The current global framework, with growing oil price instability, limited oil and gas resources and the Kyoto Protocol environmental requirements, calls for continued improvements in the usage of renewable energy resources, including solar. During the last decades, interest in solar energy solutions has increased because the potential of solar energy has become apparent.
Even though solar radiation is a source of high temperature and energy at the origin, sun-earth geometrical constraints lead to a dramatic dilution of flux and to irradiance available for terrestrial of about 1 kW/m2 and consequently, to a supply of low temperature to the thermal fluid. It is therefore essential requisite for solar thermal power plants to make use of optical concentration devices that enable the thermal conversion of high solar flux and with relatively little heat loss. Typical concentration devices for solar radiation are: parabolic troughs, linear Fresnel reflectors, parabolic dishes, and power tower (or central receiver solar systems—CRS). Solar thermal power based on such concentrators is called Concentrated Solar thermal Power (CSP). The most common solar thermal power systems are parabolic trough and power tower.
A parabolic trough power plant is basically composed of three main elements: the solar system, the steam generator and the power block. The solar system comprises parabolic trough collectors' field and the oil (i.e. heat transfer fluid) circuit. At the solar field, solar radiation is collected and converted into thermal energy as the temperature of the oil circulating through the receivers, increases. Once heated at the solar field, the oil is pumped and conveyed to a steam generator, to produce high pressure/temperature steam. The steam is then used to produce power similarly to conventional steam power plants (e.g. Rankine cycle).
In power towers (or CRS), incident sunrays are reflected from large mirror collectors (heliostats), which track the apparent sun movement and concentrate the energy flux onto a solar receiver, where energy is transferred to thermal fluid. This fluid can also be direct steam. The thermal energy conversion into electricity is quite similar to fossil-fueled power plants.
Both parabolic trough and CRS are proven technology. However, their cost is not yet competitive with conventional alternatives unless subsidized. Therefore, it is yet desired to improve the existing plants cost effectiveness.
U.S. Pat. No. 5,444,972 describes a hybrid power plant driven by hydrocarbon fuels and solar energy. The solar system is CRS and the power block is condensing steam cycle (Rankine). Exhaust gas of a turbine and fuel added burner backup the solar field in generating the steam. Sensible heat storage and a receiver thermal shield are described in this publication as being optional features.
GB 2449181 discloses a combined gas/steam (or Brayton/Rankine) hybrid power plant. The heat input to the gas cycle partially depends on solar heating of air supplied to an initial combustion stage from a compressor of the gas turbine engine. Simplification and/or greater responsiveness of the gas turbine engine's fuel control system is achieved by providing the power plant with separate combustion stages being coupled to an associated turbine. Compensation for variations in insolation is achieved by controlling fuel flow to the initial combustion stage while compensation for variations in electrical load is achieved by controlling fuel flow to a subsequent combustion stage. The final turbine stage drives a generator, and the exhaust from the final turbine stage is passed through a heat recovery steam generator to raise further power in a steam turbine that also drives a generator. The second combustion stage, including a superheater, may be located in the steam cycle part of the combined cycle to further heat the steam before entry to the steam turbine. Concentrated solar energy may heat a heat transfer fluid, e.g. a molten salt, for intermediate heat transfer and heat storage.
U.S. Pat. No. 5,417,052 describes a hybrid, combined cycle power plant driven by CRS and natural gas. The combined cycle is Brayton/Rankine. The CRS heat transfer fluid (HTF) is molten salt. The molten salt preheats the air leaving the gas cycle compressor. The exhaust gases from the gas cycle drive a steam cycle for additional energy production.
US 2008127647 discloses a method for oversizing the Rankine power block with respect to the topping cycle block in combined cycles where the bottoming cycle is Rankine. The method describes the production of the additional steam in the Rankine plant by solar energy. The method is applicable in plants that are equipped with an oversized heat recovery steam generator (HRSG) and steam turbine system that is coordinated with duct burners or other means for additional steam generation.
US 20060260314 discloses an integration between a combined cycle power plant and a solar Rankine power plant. Relatively high temperature, low pressure reheat from the combined cycle power generation system can be used, through, for example, a superheater, to raise the temperature and pressure of a working fluid in a solar Rankine power generation system. The resulting integrated system has enhanced efficiencies as compared with stand-alone systems.
Most of the solar thermal power today is produced by parabolic trough technology. Typically, parabolic trough plants consist of large fields of parabolic trough collectors, a heat transfer fluid/steam generation system, a Rankine steam turbine/generator cycle, and optional thermal storage and/or fossil-fired backup system(s). The solar field is modular in nature and comprises many parallel rows of single-axis-tracking parabolic trough solar collectors, normally aligned on north-south horizontal axis. Each solar collector has a parabolic shaped reflector that focuses the sun's direct beam radiation on a linear receiver located at the parabola focal axis. The collectors track the sun from east to west during the day. A heat transfer fluid (hereinafter “HTF”) is heated up to about 400° C. while being circulated through the receiver and returns to a series of heat exchangers (hereinafter “HE”) in the power block where the solar heat absorbed by the HTF (typically synthetic oil) is extracted to generate high pressure superheated steam (e.g. 100 bar, 371° C.). The superheated steam is then fed to a conventional reheat steam turbine/generator (condensing turbine) to produce electricity. The expanded steam from the turbine is condensed in a saturated condenser and returned to the HE via feed-water pumps to be transformed back into steam. Wet cooling towers or sea water supply cold water to the condenser. After passing through the power block, the cooled HTF is re-circulated through the solar field.
The parabolic trough approach is currently the most proven and lowest cost large-scale solar power technology available today as described by H. Price et al. in “Advances in Parabolic Trough Solar Power Technology”, Journal of Solar Energy Engineering V. 124, Issue 2, pp. 109-125, May 2002. However, the cost of parabolic trough power is not yet competitive with conventional alternatives unless subsidized (typical installation cost for 50 MW plants is in the range of 4-6 $/W). One of the reasons is that the standard condensing steam power block described above has several drawbacks that highly limit the overall plant cost effectiveness and deployment. Some of these drawbacks are the following:
1) Water Cooled Condenser:
The condensers in steam power units are typically water cooled type where the water are typically cooled by a wet cooling tower (WCT). Air cooled condensers (dry cooling towers—DCT) are inferior because they increase the steam condensation temperature, and the steam condensing cycle efficiency is very sensitive to that temperature. In addition, DCT are more expensive than WCT. Consequently, solar thermal power plants are installed mostly in locations where water is available, rather than in desert and arid areas where solar radiation levels are typically the highest.
2) Condensing Turbine:
Condensing steam turbines for solar plants, typically designed to generate 50-80 MW, have a very unique design which creates low market availability (up to two years of manufacturing lead time). This might introduce a significant bottleneck to projects time tables because the other components lead times are substantially lower (typically less than one year). Another downside of the condensing turbine is the performance penalty when scaling down. For instance, the difference between 60 MW and 5 MW turbine shaft (isentropic) efficiencies is about 6%. The performance penalty increase both the specific required collection area (m2/W) and the electricity specific cost ($/W). This is critical because the small and medium size plants (5-20 MW) market is currently growing rapidly.
3) Operation Time (Capacity Factor):
During day time, the solar radiation intensity varies. In a clear sky day, the radiation level increases gradually during the morning and reaches maximal level around noon while from afternoon to sunset, the insolation declines. In a standard (condensing turbine) power block, steam is fed into the turbine only when reaching a certain desired temperature, typically around 370° C. and an initial flow rate. Operating the turbine with substantially lower steam temperatures is eluded because that would expose the turbine blades to high levels of moisture which is destructive. Therefore, the standard routine in such a solar plant would be to wait until the heat transfer fluid heats up to about 390° C. so the desired steam top temperature can be achieved. However, this oil temperature can be obtained only when reaching a minimum insolation level, say 400 W/m2. Thus, during early mornings and late afternoons' periods the solar plant cannot produce power. The result is shorter plant operation time (or lower capacity factor) and of course, higher electricity cost.
4) Working Fluid:
Steam condensation increases the power block complexity and cost due to the following two reasons:
a) The saturated steam specific volume is very high (for example, 12 m3/kg at 50° C.), requiring large size condensing unit.
b) The saturated pressure of steam at typical condensing temperatures is much below atmospheric (for instance, at 35° C. the pressure is 0.056 bar). Consequently, the condenser must always be maintained under deep vacuum and free of oxygen. Addressing these constrains, increases the plant O&M costs.
Other power cycles are also described in the literature.
For example, A. I. Kalina in “Combined-cycle system with novel bottoming cycle”, Journal of Engineering for Gas Turbines and Power v. 106, pp. 737-741 (1984) describe a thermodynamic cycle that is designed to replace the Rankine cycle as a bottoming cycle for a combined-cycle energy system as well as for generating electricity by using low-temperature heat sources.
P. A. Lobos and E. D. Rogdakis described in their publication “A Kalina power cycle driven by renewable energy sources”, Energy, Jan. 31, 2009, a Kalina cycle using low-temperature heat sources to produce power. The main heat source of the cycle is provided by flat solar collectors. In addition, an external heat source is connected to the cycle, providing 5% up to 10% of the total thermal energy used in the cycle. The cycle operates at low pressure levels (0.2-4.5 bar) and low maximum temperature (130° C.). For given conditions, an optimum range of vapor mass fractions and operating pressures can be identified that result in optimum cycle performance. Simple equations have been derived that link the operational parameters with the independent variables as well as with the cycle efficiency.
The present invention seeks to provide a solution that eliminates the major part of the above problems while increasing the solar plant efficiency.