Solar Towers
Abstract
A solar tower power plant comprises a tall tower supporting a heat receiver surrounded by a field of heliostats that focus the rays of the Sun onto the receiver. The heliostats are each fitted with a solar tracking system so that they can track the Sun across the sky. Sometimes called point focusing solar concentrators, these plants can achieve concentration ratios of up to 1000. Solar towers often integrate thermal storage using molten salts, usually nitrates, as the heat transfer fluid, which enables them to generate electricity around the clock. Others use direct steam systems. More complex pressurized gas systems have also been proposed that use a gas turbine in a hybrid generating system.
Keywords
Solar tower; heliostat; central receiver; tracking solar concentrator; molten salt; energy storage; volumetric receiver
A solar tower power plant is characterized by the way in which solar energy is collected and concentrated. This type of plant has at its center a tall tower carrying a thermal receiver. The tower is surrounded by a field of square or rectangular mirrors, usually called heliostats. The heliostats are mounted on special structures so that each can individually track the Sun across the sky and direct the sunlight onto the receiver at the top of the tower. Because all the solar energy is concentrated at one point instead of along a line as in a parabolic trough system, the level of concentration is higher in the former than in the latter. Solar towers are sometimes referred to as point focusing solar thermal plants.
The solar tower concept was first tested in Spain in 1981 at a 500 kW test facility that used liquid sodium as the heat transfer fluid to carry energy from the solar receiver to a heat exchanger to raise steam for a steam turbine. Soon afterwards, in 1982, a plant called Solar One was built in California with a water/steam heat transfer medium. The pilot plant, which was supported by the U.S. Department of Energy, had 1818 mirrors, each 40 m2, and was able to generate 10 MW. The plant operated until 1986, but the technology was not developed commercially. Then, in 1996, Solar One was updated to a molten salt heat transfer system, and a ring of 108 mirrors of 50 m2 was added. The new pilot plant, now called Solar Two, also had a generating capacity of 10 MW. Other pilot schemes were built in France, Italy, Japan, and Russia; the largest of these had a generating capacity of 5 MW.
These projects proved the technical feasibility of a large solar tower plant, but it was not until 2007 that the first commercial solar tower plant, called PS10, was built in Spain. The facility has a generating capacity of 10 MW. Since then there have been a small number of other commercial plants, including one in California comprising three central towers with a total gross generating capacity of 392 MW. A new plant based on the technology used in Solar One and Solar Two has also been constructed. This plant has the ability to store thermal energy; energy storage is relatively simple to integrate into some solar tower plants.
Solar Tower Technology
The principle of the solar tower is the same as that of the solar trough: focus sunlight onto a solar receiver where a heat transfer fluid can be heated, and the heat carried away to generate electricity. With the solar tower the linear receiver is replaced with a single-point receiver mounted at the top of the central tower.1 This receiver must be able to capture all the heat energy from a large number of heliostats mounted at ground level around it. Fig. 5.1 shows the layout of a typical plant of this type.
The type of receiver used in commercial solar tower power plants is called an external tube receiver. The solar heat directly hits the outside of tubes that carry the heat transfer fluid, and the heat is conducted through the tube material to the fluid inside. The efficiency of the receiver is crucial to the overall energy capture efficiency, so this represents a key area of research. New designs including a type called a volumetric receiver are being tested, and may offer better performance (see discussion of air-driven systems later in this chapter).
The heat transfer fluid that passes through the receiver varies depending upon plant design. Sodium, as used in the early Spanish pilot scheme noted earlier, has not been used in any commercial plants. However, some plants use molten salt as the heat transfer fluid, and this permits an element of storage to be included. Others use a direct steam system. The main advantage of the solar tower over the line focusing type of solar thermal plant is that point focusing allows a much higher temperature to be achieved in the receiver; this enables the thermodynamic heat engine attached to the system to operate at higher efficiency.
The collection system for a solar tower is the field of individual heliostats, each angled to direct sunlight onto the central receiver. Heliostats vary in size from 10 m2 to 120 m2. The 10 MW PS10 solar tower in Spain has a field of 624 heliostats, or roughly 60 for each megawatt of generating capacity, and the collector field covers an area of 60 ha, or 5.5 ha/MW. Each heliostat is 120 m2. This large size can make them difficult to align in high winds. Meanwhile, the Ivanpah solar tower project in California has 347,000 mirrors, each 7 m2—with two mirrors to each heliostat—for its three solar towers, and a net generating capacity of 377 MW, or 460 heliostats/MW. The collection field for the three towers that make up this power plant cover an area of around 1420 ha, or 3.75 ha/MW. The facility also has the ability to supplement its solar input by burning natural gas in order to maintain its power output.
The collector array for a solar tower bears some resemblance to the Fresnel reflector. The ideal shape for the field would be a giant parabola with the receiver at the focus. Such a large parabolic reflector would be impossible to construct, so the solar tower breaks this down into a massive array of small mirrors mounted at ground level. In addition, although in theory each mirror should have a parabolic curvature, in practice this is usually approximated with flat mirrors. The terrain upon which the power plant is built does not have to be flat because elevation changes over the collector field have little effect on efficiency, an advantage compared to solar trough power plants. However, there are economic limits to plant size because once the collector field becomes too large, additional mirrors at the periphery contribute relatively less energy. The practical limit is likely to be between 200 MW and 400 MW for an individual tower.
A solar tower point focusing heat collection system can potentially achieve a concentration ratio of 600–1000, ten times that of a line concentrating system. This high level of concentration would allow the system to potentially provide a temperature of 1000°C and above, which would in principle allow the heat engine used in a solar tower power plant to operate with 20% more efficiency than in a solar trough plant. In practice, however, commercial plants have not yet achieved such high temperatures.
Power Generation
The high thermodynamic cycle temperature that can potentially be achieved with a solar tower power plant means that a greater variety of different configurations are possible for extracting power. As already noted, a number of different heat transfer fluids have been tested, including liquid sodium—a material that has also been used in nuclear fast reactors—molten salts, and a direct water steam system. Experimental systems have also included the use of air or a gas as the heat transfer fluid; hybrid cycles involving a gas turbine are also being explored.
The role of the heat transfer fluid is to capture heat from sunlight within the receiver, and then carry this heat away so that it can be used to drive a thermodynamic heat engine. This can be achieved in one of two ways. The most efficient is for the heat transfer fluid to be the same fluid that is used in the heat engine. The alternative is to pass the heat transfer fluid through a heat exchanger where it heats the thermodynamic fluid that drives the heat engine.
Using the heat transfer fluid directly in the heat engine is the simplest system, and in principle the most efficient because it does not involve a heat exchanger. This is the basis for a direct water/steam system in which the heat in the solar receiver is used to generate steam directly; this steam is then used to drive a steam turbine. This type of system has been used in the Ivanpah solar tower project in California, where a steam temperature of 545°C is achieved at a pressure of 170 bar to drive the towers’ three 125 MW steam turbines. Overall plant efficiency is around 18%. A direct steam system is also used in two Spanish plants, PS10 and PS20. These operate at relatively mild steam conditions of 250°C and 40 bar. The two Spanish plants also incorporate an element of energy storage in the form of steam storage tanks, but the amount of storage is very limited and the plants can effectively only operate during daylight hours. Overall plant efficiency is 15.5%.
With direct heat transfer systems using a water/steam cycle it is possible to add supplementary heating as a means of increasing the power output of the system when solar input is reduced. Supplementary heating is used at the Ivanpah plant to heat the steam system in the morning so that it can start operating more quickly when the Sun rises.
The other system that has been employed in commercial solar tower plants involves the use of a molten salt as the heat transfer fluid. The molten salt is usually a mixture of nitrates that form a liquid at the temperatures achieved in the solar tower plant. Typically the mixture includes 60% sodium nitrate and 40% potassium nitrate. This system was tested in the Solar Two project in California and has more recently been used in two commercial plants, one called Gemasolar in Spain and the second called the Crescent Dunes solar tower in the U.S. state of Nevada.
In this type of system the heat in the solar receiver is used to heat the molten salt to around 550°C. This hot salt is then pumped to a hot storage tank where it can be stored. In another circuit, hot molten salt is pumped through a heat exchanger where it heats water to steam. The spent salt is then pumped into a cold storage tank. The temperature here is around 300°C so that the salt always remains in the liquid state (it solidifies at around 220°C). The steam generated in the heat exchanger is used to drive a steam turbine.
Depending on the size of the solar field, the size of the molten salt storage system, and the size of the steam generator, this type of plant is capable of storing a significant amount of heat energy. The Gemasolar plant has a tower 140 m high surrounded by 2650 heliostats, each 120 m2. Its molten salt system is sized so that it can generate power for 15 hours without any solar input, and this allows it to operate 24 hours a day. Overall plant efficiency is 14%. The Crescent Dunes project is also capable of operating for 24 hours each day.
Air-Driven Systems
There is an alternative approach to power generation in a solar tower that uses air as the heat transfer fluid. This has the potential to be more efficient than the liquid systems described earlier, but the cycle is more complex.
The heart of this type of thermodynamic cycle is a device called a volumetric air receiver. This type of receiver is constructed of a porous material that can be a wire mesh structure or porous ceramic elements. These can absorb heat throughout the volume of the device and transfer it to a fluid passing through the receiver. The receiver provides a much larger surface area for heat transfer than an external tube receiver, and can potentially offer greater efficiency. In an air system, air is pumped through the volumetric receiver where it is heated by the hot receiver elements. The hot air is then pumped away and used to raise steam in a heat recovery boiler, steam that will drive a steam turbine. In principle it should be possible to achieve air temperatures of up to 1000°C in this type of receiver, offering higher thermal-to-electrical conversion efficiency than with current commercial systems.
A more advanced air cycle is possible if the whole air system is pressurized. The pressurized air is heated in the volumetric receiver as before, perhaps reaching 1100°C in an ideal design. The hot, high pressure air can then be used to drive a small gas turbine. Upon exiting the turbine, the hot air is once again used to raise steam in a heat recovery boiler, and the steam is used to drive a steam turbine. The result is a type of combined cycle solar power plant. It is possible to add both heat energy storage and supplementary heating to such advanced pressurized systems. Volumetric receivers and the various associated power generation configurations are being tested at the pilot stage, but are not yet available commercially.