Describing the Hybrid CPV System

This approach first proposed by Solar Systems in Australia employs a dish concentrator that reflects sunlight onto a focal point (see Fig. 6). At the focal point is a spectral splitter (heat mirror) that reflects infrared solar radiation and transmits the visible sunlight to high-efficiency solar cells behind the spectral splitter. Figure 7 schematically shows the transmission across the solar spectrum wavelengths.

The reflected infrared radiation is gathered by a fiber-optics "light pipe" and conducted to the high-temperature solid-oxide electrolysis cell. The electrical output of the solar cells also powers the electrolysis cells. About 120 megajoules are needed—whether in electrical or thermal form, or both—to electrolyze water and generate 1 kg of hydrogen. The result is that more of the solar energy is used for

Transmission

Reflection

r

-

Wavelength (microns)

Fig. 7. Transmittance (and reflectance) of a spectral splitter mirror as a function of solar wavelength in microns. This response depicts that of a "hot mirror" in which light is transmitted in the visible region and reflected in the infrared.

hydrogen production. And we shall see that the additional costs for the hybrid solar concentrator components—the spectral splitter and fiber-optics light pipe—are relatively small compared with the boost in hydrogen production.

The testing of components shown in Fig. 6 occurred in the mid-1990s and has been described previously13,14,17 on a scale considerably smaller than that of Fig. 2. The solar concentrator was a paraboloidal dish 1.5 m in diameter, with two-axis tracking, and is capable of more than 1000-suns concentration (Fig. 8). The full dish was not needed and most of it was shaded appropriately for use with the small electrolysis cell. At that time, the solar cell was a GaAs cell with an output voltage of 1 to 1.1 V at maximum power point, with a measured efficiency of about 19%. The voltage was an excellent match for direct connection to the electrolysis cell when operating at 1000 oC. The tubular solid-oxide electrolysis cell was fabricated from yttria-stabilized zirconia; the cell had platinum electrodes because the test temperature was higher than that of typical solid oxide cells. Figure 9 shows a schematic of the solid-oxide electrolysis cell operation.

A metal tube surrounded the cell to uniformly distribute the solar flux over the cell's surface. The test occurred during a 2-hour period of operation, with an excess of steam applied to the electrolysis cell. The output stream of unreacted steam and generated hydrogen was bubbled through water and the hydrogen was collected

Fig. 8. This photo, taken in the 1990s, shows John Lasich demonstrating how cool his concept is for conducting infrared energy through a fiber-optics light pipe. The dish reflects sunlight to a "heat mirror" that reflects long-wavelength solar radiation to the fiber-optic bundle along the axis of the parabolic dish. The visible light seen at the end of the light pipe in Lasich's hand is a result of partial reflection of visible light by the heat mirror.

Fig. 8. This photo, taken in the 1990s, shows John Lasich demonstrating how cool his concept is for conducting infrared energy through a fiber-optics light pipe. The dish reflects sunlight to a "heat mirror" that reflects long-wavelength solar radiation to the fiber-optic bundle along the axis of the parabolic dish. The visible light seen at the end of the light pipe in Lasich's hand is a result of partial reflection of visible light by the heat mirror.

and measured. During a definitive 17 minutes of system operation in steady state, 80 mL of hydrogen were collected. The ratio of the thermoneutral voltage of 1.47 V to the measured electrolysis cell voltage of 1.03 V was 1.43, corresponding to a boost of more than 40% in hydrogen production due to the input of thermal energy. This was also confirmed by energy balance. Combining the optical efficiencies of the concentrator dish (85%), solar cell efficiency, and thermal-energy boost, the total steam hydrogen

electricity

2e"

H20 + 2e- —> H2 + 02-

porous cathode

i

r

electrolyte (Zr02 doped with Y203)

Fig. 9. Schematic of high-temperature electrolysis in a solid-oxide cell. The geometry can be planar or tubular as in the case of the first demonstration of the hybrid solar concentrator PV system. Operating the electrolysis cell in reverse corresponds to electricity and heat production in solid-oxide fuel cell operation.

system efficiency was 22% for conversion of solar energy to hydrogen. At the time of these measurements in the mid-1990s, the efficiency was almost three times better than that recorded for any other technology converting solar energy to hydrogen.

These early tests were not conducted with the most efficient solar cells available at that time. The record efficiency then was about 30% for a laboratory cell (see Fig. 4) and those cells were not easily obtainable. Today's record efficiency is 40.7%, and 35%-efficient cells are commercially available.18 Therefore, 40% solar-to-hydrogen efficiency is expected in the near term assuming a heat boost of 40%, a multijunction solar cell efficiency of 35%, and an optical efficiency of 85%. A 40% multijunction solar cell would yield a solar-to-hydrogen conversion efficiency of almost 50%. Nevertheless, electrochemical theoretical results calculated by Licht, shown in Figure 10, are consistent with these predictions based on Solar Systems' early experiments.15

Two cost analyses have been reported for this concept.17,19 Although the resulting hydrogen costs agreed within their costing uncertainties, the hydrogen generation plants were quite different in nature, as were the financial assumptions in their cost analyses. The first analysis was conducted in 2004 and reported in 2005, and it used a set of financial and plant assumptions developed by the DOE Hydrogen Pro-gram.19,20 Because of the complexity of the DOE H2A plant assumptions, a back of the envelope calculation with simplified financial assumptions was made to highlight key cost elements.17 This analysis is presented below and compared with the H2A analysis. The principal difference between the two analyses is the additional costs of operation, transportation, storage and distribution in the H2A analysis.

The largest cost for the hybrid solar concentrator system will be for the dish concentrator and PV receiver, shown in Fig. 6. Algora recently completed an extensive cost analysis based on previously collected data for CPV systems.7 Many of the

Fig. 10. Energy conversion efficiency of solar-driven water splitting to generate H2 as a function of temperature and photovoltaic conversion efficiency at AM1.5 insolation, at pH2O = 1 bar. Reprinted with permission from J. Phys. Chem. B 2003, 107, 4253-4260. Copyright 2003

American Chemical Society."

Fig. 10. Energy conversion efficiency of solar-driven water splitting to generate H2 as a function of temperature and photovoltaic conversion efficiency at AM1.5 insolation, at pH2O = 1 bar. Reprinted with permission from J. Phys. Chem. B 2003, 107, 4253-4260. Copyright 2003

American Chemical Society."

project costs came from installed costs for the 480-kW reflective CPV system in Tenerife, Spain. The analysis included a wide range of parameters, including cumulative production of 10 MW for present-day systems to cumulative production of 1000 MW for the mid-term systems where learning cost reductions are incorporated. Concentrations ranged from 400 to 1000 suns, with solar cell efficiencies ranging from 32% to 40%. Module efficiencies ranged from 24.8% to 32.2%, and the plant's AC annual efficiency ranged conservatively from 18.2% to 23.6%. Present-day base costs were 2.34 euro/W (almost $3/W with today's exchange rate). The lowest projected system costs ranged from 0.5 to 1 euro/W for efficiencies of 40%, 1000-suns concentration, and cumulative production of 1000 MW.

We wanted to compare the results of our simplified engineering cost analysis of hydrogen generated by this hybrid solar concentrator system with those of more extensive cost analyses:

1. the electrolytic generation of hydrogen by wind systems, where cumulative production of this highly developed technology is approximately 50 giga-watts (GW); and,

Table 2. Component and system costs for 10-MW hybrid CPV project for solid-oxide electrolytic production of hydrogen.

Component costs assuming 1000-MW technology ($/kW)

Concentrator PV

800

Spectral splitter

15

Fiber optics

25

Electrolysis cell

400

Total System Cost

1240

2. the conventional production of hydrogen by reforming natural gas. So, for our analysis, we used cost estimates for mature CPV technology.

Cost studies for conceptual high-temperature nuclear reactors (projected for mature 600-MW designs) suitable for high-temperature electrolysis cells face similar problems because both the hybrid solar concentrator and high-temperature nuclear reactor are in early stages of exploratory research and development for hydrogen generation. Further, high-temperature solid-oxide electrolysis cells will be required in large sizes (500 kW to 500 MW) for integration with nuclear reactors.21 Unit sizes ranging from 20 to 50 kW could be used with hybrid solar concentrators. Although solid-oxide fuel cells are commercially available, solid-oxide electrolysis cells are beginning development. It is important to note that solid-oxide electrolysis cells have been demonstrated to date in small sizes equivalent to hundreds of watts. The modular character and size of the hybrid CPV system is commensurate with the development of solid-oxide electrolysis cell technology, also in early stages of development.

Using a set of assumptions for a well-developed technology, we acquired costs in $/kW for solid-oxide electrolysis cells from a developer of solid-oxide electrolysis cells.22 Table 2 summarizes the cost data for a well-developed technology (1000-MW cumulative production) for the hybrid CPV system and high-temperature solid-oxide electrolysis cell. Table 3 summarizes the hydrogen production costs for a 10-MW project built with the well-developed technology assuming a 20% rate of return per year not including operating, storage, transmission or distribution costs.19 It also contain the estimated costs from the H2A analysis that includes the additional operating, storage, transmission and distribution costs expected for a distant, centralized hydrogen generation plant.17

Table 4 compares these production costs with those of other hydrogen production technologies.

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