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One advantage of parabolic trough power plants is their potential for storing solar thermal energy to use during times when the sun is not shining as well as to dispatch energy when it’s needed most. As a result, thermal energy storage (TES) allows parabolic trough solar power plants to achieve higher annual capacity factors—from 25% without thermal storage up to 70% or more with it.

Thermal Energy Storage Systems

Two-Tank Direct

The first National Renewable Energy Laboratory (or NREL) Luz trough plant, SEGS I, included a direct two-tank solar thermal energy storage system with 3 hours of full-load storage capacity. This system used the mineral oil (Caloria) heat transfer fluid (HTF) to store energy for later use. It was operational from 1985 to 1999 and was used to dispatch solar power to meet the Southern California Edison winter evening peak demand period (weekdays between 5-10 p.m.).

Because power plants later moved to higher operating temperatures for improving power cycle efficiency, they also switched to a new higher temperature heat transfer fluid—a eutectic mixture of biphenyl-diphenyl oxide (Therminol VP-1 or Dowtherm A). Unfortunately, this fluid has a high vapor pressure. Therefore, it cannot be used in the same large unpressurized storage tank system similar to the one used for SEGS I.

Two-Tank Indirect

In recent years, a new indirect solar thermal energy storage (TES) approach has been developed. This approach takes advantage of the experience with the storage system used in the Solar Two— a molten-salt power tower demonstration project—and integrates it into a parabolic trough plant with the conventional heat transfer fluid through a series of heat exchangers.

The solar thermal energy storage system is charged by taking hot, heat transfer fluid (HTF) from the solar field and running it through the heat exchangers. Cold molten-salt is taken from the cold storage tank and run counter currently through the heat exchangers. It’s heated and stored in the hot storage tank for later use. Later, when the energy in storage is needed, the system simply operates in reverse to reheat the solar heat transfer fluid, which generates steam to run the power plant. This is referred to as an indirect system because it uses a fluid for the storage medium that’s different from what’s circulated in the solar field.

Several parabolic trough solar power plants under development in Spain plan to use this thermal energy storage concept. For future parabolic trough power plants, alternative approaches are being considered for reducing the cost of the solar thermal energy systems.

The primary disadvantage of a two-tank indirect solar thermal energy storage system is relatively expensive. The exuberant expense is due to the heat exchangers and the relatively small temperature difference between the cold and hot fluid in the storage system.

Single-Tank Thermocline

A single tank for storing both the hot and cold fluid provides one possibility for further reducing the cost of a direct two-tank storage system. This thermocline storage system features the hot fluid on top and the cold fluid on the bottom. The zone between the hot and cold fluids is called the thermocline.

A thermocline storage system has an additional advantage—most of the storage fluid can be replaced with a low-cost filler material. Sandia National Laboratories has demonstrated a 2.5-MWhr, backed-bed thermocline storage system with binary molten-salt fluid, and quartzite rock and sand for the filler material.

Depending on the cost of the storage fluid, the thermocline can result in a substantially lower cost storage system. However, the thermocline storage system must maintain the thermocline zone in the tank, so that it does not expand to occupy the entire tank.

Figure 2. Thermocline test at Sandia National Laboratories. Credit: Sandia National Laboratories

Direct Molten-Salt Heat Transfer Fluid

Using molten-salt in both the solar field and thermal energy storage system eliminates the need for expensive heat exchangers. It allows the solar field to be operated at higher temperatures than current heat transfer fluids allow. This combination also allows for a substantial reduction in the cost of the thermal energy storage (TES) system.

Unfortunately, molten-salts freeze at relatively high temperatures 120 to 220°C (250-430°F). This means that special care must be taken to ensure that the salt does not freeze in the solar field piping during the night.

The Italian research laboratory, ENEA, has proven the technical feasibility of using molten-salt in a parabolic trough solar field with a salt mixture that freezes at 220°C (430°F). And Sandia National Laboratories are developing new salt mixtures with the potential for freeze points below 100°C (212°F). At 100°C the freeze problem is expected to be much more manageable.

NREL