating the use of pumped storage hydropower as a viable technology for reducing carbon emissions, the Argonne-NREL study offers guidance on developing clean energy policies and regulations and making investment decisions. Such projects can also pump dollars into the Alaskan economy.

The Argonne-NREL research was conducted under DOE’s HydroWIRES (Water Innovation for a Resilient Electricity System) initiative to understand, enable and improve hydropower and pumped storage hydropower’s contributions to reliability, resilience and integration in the rapidly evolving U.S. electricity system.

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