Scientists from Argonne National Laboratory and the National Renewable Energy Laboratory have revealed their findings from a study called The Prospects for Pumped Storage Hydropower in Alaska, which identified 1,800 potential sites suitable for development of closed loop systems with a total energy storage capacity of about 4TWh.
Alaska has a unique electric power system that consists of two larger transmission systems (the Railbelt and Southeast Alaska) and more than 150 small, isolated ones serving remote communities. The Railbelt and Southeast Alaska systems are not connected to one another through transmission links and due to the large distances between cities in Alaska, most of the remote systems are expected to remain isolated for the foreseeable future, essentially continuing to operate as isolated microgrids.
As this report by Koritarov et al states, compared with the lower 48 US states, the cost of electricity in Alaska is high due to transportation costs for diesel fuel which is mostly used for electricity generation in remote communities, where the cost of electricity for some can be up to four times the cost in those served by the Railbelt system.
This is why many remote Alaskan communities want to see increased electricity generation from local renewable resources, such as wind, solar, and hydropower, where available. To support such developments energy storage will be needed to smooth variability and provide backup capacity and energy when wind or solar generation is scarce. Although the report acknowledges that different energy storage technologies are currently available, the scope of this study was limited to examination of whether pumped storage hydropower would be a viable energy storage option for Alaska.
Historically, most pumped storage projects have been built with larger capacities of several hundred megawatts for economies of scale but in recent years, utilities have been investigating smaller designs as such projects can be integrated into hybrid projects that include smaller wind and solar installations. These smaller schemes are typically envisioned with a modular design that employs standardised and prefabricated components to reduce the overall costs, Koritarov et al explain.
“While the specific capital costs of larger PSH projects are very competitive,” the authors go on to add, “the costs of smaller designs can be quite high. However, every PSH project is unique, and the capital costs are very site-specific.”
Study results
The results show that pumped storage capacity is part of the optimal capacity expansion solution in all analysed scenarios, with modelling selecting between 300MW and 600MW of new capacity in the different scenarios. One of the key findings of the Argonne Low-Carbon Electricity Analysis Framework that was used, is that the Railbelt system will need both short- and long-duration energy storage in the future. In addition to new pumped storage capacity, which was assumed to provide ten-hour energy storage, the optimal expansion solutions for all analysed scenarios also included new battery capacity, assumed to provide short-term (four-hour) energy storage. A mix of short- and long-duration energy storage can balance the operational variability of wind and solar generation and provide reliability and backup capacity for longer periods when little wind and solar generation is available or during outages of conventional generating units and/or transmission lines.
The study’s resource mapping identified a total of 192 remote communities with potential sites suitable for smaller projects, and after using screening criteria to identify the most promising sites and representative communities for analysis, this was narrowed down to 18. Nearly 50% of the identified potentially suitable small-scale PSH sites are in Southeast Alaska.
Several potential designs for pumped storage projects were examined that could be suitable for remote communities, but the team selected a small closed-loop design (<1 MW) that uses pump-as-turbine and either reservoirs or steel tanks for both the upper and lower reservoirs.
Using this PSH design, the Hybrid Optimisation Model for Electric Renewables (HOMER) analysis was conducted for three scenarios:
- Scenario 1 – large PSH reservoirs that could provide ten-day energy storage to the community.
- Scenario 2 – the same PSH project but with smaller storage tanks, providing ten hours of energy storage.
- Scenario 3 – remote community relies on four-hour energy storage provided by lithium-ion batteries instead of pumped storage plants.
Each scenario was also analysed for two charging options: only wind and solar energy are used for charging (eg to pump water into the upper PSH reservoir), or both diesel generation and renewable generation are used for charging. Finally, the team completed a site-specific case study for a community in Alaska to investigate the cost viability of including PSH with a proposed run-of-river hydropower plant.
According to the study, the results of the HOMER analysis indicate that, based on their high investment cost, small PSH projects are “unlikely to be economically viable for applications in small remote communities”. The team performed sensitivity analyses of PSH capital costs and the price of diesel fuel to determine at what point PSH projects may become economically viable. The analysis showed that, for Alaska applications, PSH projects with ten-hour energy storage are likely to be more economical than those with larger reservoirs providing ten days of energy storage for the remote communities.
For the project providing ten hours of storage, diesel fuel costs would need to be above ~$6 per gallon for a PSH project to offer a cost-competitive storage solution. Adding PSH allows for high renewable energy penetration and can reduce diesel fuel usage by more than ~80%, depending on the microgrid configuration.
Giving details about the charging options, the authors explain that if only wind and solar generation are used for pumping, their available pumping energy would be insufficient to fill the large, ten-day PSH reservoir. However, if diesel generation is also used for pumping, the reservoir can be filled most months of the year, with slightly lower renewable energy penetrations but similar costs. For Scenario 2, assuming a smaller, ten-hour PSH reservoir, both charging options would be able to fill the reservoir most months of the year.
The results for Scenario 3 show that lithium-ion batteries provide an economically viable storage solution for small remote communities; the range of cost effectiveness increases when compared with Scenarios 1 and 2. However, compared with PSH storage options in Scenarios 1 and 2, the diesel reduction potential significantly decreases.
Finally, the site-specific case study—which analysed the addition of a ~200-kW modular PSH plant providing 12 hours of storage to a planned run-of-river plant in False Pass, Alaska—indicated that, although the addition of PSH would significantly reduce the size of the run-of-river plant required to provide a similar diesel fuel reduction (compared with the run-of-river plant alone), the cost of energy would more than double. The addition of solar and lithium-ion batteries also reduces the size of the run-of-river project, provides the lowest-cost option with the highest reduction in diesel fuel, but only supplies two hours of storage duration.
This article first appeared in International Water Power magazine.
