Gains from CSP with storage hinge on market-specific designs

CSP developers must target energy storage capacities based on market needs to maximize cost advantages from longer dispatchability and higher capacity factors, industry experts told CSP Today.

Molten salt thermal energy storage technology is used on SolaReserve's 110 MW Crescent Dunes CSP project. (Image credit: SolarReserve)

Thermal energy storage (TES) systems are becoming commonplace in CSP plants as developers look to leverage cost advantages over other renewable energy sources for longer dispatch periods.

Some 15 out of the 17 utility-scale projects under construction around the world include TES, according to the CSP Today Global Tracker.

In China, 18 out of 20 projects being developed under the CSP demonstration program incorporate molten salt TES, according to the China National Solar Thermal Energy Alliance.

“The integration of TES can indeed decrease the LCOE [levelized cost of electricity] significantly when optimally sized in relation to the solar field size and design, power block capacity and dispatch strategy,” Rafael Guedez, senior researcher at Sweden’s KTH Royal Institute of Technology, told CSP Today.

The addition of one hour of storage at full capacity can increase plant capital cost by around 3 to 4%--depending on factors such as CSP technology, storage material, and operating strategy-- but the extra investments are spread over higher volume of output, Katlyn Avery, a thermal energy storage expert at Araner, a Spanish power engineering and consultancy firm, said.

“By increasing storage capacity in a CSP plant, a developer can have his investment working for longer hours and therefore provide a reduced LCOE," Avery said.

Molten salt towers

CSP towers with molten salt storage can operate under high temperatures and this makes them the most efficient thermal energy storage systems and the simplest to install and operate, according to experts.

Tower technology was used with molten salt storage on Torresol Energy’s 20 MW Gemasolar plant in Spain, SolaReserve’s 110 MW Crescent Dunes plant in U.S and similar configurations are expected in the coming years at Abengoa’s 110 MW Atacama 1 plant in Chile and ACWA Power’s 150 MW Noor III plant in Morocco. 

Tower plants using molten salts as heat transfer fluid (HTF) can operate up to 565 degrees Celsius. In contrast, parabolic trough plants, which currently use thermal oil HTF, are limited to temperatures below 385 degrees Celsius.

“The high working temperature leads to a comparatively less costly TES system with higher efficiency. This translates into [profits] very quickly,” Avery said.

According to Guedez, the integration of TES in molten salt towers is also seamless as using molten salt as both heat transfer fluid and storage medium means less equipment and simpler plant control.

Trough advancements

Parabolic Trough developers are experimenting with molten salt HTF to increase operating temperatures and further technology advancements could narrow the advantage of tower-based storage systems.

The transition to molten salt HTF in trough plants could halve the installed cost of storage in molten-salt parabolic trough plants by 2025, according to the International Renewable Energy Agency (IRENA).

Installed TES costs are expected to fall to $16/kWh-thermal by 2025, according to IRENA.

Chinese companies are now researching molten salt based parabolic trough plants and two out of seven parabolic trough plants under China’s demonstration program will use molten salt as HTF.

The storage provided by these two projects is significantly longer than the other five plants.

Parabolic trough projects in China’s demonstration program

Source: China National Solar Thermal Energy Alliance

Optimal size

In competitive tenders, project developers typically bid projects with thermal energy storage durations that can provide a competitive power purchase price while fulfilling tender requirements.

“The optimal size of the TES depends on the conditions set by the offtaker or market, such as electricity-buying schemes or incentives,” Guedez noted.

A study by KTH Royal Institute of Technology in 2014 found that smaller TES units and solar fields tend to be used when adopting a peaking operating strategy while larger TES units and solar fields are typically preferred if continuous baseload power production is desired.

The study concluded that the most profitable configuration for a 100 MW CSP plant in a location like Seville in southern Spain would be a plant providing baseload power through 12 hours of storage and a solar multiple of 2.75.

Availability-based payment schemes could also impact the optimal storage capacity if applied to renewable projects, Avery noted.

For conventional power generation, capacity payments are typically made for power production or power availability, which effectively rewards dispatchability.

“CSP plants with larger storage capacity should be granted a better payment from the grid operator due to the more reliable power availability,” Avery said.

Heba Hashem