Comprehensive Energy Systems, vol.4b - Energy Conversion [4b, 1 ed.] 978-0-12-814925-6

Citation preview

4.15 Solar Cells Mehmet Kazici, Sinem Bozar, Anil Gürs¸en, Fatih Ongül, and Adem Karsli, Yildiz Technical University, Esenler, Istanbul, Turkey Niyazi S Sariciftci, Johannes Kepler University Linz, Linz, Austria Serap Günes, Yildiz Technical University, Esenler, Istanbul, Turkey r 2018 Elsevier Inc. All rights reserved.

4.15.1 Introduction 4.15.2 Background/Fundamentals 4.15.3 Systems and/or Applications 4.15.3.1 Open Circuit Voltage 4.15.3.2 Short Circuit Current 4.15.3.3 Fill Factor 4.15.3.4 Morphology 4.15.3.5 Charge Transport and Mobility 4.15.4 Illustrative Example (Fabrication and Characterization of an Inverted Type Solar Cell) 4.15.5 Future Directions 4.15.6 Closing Remarks References Further Reading Relevant Websites

Nomenclature Isc (mA) Jsc (mA/cm2)

Short circuit current Current density

Abbreviations AM

4.15.1

Air mass

637 638 639 643 644 644 645 645 650 653 654 655 657 658

η Power conversion efficiency Voc (V) Open circuit voltage

FF IPCE

Fill factor Incident photon to current efficiency

Introduction

Sun is a powerful source of energy. According to the solar energy authorities, the solar energy striking the earth’s surface in 1 h delivers enough energy to power the world economy for entire year. Solar cells which convert sunlight into electricity can be used to evaluate such an enormous energy. Solar cells have already been used in the space applications. However, there is a high demand for development of cheap and cost-effective routes for their widespread use in the PV market. In this chapter, we review on the different generations of solar cells, engineering challenges, and the routes for their further improvement. Energy is vital for social and economic development of a modern society [1]. In proportion to the rapid growth of the world population and economy the energy requirement has also increased causing a global energy problem [2]. In today’s world it is not possible to imagine a world without the comfort of modern computers, internet, and mobile phones. Desire of high living standards leads to an increase in the energy demand. As the population grows, there exists a need for more and more energy [3]. Recently, the source for the energy of the world is highly dependent on the fossil fuels. However, the resources of fossil fuels are facing to exhaustion and also the use of fossil fuels leads to a climate change due to the increased amount of carbon emissions to the atmosphere [1]. Two strategies have been proposed to overcome this problem (1) to reduce the dependence on fossil fuels and (2) the use of renewable energy souces. The second strategy actually covers the first one since it does not depend on fossil fuels and has the advantage of reduction of carbon emission to the atmosphere. Renewable energy sources have several other advantages such as the stability, reliability, cost effectivity, and public acceptibility. Among renewable energy sources solar energy is one of the most important one since all other energy forms derive from the Sun. The amount of solar energy reaching the surface of Earth is so vast that in 1 year it is about twice as much as will ever be obtained from all of the Earth's nonrenewable resources of coal, oil, natural gas, and mined uranium combined. Therefore, solar energy is sufficient enough to meet all of the mankind’s energy needs. If this is the case, then the following questions arise: “How to use such a large amount of energy and what are the challenges and the price to pay for it?” One of the most distinguished ways of evaluating such an enormous energy is generating electricity. Solar energy can be converted into electricity using solar cells. A solar cell is an electrical device which directly converts sunlight into electricity by

Comprehensive Energy Systems, Volume 4

doi:10.1016/B978-0-12-809597-3.00426-0

637

638

Solar Cells

photovoltaic (PV) effect. Historically, the first solar cell was demonstrated in 1954 at Bell laboratories. Since then, tremendous effort has been spent for the realization of the scientific background and also commercialization. In this chapter, we will review on different generations of solar cells, engineering challenges, and their further improvement.

4.15.2

Background/Fundamentals

The working principle of solar cells depends on the PV effect. The PV effect is based on the generation of a potential difference at the junction of two different materials upon light irridiation. The following steps are crucial for the operation of solar cells:

• • •

Absorption of photons leads to electron–hole pairs (EHPs). Separation of photogenerated charge carriers at the junction. Collection of the charge carriers at the electrodes.

The conventional solar cell is a typical p–n junction consisting of two layers of differently doped semiconductors. Without the presence of light the cell functions as a p–n junction diode whose current–voltage characteristics is defined by the following Schokley Eq. (4):     qV −1 ð1Þ Id ¼ Is exp nkT where Is is the saturation current, V is the voltage of the diode, n is the ideality factor of the diode, q is the charge of an electron, k is Boltzmann constant, and T is the temperature in Kelvin. When the cell is exposed to solar radiation photons with energies equal or larger than the band gap of the semiconductor are absorbed. Note that a photon with energy less than Eg makes no contribution to the cell output (neglecting phonon-assisted absorption) [4]. The creation of EHPs via light absorption is a crucial step for the operation of solar cells. If the electron and hole are not separated within their lifetime they will recombine. Recombination of light generated EHPs is a loss mechanism in solar cells and hence, if they recombine no current can be generated. One of the ways to separate the EHPs is to make use of the electric field existing in a p–n junction. EHPs are mainly created in the depletion region and due to the built-in potential and electric field, electrons move to the n region and the holes to the p region. The resulting electrical current due to PV effect is called the photocurrent. Thereby, an illuminated cell can be described as a current source paralled by a p–n junction diode [5]. The I–V characteristics of an ideal solar cell under illumination is characterized by the following equation:     qV −1 ð2Þ I ¼ Iph −Is exp nkT The source Iph arises from the excitation of excess carriers by solar radiation [4]. The equivalent circuit of a solar cell is shown in Fig. 1. We can obtain open circuit voltage by setting I¼0     Iph Iph kT kT þ 1 ≈ ln ln Voc ¼ Is Is q q

ð3Þ

The maximum Voc is the built in potential of the junction and the maximum built-in potential is close to the band gap [4]. The current–voltage characteristics of a solar cell is shown in Fig. 2. To derive the maximum-power operating point, the output power is given by P¼IV

ð4Þ

The condition for the maximum power can be obtained for dP/dV ¼0 Pm ¼ Im  Vm ¼ FF  Voc  Isc

ð5Þ

I

h

RL

Fig. 1 Ideal equivalent circuit of solar cell under illumination.

≡

IL

RL

V

Solar Cells

639

2.0 1.5

I (mA)

1.0 0.5 0.0

0.0

−0.5

0.2 PMAX=VMPP* IMPP

0.4

U(V)

0.6 IMPP

−1.0

VMPP

−1.5

Isc

Voc

Fig. 2 Current–voltage (I–V) characteristics of a solar cell.

Zenith (perpendicular)

AM

1.

5

AM 0

ECOS 98

AM 1.0

48.2 °

Atmosp here

Earth Fig. 3 Schematic representation of air mass (AM) sunlight spectra. Reprinted from Rostalski J, Meissner D. Monochromatic versus solar efficiencies of organic solar cells. Sol Energy Mater Sol Cells 2000;61(1):87–95 with permission from Elsevier.

The fill factor (FF) is a measure of the sharpness of the curve and is defined as FF ¼

Vm  Im Voc  Isc

ð6Þ

The ideal power conversion efficiency (PCE) is the ratio of the maximum power output to the incident power Pin η¼

Pm Im  Vm Isc  Voc  FF ¼ ¼ Pin Pin Pin

ð7Þ

When defining the PCE it is important to use a well-defined and reproducible light spectrum. The air mass (AM)-solar spectra are certainly the standard light spectra to use for outdoor PV applications [6]. AM defines the degree to which the atmosphere affects the sunlight received at the earth's surface. The secant of the angle between the sun and the zenith (sec θ) is defined as the AM number and it measures the atmospheric path length relative to the minimum path length when the sun is directly overhead [4]. Shematic representation of AM sunlight spectra is depicted in Fig. 3. For PV applications, the global AM 1.5 spectrum is used as a reference spectrum. The global AM 1.5-spectrum combines a direct AM 1.5 spectrum and a standard spectrum of scattered light [6].

4.15.3

Systems and/or Applications

Solar cells are divided into three categories which are called as generations [7]. The first generation solar cells are the oldest and involve single and multicrystalline solar cells which are produced on wafers. The difference between the two types is the crytallization level of the semiconductors used in these devices. The solar cells are named as single crystal if the wafer contains only one crystal whereas they are named as multicrystal solar cells if the wafer contains crystal grains [8]. Single crystal solar cells exhibit a higher PCE as compared to that of multicrystalline solar cells. The recent PCE of a single cyrstal silicon solar cell is 25% whereas a multicrystalline silicon (mc-Si) solar cell exhibits a PCE of 21% [8].

640

Solar Cells

A-Si thin films, mc-Si, cadmium telluride (CdTe), copper indium diselenide (CIS), and copper indium gallium selenide (CIGS) are employed in second generation solar cells. The PCEs of the solar cells employing a-Si and mc-Si thin film solar cells are 10% and 11%, respectively, whereas the PCEs of CIGS (minimodule) and for CdTe (cell) are recorded as 18% and 21%, respectively [8]. Although first generation solar cells exhibited higher conversion efficiencies than that of second generation solar cells the latter are more likely applicable to the building integrations and are more compatible with flexible substrates. Nanocrystal solar cells, organic/hybrid solar cells, dye sensitized solar cells (DSSCs), and perovskite solar cells can be counted as third generation solar cells. Third generation solar cells involve novel technologies. Low cost, easy fabrication, compatibility with flexible substrates can be counted as the main advantages. However, their PCEs are still low as compared to that of first and second generation solar cells. Different generations of solar cells will be reviewed in detail below. First generation solar cell technology comprises of crystalline silicon solar cells. They are made up of either a single silicon crystal (monocrystalline) or a silicon which is made up of many crystals (polycrystalline or multicrystalline) [9]. Among PV materials, silicon is second most abundant element in the earth's crust. It is a suitable semiconductor material for PV applications. Silicon is an indirect band gap semiconductor with a band gap of 1.1 eV and also has direct band gap of 3.4 eV at 25° C [10]. It is nontoxic that is particularly significant for a green technology. It has long lifetime, physical, chemical, and electrical properties. The crystalline silicon has a density of 2.3290 g/cm3 and exhibit a diamond cubic crystal structure [10]. The PV module containing crystal silicon solar cells are long-term stable in the oxygen environment (420 years) [11]. The oldest solar cell technology is silicon wafer-based solar cells. These are entitled as “single-crystal silicon solar cells” or “monocrystalline silicon solar cells” (sc-Si). Single-crystal-based silicon technology dominates about 87% of the PV market. Efficiency and stability are the most important factors that have to be taken into account when producing solar cells. Single-crystal Si solar cells possess high conversion efficiencies because they are fabricated from the highest grade silicon. On the other hand, they have long lifetime and are stable for about 25 years. Despite these advantages, the high production costs and sensitivity to high temperatures are the main drawbacks of this technology. Historically, the first diffused silicon solar cells exhibiting PCE of 4.5% were developed at Bell Laboratories in 1954 by Pearson et al. [12]. Since then, there has been a rapid progress in the PCE of silicon solar cells and hence, they have been used as a source of power for satellites in space applications [13]. In almost 40 years, by the end of 1990s, silicon solar cells employing n type Si exhibited a PCE of 14% [14]. Besides silicon solar cells employing n type silicon, solar cells consisting of p-type silicon with a phosphorus doped emitter have also been fabricated [15]. The development of low and high temperature processes have led to an improvement in the PCE of sc-Si solar cells. PCE of c. 23% in 4 m2 area solar cell with a high temperature process in boron addition and a high open circuit voltage up to 0.7 V was announced [16]. Later, a PCE of c. 24% for the cells with 25 cm2 area using a low temperature process for thermal oxidation which is less than 850°C was reported [17]. PCE was further improved to c. 25% using a novel cell structure of passivated emitter rear locally diffused (PERL). Surface passivation has been used to minimize recombination of charge carriers [18]. It seems that the PCE of c. 25% is the highest PCE received by several different groups working in the area of single crystal silicon solar cells. One of the problems affecting the PCE seems to be the reflection losses. In order to reduce reflection losses single-crystal silicon solar cells are commonly textured by dipping into an alkaline solution such as KOH or NaOH. This is performed possibly by the anisotropic structure of these alkaline solutions, in associated with a suitable choice of the crystal plane orientation at the surface, but is not applicable to multicrystalline Si [19]. On the other hand, alkaline etching solutions may lead to undesirable stages between grains [20]. Besides reflection losses there are also other losses such as photon losses, back contact absorption; minority carrier losses due to recombination in the silicon bulk and at the surface; heat losses due to series resistance in the gridline, at the interface between the silicon and the back contact which in turn limit the device performance. Therefore, key parameters to achieve high efficiency crystalline silicon solar cells and to overcome the loss mechanisms can be summarized as follows [21]: 1. Minimization of the carrier losses via passivation of the front electrode to reduce carrier recombination, shallow doped p–n junction, heterojunction with thin amorphous layers on a crystalline silicon base. 2. Minimization of photon losses via texturing the surface, using back contact structure to prevent front contact absorption losses, making flat back surface by chemical etching of silicon. 3. Minimization of electrical losses via fine gridline front contact and selective emitter. The investigations on silicon solar cells started in 1970s and still continues as a result of which allowed them to take their places in PV market. Polycrystalline silicon is another significant material for the PV market. These solar cells are also called as “multicrystalline silicon solar cells” or “Siemens process” (mc-Si). The Siemens process contains purification of volatile silicon compounds and their dissociation in silicon at high temperatures [9]. In the past, a great number of methods for texturing multicrystalline silicon were used. Some of them have focused on the utilization of reactive ion etching (RIE) associated with a mask to obtain large and standard properties. Other approaches are based on isotropic wet acidic etching [20].

Solar Cells

641

The considerable interest in mc-Si started at the 1970s with record efficiencies around 15%. The historical increase in efficiency was basically affected by the improvement of the material quality either during the crystallization process or the cell process utilizing internal hydrogen passivation of crystal defects [11]. An effective way to overcome the influence of material quality on the cell performance is to decrease of the cell thickness and to use an effective surface passivation. This path led to today’s record solar cell on mc-Si with a PCE of c. 20% with a thickness of only 99 mm [22]. Multicrystalline Si is much less pure than the single crystal Si and their efficiencies reflect this situation. Mc-Si has been made by pouring molten silicon and allowing it to cool and this process is called casting. The resulting silicon has no overall lattice structure, but the ingot fabricated has large column grains of crystallinity. The grain boundaries in polycrystalline silicon obstruct the flow of electrons and reduce the power output of the cell. Therefore, the PCE for a module made of polycrystalline silicon ranges between 10 and 21%. An extensive approach to fabricate multicrystalline silicon PV cells is to slice thin wafers from blocks of cast polycrystalline silicon. Another more advanced approach is the “ribbon growth” method in which silicon is grown as thin ribbons with the approach thickness for making PV cells [23]. Mc-Si is also produced from a lower-grade feedstock, consisting primarily of reject and out-of-spec material from the microelectronics industry. Because mc-Si material is grown very rapidly, the ingot experiences higher thermal stresses, accompanied by high defect densities. Dislocations are the primary intragrain defects. The impurities interact with defects during crystal growth, which leads to a very strong influence of defects on the cell performance [24]. Despite the limitations multicrystalline Si is one of the oldest and the matured technologies with 80–90% share in world wide installations [25]. Although PCEs of up to 21% are reported for this type of solar cells. There is still much to do to improve it further. Charge carrier transport hindrance through the active layer, the existence of nonlinear shunt paths and high charge carrier recombination can be counted as the main reasons for the less efficient polycrystalline silicon solar cells. Several groups work on novel cell designs and processing methods to overcome these problems. Although first generation solar cells have reached remarkable power conversion efficiencies their primary drawback is still their costs, which are due to the use of high purity materials. On the other hand, they require cost intensive production techniques. Therefore, several research groups focused on second generation solar cells which include amorphous silicon, micro- or nanocrystalline silicon, CdTe, and CIGS. Amorphous silicon-based solar cells have lots of advantages such as less material needs, large scale manufacturing, and low temperature processing. Besides, amorphous silicon-based solar cells can be produced on affordable and plastic substrates. In addition to that, a-Si has distinct energy gap at 1.75 eV and high absorption coefficient which are both better than crystalline ones. Amorphous silicon layers were first deposited by Chittick [26]. David Carlson and Christopher Wronski produced first amorphous silicon solar cell at 1976, which exhibited a PCE of 2.4% [27]. The solar cell performance was further improved by deposition of a-Si by glow discharge in silane gas (SiH4) [27,28]. Consequently, hydrogenated amorphous silicon (a-Si:H) has been achieved. Most of the amorphous silicon term in the literature refers to hydrogenated amorphous silicon. This hydrogenation process leads to the diminishing of the gap state density. Hence, a-Si:H had been used to produce solar cells with PCEs up to 5.5% [29]. But, in a-Si:H solar cells light trapping became an issue. In addition to that, a-Si:H solar cell had some other drawbacks due to doping capabilities. Fermi energy level was obligated to lie further from conduction or valance band, even with heavily doping. Another drawback of both p and n type a-Si:H was the short diffusion length of 0.1 µm. To minimize these disadvantages, the p-i-n type a-Si:H solar cell has been fabricated by Carlson and Wronski [27]. P-i-n type amorphous silicon solar cell developed swiftly. In 1982, a-Si:H solar cell efficiencies were over 10% [30]. Nevertheless, a-Si:H solar cells suffer from a light-induced degradation effect which is called as Staebler–Wronski effect [31] which leads to a dramatical decrease in PCE during the initial hundred hours under light. On the other hand, this problem could be solved by annealing at about 150°C for a number of time but this solution was not an exact solution. If solar cells stay again hundred hours under light after annealing, the Stabler–Wronski effect will occur again. Although lots of researchers have worked on a-Si:H thin film solar cells, there has been a saturation in PCE. The recent PCE records of a-Si:H thin film solar cell is about 10% [32]. For a long time, researchers have focused on a-Si:H solar cells, some of these studies have focused on deposition methods, the others included hydrogen dilution while deposition. Strong hydrogen dilution of the silane gas mixture during a-Si deposition has been found to decrease the density of imperfect locations and improve the stability of the material against light-soaking effects [33,34]. Hydrogen dilution has more significant effects. When hydrogen dilution increases enough, the amorphous silicon thin film becomes microcrystalline. In other words, it looks like very few silicon crystallites are dispersed inside the amorphous structure of silicon [35]. Microcrystalline silion layers were first deposited by Veprek and Marecek [36]. Later, it has been realized that doping of µc-Si:H can be easier than that of a-Si:H. But the first µc-Si:H layers were not high grade because of high defect density, therefore most of n-type layers were produced without doping gases. However, the first µc-Si:H solar cell was fabricated in 1994 with a moderate PCE of 4.6% [37]. Their light induced degradation is acceptable. They require less expensive materials for production and exhibit high FFs. The major disadvantage of µc-Si is that its absorption coefficient is lower than that of amorphous Si [38]. Initially, p-i-n type µc-Si:H solar cells exhibited a PCE of 7.7% [39]. However, µc-Si:H is an indirect semiconductor so its absorption coefficient in the visible range of spectrum is comparatively low, it means thicker µc-Si:H layers should be employed in the devices for reasonable photogeneration. The latest PCE of this type of solar cells was recorded as 12% [40] but µc-Si:H solar cells are still open for improvement.

642

Solar Cells

CdTe is a direct band gap material (1.45 eV) which is also a leading material as an absorber in solar cells, due to its high absorption coefficient, low-cost, and high chemical stability [41,42]. CdTe solar cells generallly contain CdS as a window layer because CdS has low band gap which is about 2.42 eV and short wavelength region can be absorbed. The first reasonable efficiency of about 6% for CdS/CdTe solar cell was reported 1972 [43]. In most of the CdTe solar cells, the superstrate configuration is used which is due to the difficulty in making the rear contact. When chemical bath deposition method was chosen for CdS layer and closed space sublimation method was used for CdTe layer, the PCE approached to 16%, in 1993 [44]. Generally, CdTe is used as a p-type material in solar cells, but to choose an appropriate contact for p-type material is very hard because the contact resistance should be low. Because of this Cu is frequently preferred. Normally, the theoretical value of efficiency is predicted about 30%. But some difficulties prevent to reach this value. One of them is short minority carrier lifetime due to defected locations at the interface between CdTe and CdS. Another one is inefficient transparency and the lack of proper contact between p-type layer and back electrode [45]. Another strategy for the improvement was the crystallization of the layers. CdCl2 treatment was applied to CdTe layer. If this process is not used, the short circuit current is very low and also the PCE is very low. The recent efficiency for this type of solar cells has reached at 21% [46]. Cu(In,Ga)Se2 is another important material because of its high efficiency values, long term stability, and less expensive material usage [47]. As an absorber material, the band gap of CuInSe2(CIS), is about 1.0 eV. By associating the CIS with Ga or S, the band gap can be adjusted at 1.7 eV so that the open circuit voltage should increase faster than the short circuit current would decrease [48]. Commonly, CIGS solar cell’s device form is in the substrate configuration which has suitable process conditions but it needs an encapsulation layer. Unlike this, superstrate configuration does not need an encapsulation but the efficiencies could not pass over the 5% barrier [49]. At the beginning, monolayer CdS was used as a either buffer layer or front contact. Afterwards, because of absorption losses at the solar spectrum some materials which had energy gap above 3 eV, were replaced with CdS. N type semiconductors with band gaps of 2.0 and 3.6 eV have been used as buffer layers in CIGS solar cells. Nevertheless, CdS stands as the most generally used buffer layer due to its permanent abundance. Cd-free semiconductors showed also promising results as a buffer layer. Cd-free buffer layers exhibited PCEs above 11% [50]. Generally, many researchers focused on deposition techniques rather than focusing on the device structure. Improvement of the deposition methods gave better results. The latest recorded efficiency for CIGS solar cell is 21.0% [51]. First and second generation solar cells have already taken their places in the PV market. However, the three most important criteria should be fulfilled for the first and second generation solar cells to preserve their existence permenantly in the PV market. These criteria are the PCE, lifetime, and the costs. Although they have exhibited reasonably good PCEs, their sensitivity to high temperatures, high temperature processes involved in the production and high production costs are still the issues to be resolved. Despite the scientific and engineering work done on these type of solar cells the PCEs seem to be saturated. Therefore, research on alternative materials or production routes are of great interest. These two solar cell technologies are based on inorganic semiconductors which show either n or p-type conductivity. The discovery of the fact by Alan Heeger, Hideki Shrikawa, and Alan McDiarmid that organic materials such as polymers can also be semiconductors or even conductors was a breakthrough and led to the birth of the so called third generation solar cells. Organic semiconductors have several advantages such as low cost, light weight, compatibility with the flexible substrates, easy tunability of the chemical, and physical properties via synthetic routes. Therefore, they found application in many different device structures such as organic solar cells, tandem solar cells, DSSCs, and hybrid solar cells which belong to the group of third generation solar cells. These device structures will be reviewed in detail below. The discovery of photoinduced electron transfer from a conjugated polymer to a fullerene has become a milestone in the development of organic solar cells [52,53]. Since then, there has been a tremendous effort to synthesize novel materials, design cells, and introduce novel concepts. Organic semiconductors have been used not only in organic solar cells but also in other electronic devices such as light emitting diodes, field effect transistors, lasers, etc. Therefore, a new era has been born the so called organic electronics. Therefore, the end of 1980s and the beginning of 1990s experienced a kind of scientific revolution. This transition from solid state semiconductor physics to molecular chemistry/physics was a paradigma shift. Together with these developments the electronics of the 21st century became based on molecular physics and chemistry. Organic semiconductors have several advantages, for example, they have high absorption coefficients, their band gap can be easily tuned by simple chemical synthesis routes [54,55]. They may possess high charge carrier mobilities [56]. On the other hand, organic materials can be processed using simple techniques which are not applicable to inorganic semiconductors. Organic solar cells comprise of organic layers sandwiched between two metal electrodes. Depending on the solubility of the materials, organic solar cell materials are divided into two groups of either solution or vacuum processed. Most of the materials are soluble in common organic solvents such as chloroform, chlorobenzene (CB), and toluene. Generally, small organic molecules which are not soluble in common organic solvents are vacuum processed through sublimation. Conjugated polymers and fullerenes are the mostly used organic semiconductors in organic solar cells. Conjugated polymers possess fundamentally different electronic configuration. The chemical bonding in conjugated polymers leads to one unpaired electron (the π electron) per carbon atom and π bonding leads to electron delocalization along the backbone of the polymer, which provides the “high way” for charge mobility along the backbone of the polymer chain. The chain symmetry such as the number and kind of atoms within the repeat unit determines the electronic structure in conducting polymers. As a result, such polymers can exhibit semiconducting or even metallic properties [57]. Conjugated polymers are generally used as electron donors, the buckminster fullerene C60 is evaluated as

Solar Cells

643

an electron acceptor. However, the solubility of C60 is limited. Wudl et al. synthesized a soluble derivative of C60, [6,6]-phenylC61-butyric acid methylester (PCBM), (1-(3-methoxycarbonyl) propyl-1-phenyl[6,6]C61) [58]. An ideal donor should transport the holes efficiently, i.e., p-type whereas an ideal acceptor should transport the electrons efficiently, i.e., n type. In the case of organics the n and p-type definitions refer to the fact that n type semiconductors are good electron conductors, whereas p-type ones are good hole conductors. Therefore, an alternative definition for organic semiconductors is donor for the p-type and acceptor for the n type. In an organic solar cell the donor gives electrons to the acceptor. In the case of inorganic semiconductors, for example, n type silicon is achived by introducing donor impurities. Doping mechanisms in organic and inorganic semiconductors are totally different. Organic solar cells are fabricated in the sandwich geometry. As subtrates, transparent conducting oxide (TCO) coated glasses are used. Indium tin oxide (ITO) is one of the mostly used TCO in organic solar cells. However, high quality ITO is expensive, the depletion in the indium supplies affect also its widespread use in organic solar cells. On the other hand, it cannot be solution processed which in turn may weaken the flexibility claim of organic solar cells. A random carbon nanotube network has been investigated as an electrode [59]. Alternative materials to replace ITO is of great interest. poly(2,5-dibromo-3,4-ethylenedioxythiophene) (PEDOT):poly(styrene sulfonate) (PSS), poly(ethylene-dioxythiophene) doped with polystyrenesulfonic acid, is coated from an aqueous solution on top of ITO coated glass substrates. PEDOT:PSS improves the surface quality of the ITO substrates and also allows hole injection/extraction. The active layers of donor and acceptors are coated using either solution or vacuum processing techniques depending on the solubility of the organic semiconductors used in the device configuration. Aluminum (Al) which is a lower workfunction metal as compared to ITO is used as a top metal electrode. The operation principles of organic solar cells depend on the following consequent steps: (1) the absorption of a photon leading to exciton creation, (2) exciton dissociation, (3) charge separation, and (4) charge transport to the appropriate electrodes [60]. The photoexcitations in organic semiconductors do not directly lead to the formation of free charge carriers but instead bound EHPs, called excitons. These excitons should be separated into free charge carrier within their lifetime. Electric fields are necessary for the separation of excitons. These fields can be supplied either by applying an external electric field or it already exists at the interfaces. The change of the potential at the interface is a possible source for local electric fields. If an exciton can reach such an interface within its lifetime, photoinduced charge transfer may occur [61]. Exciton diffusion lengths in organic semiconductors are between 10 and 20 nm. For an efficient dissociation exciton diffusion length should be comparable with the donor acceptor phase separation length [60]. Excitons decay via radiative or non-radiative paths before reaching the interface which is a loss mechanism for organic solar cells. For an efficient device performance the separated charges should be transported to the respective electrodes. The transport of the charges is affected by recombination during their journey to the electrodes, especially if the same material is used for transport of both electrons and holes. Bilayer and bulk heterojunction device concepts (see Fig. 4) are the most widely used device architectures in organic solar cells. A bilayer organic device consists of two individual layers of p and n type organic semiconductors coated on top of each other and sandwiched between two metal electrodes. In such devices only the excitons created within the distance of exciton diffusion length from the interface can reach the junction interface. The excitons created further apart from the interface may decay radiatively or non-radiatively which is a loss mechanism and limitation for bilayer heterojunction solar cells. Bulk heterojunction concept has been proposed to overcome the limitations of the bilayer heterojunction concept. In a bulk heterojunction solar cell the active layer consists of a mixture of a donor and an acceptor blended together. Solution processibility of the donor and acceptor facilitates the possibility of blending various type semiconductors. Bulk heterojunctions can also be achived by coevaporating donor and acceptors [62]. Since PCE is dependent on the Voc, Isc, FF, these parameters are critical and the understanding of the origin of these quantities and the ways to improve them become important.

4.15.3.1

Open Circuit Voltage

In a classical metal–insulator–metal picture the Voc originates from the difference of the metals’ workfunctions [63]. In organic solar cells, Voc is dependent on the difference between the highest occupied molecular orbital (HOMO) of the donor and the lowest unoccupied molecular orbital (LUMO) of the acceptor [64,65]. The origin of Voc in organic solar cells is still under debate since several studies indicate different origins. In the initial studies Brabec et al. demonstrated that there is a linear correlation between the LUMO of the acceptor and the observed open circuit voltage [64]. Later, Scharber et al. demonstrated that the following equation determines the Voc: Voc ¼ EHOMO_DONOR −ELUMO_ACCEPTOR −0:3

ð8Þ

According to the above formula, the Voc is independent of the LUMO of the donor. Mola et al. have chosen three different polthiophene donor polymers with similar HOMO levels but different LUMO levels in order to verify the correlation between the Voc and the LUMO offset of the bulk heterojunction solar cells [66]. According to this study, the open circuit voltage decreased monotonically with increasing LUMO offset. This variation was associated with diminished recombination of charge carriers for high offset values. Therefore, they concluded that the LUMO level of a donor should be optimized with respect to the LUMO level of the acceptor in order to improve the magnitude of the open circuit voltage as well as the performance of the devices. The morphology of the bulk heterojunction solar cells and also the charge carrier losses at the electrodes may also affect the Voc [67,68].

Solar Cells

644

e− h+

LUMO LUMO

e−

HOMO HOMO Acceptor

Donor ITO

AI

(A)

Au Au C60 MEH-PPV

PEDOT:PSS

PEDOT:PSS ITO Glass

ITO Glass

P3HT (B)

PCMB (C)

Fig. 4 Schematic description of (A) charge transfer, (B) bilayer heterojunction, and (C) bulk heterojunction solar cells. HOMO, highest occupied molecular orbital; ITO, indium tin oxide; LUMO, lowest unoccupied molecular orbital; MEH:PVV, poly[2-methoxy-5-(2′-ethylhexyloxy)-p-phenylene vinylene]; P3HT, poly(3-hexylthiophene); PCBM, [6,6]-phenyl-C61-butyric acid methylester; PEDOT, poly(2,5-dibromo-3,4-ethylenedioxythiophene); PSS, poly(styrene sulfonate).

Interfacial effects at the metal/organic semiconductor interface change the workfunction of the electrodes and influence the open circuit voltage [69,70]. Modification of the ITO electrodes by plasma etching or coating with a higher work function organic material or the use of self assemble monolayers on ITO surface have been chosen as ways to modify the work function of ITO [71–74]. As a summary, Voc is sensitive to the energy levels of the investigated materials as well as the interfaces.

4.15.3.2

Short Circuit Current

Isc is defined by the following formula: Isc ¼ neμE

ð9Þ

where n is the density of charge carriers, e is the elementary charge, μ is the mobility, and E is the electric field. Short circuit current density Jsc (mA/cm2) term is generally used in solar cells rather than short circuit current to remove the dependence of the solar cell area. Although organic semiconductors have high absorption coefficients, their absorption range is mostly between 350 and 650 nm which brings in the mismatch between the organic semiconductors and the solar spectrum. This can be considered as a limitation in absorption. The organic semiconductors having such an absorption profile have band gaps higher than 2 eV [60,75]. Therefore, the synthesis and application of low band gap polymers that absorb light above 600 nm is of great interest. Low band gap polymers are defined those having a band gap lower than 2 eV [76–82]. Another possibility to overcome the limitation of absorption is to increase the layer thickness. It has been already demonstrated that the thickness of the active layer has an effect on the Jsc of organic solar cells. However, it should be noted that thickness is also a sensitive parameter to charge carrier mobility and transport. Due to lower mobility of organic semiconductors as compared to that of inorganic semiconductors the thickness cannot be increased too much. Moule et al. concluded that high efficiency organic solar cells could be achieved with film thicknesses over 100 nm [83].

4.15.3.3

Fill Factor

The FF of an organic solar cell depends on the charge separation, transport, and recombination. Morphology, thickness, the regioregularity of the conjugated polymer, and the interfaces between the electrodes and the blend layer have a large impact on the FF by affecting the series resistance (Rs), and the shunt resistance (Rsh). The Rs can be calculated

Solar Cells

645

from the inverse slope of the I–V curve in the first quadrant and is closely correlated with the intrinsic resistance, morphology, and the thickness of the semiconductor layer. Rsh is correlated with the amount and character of the impurities and defects in the active organic semiconductor layer since impurities and defects cause charge recombination and leakage currents [84,85]. As summarized above the PCE of organic solar cells is dependent on three important factors of short circuit current density, open circuit voltage, and the FF. However, the following parameters also in turn affect these parameters and thereby the PCE of organic solar cells.

4.15.3.4

Morphology

Bulk heterojunction solar cells consist of blends of two different organic semiconductors one of which is an electron donor and the other is acceptor. Despite the ideal HOMO–LUMO level relations of the donor and the acceptor materials, the physical interaction, the morphology of these materials play important roles in the overall PCE. The miscibility of the donor and acceptor in the same solvent, the choice of the solvent, concentration of the donor and the acceptor, deposition techniques and the thermal annealing are the other factors affecting the morphology [86]. Below is an example of one of our studies on the morphology of the polymer:fullerene blends. We have performed an atomic force microscope study on a polymer:fullerene blend. We have blended polymer and a fullerene derivative in 1:1 and 1:4 wt ratio in chloroform. Fig. 5(A) and (B) shows the atomic force microscopy (AFM) images of polymer:fullerene blends in 1:1 and 1:4 wt ratio in chloroform. We have observed that as the concentration of the fullerene derivative increased the blend film exhibited a rougher morphology which is due to the large phase separation of polymer and fullerene. Since morphology is dependent on the choice of solvent, when studying a new blend system of polymer and fullerene an optimization is definitely required. We can conclude that there is not a general prescription that can be applied to all blend systems. In each case, the choice of the solvent should be optimized.

4.15.3.5

Charge Transport and Mobility

Besides morphology, charge carrier transport, and mobility are the most important issues in organic solar cell research. The key quantity in charge carrier transport is the charge carrier mobility. As mentioned above, charge carrier mobilities of organic semiconductors are several orders of magnitude lower than those of inorganic semiconductors. The low mobilities arise from the localization of electronic states on individual molecules or segments of molecules. Relatively weak intermolecular interactions mean that charge transport is best described by hopping transport rather than band transport [87]. Balanced electron and hole mobility are required for a better PV performance. Low mobilities limit the device performance by enhancing the probability of charge recombination, limiting the charge separation yield, and increasing resistive losses [87]. Solution processability of organic materials seem to be an important step for achieving milestones in organic solar cell research. The milestones achieved in solution processable bulk heterojunction solar cells can be summarized as follows: A breakthrough on solution processed organic solar cells was achieved by Shaheen et al. [88]. They showed that the PCE of organic PV devices based on a conjugated polymer/methanofullerene blend was dramatically affected by the molecular morphology. By structuring the blend to be a more intimate mixture that contained less phase segregation of methanofullerenes, and 35.0 nM

25.0 nM

2.00

2.00

12.5 nM

17.5 nM

0.0 nM

0.0 nM 1.00

1.00

0 0 (A)

1.00

2.00

0 0 (B)

1.00

Fig. 5 Atomic force microscopy (AFM) images of polymer fullerene blends with (A) 1:1 and (B) 1:4 wt ratio in chloroform.

2.00

646

Solar Cells

by simultaneously increasing the degree of interactions between conjugated polymer chains, they have fabricated a device with a PCE of 2.5% under AM 1.5 illumination [88]. Padinger et al. investigated the effect of postproduction treatment on organic solar cells containing poly(3-hexylthiophene) (P3HT) as a donor. They used ITO/PEDOT:PSS/P3HT:PCBM/LiF/Al device configuration for bulk heterojunction organic solar cell. They applied both annealing (at 75°C) and at the same time subjected the cells to an external voltage larger than Voc (applied external voltage ¼2.7 V); consequently device exhibited a PCE of 3.5%. They have concluded that postproduction treatment for P3HT-based bulk heterojunction type solar cells is important since it improves the crystallization of P3HT [89]. Kim et al. used solution-processed titanium oxide (TiOx) as electron transport layer (ETL) and also optical spacer for improving the device efficiency. They improved the PCE of conventional bulk heterojunction organic solar cells with a new device structure in which TiOx was used between active layer (P3HT:PCBM) and top electrode (Al) with low temperature production. They achieved a PCE of 5%. They concluded that higher absorption resulted from TiOx layer as an optical spacer. By the help of the TiOx layer, more charge carriers were generated, therefore short circuit current density and thereby the efficiency of the devices were improved [90]. Leclerc et al. synthesized a novel low-bandgap copolymer, which was called as poly[N-9′-heptadecanyl-2,7-carbazole-alt-5,5(4′,7′-di-2-thienyl-2′,1′,3′-benzothiadiazole)] (PCDTBT), for solar cell applications. PCDTBT was used as a donor which had two broad absorption bands with peaks at 398 and 576 nm and an absorption onset at 660 nm (1.88 eV). The investigated device structure was ITO/PEDOT:PSS/PCDTBT-PCBM(1:4)/Al. They reported a PCE of 3.6% which was remerkable case for this type of a novel donor material [91]. Sung Heum Park et al. fabricated solar cells with PCEs of 6.1% using an alternating copolymer, PCDTBT in bulk heterojunction composites with the fullerene derivative [6,6]-phenyl C70-butyric acid methylester (PC70BM). The PCDTBT/PC70BM solar cells showed the best performance of any bulk heterojunction system studied. The internal quantum efficiency was close to 100%, referring that essentially every absorbed photon results in a separated pair of charge carriers and that all photogenerated carriers are collected at the electrodes. The device structure was glass/ITO/PEDOT:PSS/PCDTBT:PC70BM/TiOx/Al [92]. Ng et al. studied the effects of gold nanoparticles (AuNPs) incorporated in the hole transporting layer (HTL) of poly[[4,8-bis[(2ethylhexyl)oxy] benzo[1,2-b:4,5-b′] dithiophene-2, 6-diyl] [3-fluoro-2-[(2-ethylhexy)carbonyl]thieno[3,4-b]thiophened iyl]] (PTB7): [6,6]-phenyl C71 butyric acid methylester (PC71BM)-based solar cells. The impacts of AuNPs on the optical response of the devices were modeled by finite-difference time-domain (FDTD) simulation. The size of the AuNPs used in this work was around 50–70 nm, so that 10–20 nm penetrated from the HTL into the active layer. They found that PCEs of the devices with AuNPs were significantly enhanced from 7.5%, for the reference device, to 8.0%, 8.1%, and 8.2% for Au nanosphere-, nanorod-, and nanocubeincorporated devices, respectively [93]. Tandem solar cells provide an effective way to harvest a broader spectrum of solar radiation by combining two or more solar cells with different absorption bands. However, for polymer solar cells, the performance of tandem devices lags behind single-layer solar cells mainly due to the lack of a suitable low-bandgap polymer. Dou et al. demonstrated highly efficient single and tandem polymer solar cells featuring a low-bandgap conjugated polymer poly{2,6′-4,8-di(5-ethylhexylthienyl)benzo[1,2-b;3,4-b]dithiophene-alt-5-dibutyloctyl-3,6-bis(5-bromothiophen-2-yl)pyrrolo[3,4-c]pyrrole-1,4-dione ((PBDTT-DPP): band gap, ~1.44 eV). A single-layer device based on the polymer provides a PCE of ~6%. When the polymer was applied to tandem solar cells, PCE of 8.62% was achieved [94]. Recently, Heliatek company announced a PCE of 13.2% in February 2016. The device was an organic photovoltaic (OPV) multistack cell. Most basically, the idea behind the tandem solar cells is based on increasing the number of energy levels. Tandem organic solar cells are made up of p–n junction using various semiconductor materials piled up on top of each other. To produce the highest efficiency from the entire tandem device, the power of each cell in the system must be optimized. This optimization can be achieved by selecting;

• • • •

Selecting most appropriate band gaps of materials. Thicknesses of the thin films. Junction depths. Characteristics of doping materials.

Two variations are used in tandem solar cells: the first one is “mechanically stacked” cell, in which each cell in the stack is considered as a separate device known as parallel connection. The second one is an “in-series” cell in which each cell in the stack is connected in series, so that the overall cell has only two terminals on the front and back of the whole stack [95]. A typical organic tandem solar cell is shown below (see Fig. 6). If we compare two variations, in series connections, the photo-generated holes of one cell are brought closer to photogenerated electrons of the next cell. These carrier movements are limited at the interface due to the existence of an internal electric field orientated in opposite direction. Thus, this situation has a drawback which makes the recombination of the carriers at the interface more possible through the tunnel junction. In parallel connections, there are two different places that can generate EHPs. One is in the front of the layers which uses high-energy photons. The other is in the back of the layers which uses low-energy photons. The photo-generated electrons are accelerated toward the front contact and holes are accelerated toward the back contact. In this matter, the recombination possibility has been reduced to minimal level and charge carriers gain very high kinetic energies due to continuous acceleration across the device structure [96].

Solar Cells

647

Top electrode Top device Intermediate Bottom device Transparent bottom Fig. 6 Schematic representation of an organic tandem device comprised of two subcell.

According to some scientific reports, tandem solar cells made up of three different structures: 1. First structure, tandem organic solar cells, is created by using evaporation techniques, which means both the bottom (in front of the light illumination) and the top (back) cells are based on low-molecular-weight evaporated molecules. 2. Second structure, hybrid tandem organic solar cells in which one of the cells is produced by solution processes, while the other cell is based on vacuum-deposited low-molecular-weight materials. Those two can be on top or bottom cells. 3. Third structure contains fully solution-processed tandem organic solar cells where both the bottom and top cells are processed from solution [95]. Hiramoto et al. realized the first known organic tandem solar cell in 1990 [97]. They used series connected two subcells based on evaporated small molecules. Each subcell included containing 50 nm of metal-free phthalocyanine (H2Pc-p-type) and 70 nm perylene tetra-carboxylic derivative (Me-PTC n type). They evaporated an ultra-thin (2 nm) Au layer to achieve an ohmic contact between the two subcells. As a result the device exhibited a Voc of 0.78 V. That was the double value of Voc of a single cell which was around 0.44 V. Approximately 10 years later, Forrest and his group inspired from the same aspect, and they utilized an another type of small molecule material. In 2002, Yakimov and Forrest [98] illustrated high Voc organic solar cells that unified two, three, or five stacked thin heterojunctions containing of Cu-phthalocyanine (CuPc) as a donor and 3,4,9,10-perylenetetracarboxylic bis-benzimidazole (PTCBI) as an acceptor. The line of donor to acceptor to metal has been done over two, three, and five times, resulting in dual, triple, and fivefold heterojunction PV cells. The measurements of two and three heterojunction cells has been performed under one sun (AM 1.5 illumination) and PCE (η) turned out to be η ¼2.5% and 2.3%, with a Voc ¼0.93 and 1.2 V, respectively. This work showed that light absorbtion of each individual stacked cell has a crucial part in their multiple heterojunction architecture. More clearly, light absorption is reduced in each stacked cell through the device. Definitely, all subcells has to be properly thin to produce a balanced current among all of them. In 2015, Heeger and his group reported the best PCE for tandem solar cells. They emphasized two aspects: 1. The synthesis of novel donor materials for more harvesting light absorption [99,100]. 2. The rational design for new low loss interconnection layers (ICLs) to obtain better charge extraction and reduced recombination [99]. For both subcells they have used the same organic donor material (so called organic homo-tandem cells). They found out a new ICL based on pH neutral CPEs as the p-type HTL and a metal oxide as the n-type ETL for solution-processed organic homotandem solar cells. In polymer:fullerene active layers, poly[4,8-bis(5-(2-ethylhexyl)thiophen-2-yl)benzo[1,2-b:4,5-b′] dithiophene-co-3-fluorothieno[3,4-b]thiophene-2-carboxylate] (PTB7-Th) has been used as donor material and [6,6]-phenyl C71butyric acid methylester (PC71BM) has been used as acceptor material. Firstly, devices were optimized for single cells with PCE of c. 9%. Two same BHJ layers have been stacked in series by using a new ICL, achieving the best PCE of 11.3% [99]. As is summarized above the highest PCE achieved using this concept was c. 12%. However, Dennler et al. have shown that realizing tandem cells by connecting in series two sub-devices does not always enhance the potential of the corresponding single junction cells. When the donor materials employed in organic solar cells yield performance below their capabilities, tandem can be highly beneficial. Moreover, their calculations suggested that tandem cells with efficiencies up to 15% are technically feasible given the availability of an optimized donor couple [100]. Organic materials have big advantages due to their solution phase processing, tunable band gap, which give rise to low cost electricity production, nevertheless oxygen sensitivity of organic materials should be solved for stability issues. Inorganic semiconductors have high charge carrier mobilities and good stabilities. Recently, researchers realized that inorganic materials can be combined with organic materials for solar cell aplications. Hybrid solar cells consist of both organic and inorganic semiconductors. Inorganic semiconductors are used as electron acceptors in hybrid solar cells and are also more stable than organic materials [101– 103]. Inorganic semiconductors have high absorption coefficients and charge carrier mobilities. Device structure and production of hybrid solar cells is similar to that of organic solar cells, the only difference between organic and hybrid solar cells is that organic acceptor materials are replaced by inorganic semiconductors. In order to improve the device performance of hybrid solar cells, both electron and hole mobilities must be balanced [104]. The HOMO and LUMO energy levels of the organic semiconductors and, the conduction and valence band energy levels of the inorganic semiconductors must be chosen properly for a suitable charge transfer.

648

Solar Cells

Bulk heterojunction concept is one of the mostly used ways to fabricate hybrid solar cells. In a bulk heterojunction type hybrid solar cell the photoactive layer consists of inorganic semiconductor nanoparticles and conjugated polymers. Inorganic semiconductors have been used as acceptors whereas semiconducting polymers are used as electron donors. Organic materials may have a donor or an acceptor character. Molecular materials that have a low ionization potential and thus can easily donate an electron are denoted as electron donors. On the other hand, materials having a high electron affinity and thus can easily take up an electron are denoted as electron acceptors. They can be efficient electron or hole transporters, which is determined by intermolecular orbital overlap in the solid state [56]. The blend films of conjugated polymers and inorganic nanoparticles are sandwiched between two metal electrodes. In hybrid solar cells inorganic nanoparticles replaced fullerene derivatives which were used as electron acceptors in organic solar cells. The synthesis of fullerenes is rather energy intensive and difficult. On the other hand, the colloidal synthesis of inorganic nanoparticles is comparably easier. Also, absorption range of inorganic nanoparticles is wider than that of fullerenes which in turn means that thinner devices can be fabricated. Several inorganic nanoparticles such as CdSe, CdS, CuInS2, CuInSe2, titanium dioxide (TiO2), and ZnO have been widely used to fabricate hybrid solar cells in the literature [103–107]. However, the PCEs still remain limited. The PCEs changed between 0.1 and c. 2%. During the synthesis of the nanoparticles a ligand is used. The role of the ligand is to prevent the further growth and oxidation of the nanoparticles. This ligand is an insulator and affects the dispersion of nanoparticles and also hinders the charge transfer from the donors which limits the device performance. Other reasons for the low performance can be summarized as follows [108]:

• • • • •

High temperatures may be necessary for the synthesis of the inorganic nanoparticles. The dispersion of the nanoaparticles in polymer matrix may be prevented. Reproducibility of the nanoparticles is a problem due to change in the physical and chemical properties from batch to batch. The organic ligand itself is an insulator which blocks the electron transport between the particles. The toxicity of the materials such as Cd used in the synthesis of inorganic nanoparticles.

Besides inorganic nanoparticles bulk inorganic semiconductors have also been used to fabricate hybrid solar cells in the bilayer configuration. Inorganic bulk semiconductor has been used either as a donor or an acceptor. The mostly studied bilayer heterojunction hybrid solar cells were based on silicon (Si)/organic heterojunctions. Si/P3HT heterojunction has been demonstrated to be a viable way for PV applications as a cheap and low temperature alternative to traditional silicon solar cells [109–112]. The PCE of these kinds of solar cells have been reported to be c. 10%. The main reason was that the charge separation and transport in the P3HT layer are much slower than that in silicon. The efficiency was further increased by replacing P3HT with PEDOT:PSS and employing Si/PEDOT:PSS heterojunctions in the device structure. Zielke et al. achieved a PCE of 17% using a PEDOT back cell concept which is the highest PCE reported on the bilayer heterojunction hybrid solar cells [112]. Most of the studies mentioned above focused on improving the PCE of either organic or hybrid solar cells. However, besides PCE, stability is another important issue. There are several factors affecting the stability. Exposure of the solar cells to oxygen and moisture is one of the most dominant degradation mechanism. Especially, organic materials are very sensitive to oxygen and moisture. Also, the top metal contacts such as Al and Ca are very sensitive to oxygen and can be easily oxidized if they are not protected. Two ways can be used to overcome these problems (1) encapsulation of the devices after production [113] and (2) inverting the device structure to use metal top electrodes which are less sensitive to oxygen and moisture [114–116]. The second way to improve the stabiliy with a novel device concept has been called inverted type hybrid solar cells. In a conventional bulk heterojunction organic solar cells the electrons are transported to the Al electrode whereas the holes are collected at the ITO electrodes. By inserting an ETL between the ITO and the photoactive layer and also a HTL between the top metal contact and the photoactive layer the direction of the flow of electrons and holes in the conventional solar cells can be inverted so that the electrons are transported to the ITO electrode whereas the holes are transported to the electrodes such as silver (Ag) and gold (Au) which are less sensitive to oxygen. Such a device is called an inverted type hybrid solar cell. The device configuration becomes ITO/ETL/Photoactive Layer/HTL/Au or Ag. TiO2, ZnO, CdS, In2S3, and ZnS have been used as ETLs in inverted type solar cells [117–123]. The highest PCE was achieved by inserting a neutral polymer interlayer of poly (2-ethyl-2-oxazoline) (PEOZ) between ZnO layer and the photoactive layer, the authors achieved a certified PCE of almost 10% [124]. This substantial increase upon addition of PEOZ layer was attributed to the significant reduction in workfunction and the improved morphology. DSSCs were first discovered by Michael Graetzel and Brian O’Reagan in 1991. Therefore, DSSCs are also referred to as Graetzel solar cells. In this cell design, there are three important parts. A thin layer of TiO2 is coated on top of a fluorine doped tin oxide (SnO2:F) which has a highly porous structure with a high surface area. After coating TiO2 is sintered to ensure the electrical contact between the particles and also to remove the organic and solvent residues remained during preparation. TiO2 absorbs light in the UV region. A dye is used for sensitization. TiO2 films are immersed into the dye solution and the dye is covalently bonded to the TiO2 surface. Another seperate glass consisting of a metal sheet of platinum is brought together and is filled with an electrolyte and later, device is sealed to prevent the leakage of the liquid electrolyte. The basic working principle of such a device is summarized as follows: 1. The dye on the TiO2 surface absorbs the incident light.

Solar Cells

649

2. The dye is excited from the ground state to the excited state. This results in the oxidation of the dye. S þ hγ → S 3. It injects an electron into the conduction band of the TiO2 and injected electrons are transported by TiO2 between its nanoparticles. S →Sþ þ e− ðTiO2 Þ 4. Regeneration of the dye is restored by an injection of an electron from the electrolyte. Sþ þ e− → S 5. The oxidized redox mediator, I3−, diffuses toward the counter electrode and then it is reduced to I − ions. I3 − þ 2e− → 3I − Although liquid electrolytes have been widely used in the most efficient DSSCs. They have some practical problems such as leakage and evaporation of solvent, photodegradation and solving the dye from the semiconductor surface, corrosion of the counter electrode. Quasi solid state electrodes, ionic liquids have also been investigated as alternatives to liquid electrolytes to solve these problems. Quasi solid state electrolyte is a molecular or nanomolecular aggregate system which possess high ionic conductivity whereas ionic liquids are salts in liquid state [125]. The highest PCE of liquid electrolyte-based DSSCs reported up to now has been 13%. A molecularly engineered porphyrin dye, coded as SM315 has been used as a sensitizer. The prototypical structure of a donor–π-bridge–acceptor both maximizes electrolyte compatibility and improves light-harvesting properties [126]. Although reasonable PCEs were achieved using liquid electrolyte-based DSSCs, the practical problems such as the leakage or evaporation of the electrolyte due to sealing problems or the sensitivity to the temperature. One of the ways to overcome this problem is the replacement of the liquid electrolyte with a solid or quasi solid hole transporter. A solid state DSSC is similar to the liquid-based DSSCs except the replacement of the electrolyte with a solid state counter part such as a p-type semiconductor. The most common approach to fabricate solid-state DSSCs is by using p-type semiconductors. These p-type semiconductors should fulfill the following requirements [127]: 1. Penetration into the pores of semiconductor electrode. 2. Deposition without dissolving the dye layer. 3. Transparency in the region where the dye absorbs light and if it absorbs light it must be as efficient as electron injection of the dye. The main difference between solid-state and liquid electrolyte DSSCs is the properties of the charge transport. In the solid state cell, the charge transport is electronic whereas when using liquid or polymer electrolyte, ionic transport takes place [128]. Initially inorganic p-type semiconductors such as CuI and CuSCN were used as hole transporters in DSSCs [129,130]. However, the difficulty of proper filling of the pores with these hole transporters lead to rather moderate efficiencies as compared to that of liquid electrolyte-based DSSCs. Initially, using a (2,2′,7,7′-tetrakis-(N,N-di-p-methoxyphenylamine)-9,9′-spirobifluorene or spiro-OMeTAD) molecule and by adding salts into the Spiro-OMETAD and adding silver ions to the dye, a PCE of 4% was reported [131]. The main success was attributed to the efficient pore filling by the spiro-OMETAD. The highest PCE of 7% was reported for solid state DSSCs employing PEDOT as HTL [132]. Highly transparent organized mesoporous TiO2 (OM-TiO2) was used. OM-TiO2 was prepared via sol–gel synthesis of TiO2 using a template of an amphiphilic graft copolymer that consisted of a poly(vinyl chloride) (PVC) backbone and poly(oxyethylene methacrylate) (POEM) side chains (PVC-g-POEM). This high efficiency was attributed to the high conductivity of PEDOT and also to the improved hole transporter-OM-TiO2 interface [132]. Polymeric gel electrolytes have also been applied in solid state DSSCs [133,134]. However, the PCEs were rather moderate as compared to liquid electrolyte-based DSSCs. During the last 3 years a new family of PV compounds “perovskites” have been the focus of attention. Such organic/inorganic hybrid solar cells based on ionic salts of organic compounds with lead halides exhibited rather high efficiencies. Perovskite ABX3 (X ¼ halogens) structure consists of organic components in cuboctahedral A site and inorganic components in octahedral B site and the chemistry of the organic and inorganic components can be tailored to tune the optical, electronic, magnetic, and mechanical properties of hybrid materials [135]. Initial devices were based on the replacement of the dye layer with a perovskite of methylammonium lead iodide (MAPbI3) CH3NH3PbI3. Liquid electrolyte was employed in the device configuration. Such a cells exhibited a PCE of 7% [135]. By employing a crystalline perovskite absorber (a mixed Halide perovskite absorber, CH3NH3PbI3–xClx) with intense visible to near-infrared absorptivity Snaith et al. demonstrated a device with a PCE of almost 11% in a single junction device under simulated full sunlight [136]. They achieved Vocs more than 1.1 V, despite the relatively narrow absorber band gap of 1.55 eV. Later, in a study using chemically tailored novel conjugated copolymers a PCE of almost 17% have been realized [137]. It has been demonstrated that the new hole selective layers with well wetting and electronic properties improve the device performance.

650

Solar Cells

Perovskite solar cells on highly conductive PEDOT:PSS substrates were investigated by Adam et al. PEDOT:PSS was deposited with dimethyl sulfoxide (DMSO) and Zonyl as additives. This process enables the fabrication of perovskite solar cells using PCBM as ETL with PCEs higher than 12%, low hysteresis and excellent operational stability [138]. Recently by replacing the perovskite of MAPbI3 with formamidinium lead iodide (FAPbI3) PCEs over 20% have been achieved [139]. The band gap of the latter allows broader absorption of the solar spectrum relative to the former. They reported a method for depositing high-quality FAPbI3 films, involving FAPbI3 crystallization by the direct intramolecular exchange of DMSO molecules intercalated in PbI2 with formamidinium iodide. This process produces FAPbI3 films with (111)-preferred crystallographic orientation, large-grained dense microstructures, and flat surfaces without residual PbI2 which in turn leads to PCEs over 20%. Organolead halide perovskites constitute a highly promising class of materials, but suffer from limited stability under ambient conditions without heavy and costly encapsulation [140]. Kaltenbrunner et al. reported on ultrathin (3 mm), highly flexible perovskite solar cells (see Fig. 4) with stabilized PCE of 12% and a power-per-weight as high as 23 W g−1. To facilitate airstable operation, they introduced a chromium oxide–chromium interlayer that effectively protected the metal top contacts from reactions with the perovskite [140].

4.15.4

Illustrative Example (Fabrication and Characterization of an Inverted Type Solar Cell)

In this section, we will examine a case study on the fabrication and characterization of an inverted type solar cell. Inverted type solar cells have been fabricated in the form of ITO/TiO2/Active Layer/Ag and ITO/TiO2/Active Layer/Au in our group. We have studied the effect of metal electrodes such as Ag and Au on the performance of inverted type solar cells. TiO2 was prepared following a sol–gel procedure. TiO2 precursor solution was prepared titanium (IV) isopropoxide (TTIP) precursor. Acetylacetone was added to TTIP dropwise. The mixture was stirred for 15 min and then diluted with ethanol in 1:10 ww ratio and stirred over night at room temperature. ITO coated substrates were used as substrates, glass sheets of 1.5 cm  1.5 cm, from Kintec Company, Honkong, were used with an ITO and sheet resistance o12 O cm−2. The ITO was patterned by etching with an acid mixture of HCl:HNO3:H2O (4.6:0.4:5) for 30 min. The part of the substrate, which forms the contact was covered with a scotch tape to prevent etching. The tape was removed after etching and the substrate was then cleaned using acetone and isopropanol in an ultrasonic bath. The blends for the active layer with 1:0.55 wt ratio was prepared by 12 mg of P3HT and 6.5 mg of PCBM in 1 mL of CB. TiO2 was spincast on precleaned ITO substrates using a spin coater as shown in Fig. 7. The TiO2 coated substrates were placed in an oven and sintered at 450°C for 30 min. Sintering procedure is performed to ensure the electrical contact between the particles and also to remove the unwanted residues due to sol–gel procedure. Fig. 8 shows the morphology of the TiO2 film. Fig. 8 indicates a compact TiO2 film in which there are no pores. The sol–gel procedure leads to morphology, which is in agreement with the literature. P3HT:PCBM active layer was spincast on TiO2 electrodes at 2000 rpm. The films were dried inside a glovebox and a temperature annealing was applied at 120°C for 3 min. PEDOT:PSS was diluted with isopropanol in 1:20 volume ratio. PEDOT:Isop

Fig. 7 Spin coater.

Solar Cells

651

25.0 nM

2.00 12.5 nM

0.0 nM 1.00

0 0

1.00

2.00 μM

Fig. 8 Morphology of the titanium dioxide (TiO2) film.

Fig. 9 Thermal metal evaporator.

solution was spincast onto P3HT:PCBM layer at 800 rpm. The films were dried inside the glovebox. Finally, 100 nm of silver (Ag) or gold (Au) were thermally evaporated as top electrode as shown in Fig. 9. The device characterization inside a glovebox are shown in Fig. 10. The devices were transferred into the glovebox in which N2 gas is flowing to prevent the interaction of the devices with ambient conditions. Current–voltage (I–V) characteristics of the solar cells employing Ag and Au as top metal electrodes are shown in Fig. 11(A) and (B), respectively.

Solar Cells

652

Fig. 10 Glovebox filled with nitrogen.

8 Dark Illumination

Dark illumination

6

0

−2

−4 VOC = 600 mV

−6

Current density (mA cm−2)

Current density (mA cm−2)

2

4 2 0 −2 VOC = 533 mV −4

JSC = 6.26 mA cm−2

−6

FF = 0.46 PCE = %1.53

JSC = 7.5 mA cm−2 FF = 0.39 PCE = %1.75

−8

−8 0.0 (A)

0.3 Voltage (V)

0.0

0.6 (B)

0.3 Voltage (V)

0.6

Fig. 11 I–V characteristics of (A) ITO/TiO2/P3HT:PCBM/Ag and (B) ITO/TiO2/P3HT:PCBM/Ag solar cells. ITO, indium tin oxide; P3HT, poly(3hexylthiophene); PCBM, [6,6]-phenyl-C61-butyric acid methylester; TiO2, titanium dioxide.

As can be seen from Fig. 11, inverted type solar cells employing Ag as metal top electrode exhibited a short circuit current density (Jsc) of 7.5 mA/cm2 and an open circuit voltage (Voc) of 600 mV, a FF of 0.39 was calculated which led to a PCE of 1.75% whereas inverted type solar cells employing Au as top metal electrode exhibited a Jsc of 6.26 mA/cm2, a Voc of 533 mV and a FF of 0.46 was calculated which led to a PCE of 1.53%. The solar cells employing Ag as top metal electrodes performed better than solar cells employing Au as top metal electrodes. This difference in the PCE is attributed to the changes in the energy level alignment and ohmic contacts between the photoactive layer and the metal electrodes may lead to higher Jsc and Voc facilitating better charge extraction. On the other hand, Ag is realized to be the most suitable top electrode, since its slow oxidation shifts its work function from about 4.3 to about 5 eV, favoring hole extraction. Also, It has no absorption in the visible range contrary to the evaporated Au layer, which has a slight absorption in the visible and a higher reflectivity [141,142]. A simple monochromatic efficiency is the incident photon to current efficiency (IPCE), which is the number of electrons measured under short circuit conditions, no applied bias, divided by the number of incident photons [6]. By means of IPCE measurements, the contribution of the species present in the device to the total photocurrent generation can be investigated. Fig. 12 shows the IPCE spectrum of inverted type solar cells in the form of ITO/TiO2/P3HT:PCBM/Ag.

Solar Cells

60

653

0.7 IPCE 0.6

50

IPCE (%)

0.4 30 0.3 20

Absorption of P3HT:PCBM

0.2

10

0 300

Absorption (au)

0.5 40

0.1

400

500 600 Wavelength (nm)

700

0.0 800

Fig. 12 Incident photon to current efficiency (IPCE) spectrum of inverted type solar cells in the form of ITO/TiO2/P3HT:PCBM/Ag and absorption spectrum of active layer of P3HT:PCBM. ITO, indium tin oxide; P3HT, poly(3-hexylthiophene); PCBM, [6,6]-phenyl-C61-butyric acid methylester; TiO2, titanium dioxide.

As can be seen from Fig. 12, IPCE spectrum device spans the spectral range over the wavelengths 300 and 800 nm which is consistent with the absorption spectrum of P3HT:PCBM. There is a slight red shift between the absorption of P3HT:PCBM and the IPCE spectrum of the inverted type solar cells which attributed to the intimate contact between TiO2 and the active layer. In summary, we have compared the PV performance of the inverted type devices employing Au and Ag as top metal electrodes. We have observed that the inverted type devices employing Ag as top metal electrode performed better. This better performance was attributed to the improved ohmic contact between the active layer and Ag as compared to Au and also the shift of Ag’s workfunction due to its slow oxidation and to the fact that Ag has no absorption in the visible in contrary to Au.

4.15.5

Future Directions

In recent years, solar cells showed promising progress toward more widespread usage all over the world. Although such a progress has been achieved the technology is not yet mature enough for the public customer use. Even though many people are aware of PVs solar cells are still expensive for them to afford especially for the household purposes. The scientists contributing to the history of solar cells all forsee the solar energy as the most important kind of energy which could solve the future energy problems. Scientists and engineers work hard together to bring this technology to where it deserves. The know-how born in research laboratories is being transferred to technology as a result of which new products are born. Since the first report and invention of silicon-based solar cells by Chapin et al. [143] there has been a tremendous interest and effort from both scientific and technological points of views which in turn led to the development, maturization and thereby the domination of silicon solar cells in the PV market. The same situation is also valid for other type of solar cells. The current solar cell industry is dominated by Si with nearly 90% of the market [144]. Polycrystalline silicon solar cells have the leading share of 53% which is followed by the amorphous silicon of 33%. Thin film technologies has a market share of 11%. The main reason behind this table is the fact that silicon technology is a very well studied, understood, and mature technology. Efficiency, cost, and stability are three important parameters for the PV market. Although silicon solar cells are efficient, their costs become an important issue since there are many cost-effective industrial steps which involve Si purification and high temperature processes in between Si-production to Si-wafer solar cell production that in turn is seen as a major drawback behind the household use of silicon solar cells. Under the following assumptions of 15% of PCE with 1000 W/m2 solar radiation and 5 h of daily solar radiation, it is estimated that a minimum of 30 m2 solar cells is necessary for a family consuming 20 kWh/day. This points out a high amount of Si need for such a family as compared to that of a computer [144], which adds up to the costs. On the other hand, there are some other material issues related to silicon. Silicon is abundant and nontoxic. However, its band gap is not ideal. According to Shockley–Queisser limit assuming a single p–n junction with a band gap of 1.34 eV (under AM 1.5 illumination) the maximum theoretical efficiency is around 33.7% [145]. For silicon with a band gap of 1.1 eV the theoretical limit is around 32% [146]. Silicon solar cells exhibit a PCE of c. 25%. The losses are mainly due to the practical reasons such as reflection losses and light hindrance due to the thin electrodes on the surface. CdTe and CIGS have been utilized as alternatives to silicon. Although the cost of thin film devices is rather lower than that of silicon solar cells the PCE of former is still lower as compared to that of the former. Also, the toxicity of the Cd is an undesired issue.

654

Solar Cells

Considering the points mentioned above a material problem arises. What kind of properties should a material bear to be the choice of material of the solar industry? Abundance, low cost, easy processing, nontoxicity, stability, high mobility, carrier longevity, band gap suitability, controllable conduction type, and resistivity are the main parameters that the material of choice should possess [144]. Multiple junction solar cells with multiple p–n junctions consisting of different semiconductors have also attracted attention since the theoretical limit of the PCE is the highest as compared to the other PV Technologies. According to the solar efficiency tables by Green et al. multi-junction solar cells with five junction cells bonded exhibit almost 39% of PCE as the leading technology [46]. However, depending on the theoretical studies the efficiency of these type solar cells can be further improved by redesigning the individual layers and by increasing the number of junctions, etc. Although the above mentioned technologies have already taken their places in the PV market, for practical and house type applications they are rather expensive. Cost effectivity and easy processablity of the so called third generation solar cells attracted very much attention during the last decade. As a result, organic/hyrid and DSSCs have been widely studied. Sumimoto Chemicals Japan has announced a certified PCE of 11% by incorporating a new infrared absorbing material. On the other hand, DSSCs exhibited a PCE of 12% [147]. Recently, perovskite solar cells employing perovskites as sensitizers in the form of ABX3(A¼ CH3NH3, B¼ Pb, Sn, and X ¼Cl, Br, I) have been the focus of attention since they are proven to be low cost, highly efficient, and processed at low temperatures. A PCE over 20% has been achieved recently [139]. Increase in efficiency in a considerably short time is counted as a breakthrough and innovation potential of perovskite solar cells let them compete with the first and second generation solar cells. If the challenging issues associated with their stability is solved they will have no obstacle in competing with the existing technologies in the PV market. In summary, cost and energy effective technologies will have the leading position in the PV market. It seems that the first generation solar cells suffer from high production costs whereas second generation solar cells suffer from lower efficiencies as compared to that of first generation solar cells. Third generation solar cells, especially, perovskite solar cells are rather promising. There may be two ways to be followed (1) reduction in the cost of first generation solar cells and increase in the efficiency of the second generation solar cells and improvement in the stability of perovskite solar cells through scientific and technological breakthroughs (2) novel materials to improve the design of the layers and the device characteristics of the existing PV technologies. The direction of these two routes will determine the future of PV market whether there will be affordable technologies available or existing PV technologies will be viable for only certain fields where money will not be an issue such as space applications.

4.15.6

Closing Remarks

In this chapter, different generations of solar cells, their working principles, advantages, and disadvantages have been discussed. Each generation has its own advantage and disadvantage. The main features of reduction of costs and increase of PCEs should be fulfilled by solar cells to be competitive with energy sources from fossil fuels. The first generation solar cells have high PCEs but they are rather expensive due to the complex fabrication procedures. The second generation solar cells exhibit lower PCEs as compared to the first one but they are less expensive. The high absorption coefficient of the materials used, vacuum or non-vacuum processing are seen as their advantages. The use of environmentally non-friendly and toxic materials are their disadvantages. Third generation solar cells are low cost and are easily processed. There is an intense interest in the third generation solar cells and the field is growing fast. The parameter space to choose from is large and simple and low cost processability attract very much attention. The scientific progress of the first and second generation solar cells seem to be saturated. The rest of the investigations are mostly based on engineering scales. The strategies to improve the efficiency of third generation solar cells to be competitive with first and second generation solar cells require a high degree of interdisciplinary research in macromolecular chemistry, supramolecular chemistry, physical chemistry, colloid chemistry, photophysics/photochemistry, device physics, nanostructural analysis, and thin film technology. There is great challenge and opportunity in this entire field of chemical sciences and more scientific and technological advancement is expected to come from such interdisciplinary efforts. For different kinds of third generation solar cells the following discussion holds 1. Organic solar cells exhibit at most PCE of c. 12%. However, it has been demonstrated by Scharber et al. using a tandem concept the solar cell performance can be improved further. The improvement in PCE seem to be a material and device architecture issue. 2. Hybrid solar cells using nanoparticles exhibit rather low efficiencies and it seems that without improving the nanoparticle synthesis routes it won’t be further increased. The PCE of hybrid solar cells employing Si/organic heterojunctions are comparable to that of second generation solar cells. Liquid electrolyte-based solar cells have high PCEs but they technologically suffer from leakage and evaporation of the electrolyte. Solid state DSSCs were realized to overcome these problems. However, they are not as efficient as the liquid-based DSSCs. 3. Among third generation solar cells perovskite solar cells have the highest PCE and they are rather comparable with the second generation solar cells. The only drawback behind their commercialization is their stability.

Solar Cells

655

Solar cells are widely used in space applications in which the price is not an issue. The dream of the researchers working in this field is their widespread use in all fields and also for household purposes.

References [1] Baños R, Manzano-Agugliaro F, Montoya FG, et al. Optimization methods applied to renewable and sustainable energy: a review. Renew Sustain Energy Rev 2011;15:1753–66. [2] Wu J, Lan Z, Lin J, et al. Electrolytes in dye-sensitized solar cells. Chem Rev 2015;115:2136–73. [3] Dincer I. Renewable energy and sustainable development: a crucial review. Renew Sustain Energy Rev 2000;4:157–75. [4] Sze SM, Ng KK, Colinge J-P, Colinge CA. Physics of semiconductor devices. New York, NY: Wiley; 2002. [5] Jordehi AR. Parameter estimation of solar photovoltaic (PV) cells: a review. Renew Sustain Energy Rev 2016;61:354–71. [6] Rn Rostalski J, Meissner D. Monochromatic versus solar efficiencies of organic solar cells. Sol Energy Mater Sol Cells 2000;61:87–95. [7] Kibria MT, Ahammed A, Sony SM, Hossain F. A review: comparative studies on different generation solar cells technology. In: International conference environmental aspects of Bangladesh; 2014. p. 51–3. [8] Contreras MA, Mansfield LM, Egaas B, et al. Wide bandgap Cu(In,Ga)Se2 solar cells with improved energy conversion efficiency. Prog Photovolt Res Appl 2007;15:659–76. [9] Mohammad Bagher A. Types of solar cells and application. Am J Opt Photonics 2015;3:94–113. [10] Jaeger K, Isabella O, Smets AHM, van Swaaij RACMM, Zeman M. Solar energy fundamentals, technology and applications. Netherlands: Delft University of Technology; 2014. p. 1–401. [11] Glunz CSW, Preu R, Biro D. Crystalline silicon solar cells. State-of-the-art and future developments. In: Sayigh A, editor. Comprehensive renewable energy. Amsterdam: Elsevier; 2012. p. 353–87. [12] Chapin DM, Fuller CS, Pearson GL. A new silicon p-n junction photocell for converting solar radiation into electrical power. J Appl Phys 1954;25:676–7. [13] Szlufcik J, Sivoththaman S, Nijs JF, Mertens RP, VanOverstraeten R. Low cost industrial technologies of crystalline silicon solar cells. Proc IEEE 1997;85:711–30. [14] Xiao S, Xu S. High-efficiency silicon solar cells – materials and devices physics. Crit Rev Solid State Mater Sci 2014;39:277–317. [15] Rahman MZ. Status of selective emitters for p type c-Si solar cells. Opt Photonics J 2012;2:129–34. [16] Saitoh T. 30 Years of progress in crystalline silicon solar cells. In: Proceedings of 3rd world congress on photovoltaic energy conversion 3; 2003. p. 23–8. [17] Okamoto S, Nishida M. 23.5% efficient silicon solar cell with rear micro contacts of c-Si/muc-Si: H heterostructure. In: 26th IEEE photovoltaic specialists conference (PVSC); 1997. p. 255–8. [18] Green MA, Zhao J, Wang A, Wenham SR. Progress and outlook for high-efficiency crystalline silicon solar cells. Sol Energy Mater Sol Cells 2001;65:9–16. [19] Ye X, Zou S, Chen K, et al. 18.45%-Efficient multi-crystalline silicon solar cells with novel nanoscale pseudo-pyramid texture. Adv Funct Mater 2014;24:6708–16. [20] Macdonald DH, Cuevas A, Kerr MJ, et al. Texturing industrial multicrystalline silicon solar cells. Sol Energy 2004;76:277–83. [21] Saga T. Advances in crystalline silicon solar cell technology for industrial mass production. NPG Asia Mater 2010;2:96–102. [22] Schultz O, Glunz SW, Willeke GP. Multicrystalline silicon solar cells exceeding 20% efficiency. Prog Photovolt Res Appl 2004;12:553–8. [23] Singh VK, Giribabu L. Photovoltaic – a review of the solar cell generation. J Innov Electron Commun 2013;3:46–55. [24] Sopori B. Impurities and defects in photovoltaic Si devices: a review. In: NREL conference paper; 1999. p. 1–13. [25] Yadav P, Pandey K, Tripathi B, Kumar M. Investigation of interface limited charge extraction and recombination in polycrystalline silicon solar cell: using DC and AC characterization techniques. Sol Energy 2015;116:293–302. [26] Chittik RC, Alexander JH, Sterling HF. The preparation and properties of amorphous silicon. J Electrochem Soc 1969;116:77–81. [27] Carlson DE, Wronski CR. Amorphous silicon solar cell. Appl Phys Lett 1976;28:671–3. [28] Wronski CR, Carlson DE, Daniel RE, Triano AR. Electrical properties of a-Si solar cells. In: 1976 international electron devices meeting; 1976. p. 75–8. [29] Carlson DE, Wronski CR. Amorphous silicon solar cells. IEEE Trans Electron Devices 1977;24:449–53. [30] Catalano A, D’Aiello RV, Dresner J, et al., Attainment of 10% conversion efficiency in amorphous silicon solar cells. In: Record of the IEEE photovoltaic specialists conference 1982; pp. 1421–22. [31] Staebler DL, Wronski CR. Reversible conductivity changes in discharge-produced amorphous Si. Appl Phys Lett 1977;31:292–4. [32] Matsui T, Sai H, Suezaki T, et al., Development of highly stable and efficient amorphous silicon based solar cells. In: 28th European photovoltaic solar energy conference and exhibition development proceedings; 2013. p. 2213–7. [33] Guha S. On light-induced effect in amorphous hydrogenated silicon. J Appl Phys 1981;52:859–64. [34] Yang J, Lord K, Guha S, Ovshinsky SR. Amorphous silicon alloy solar cells near the threshold of amorphous-to-microcrystalline transition. MRS Online Proc 2000;609: A15.4. [35] Ferlauto AS, Koval RJ, Wronski CR, Collins RW. Extended phase diagrams for guiding plasma-enhanced chemical vapor deposition of silicon thin films for photovoltaics applications. Appl Phys Lett 2002;80:2666–8. [36] Veprˇek S, Marecˇek V. The preparation of thin layers of Ge and Si by chemical hydrogen plasma transport. Solid State Electron 1968;11:683–4. [37] Meier J, Flückiger R, Keppner H, Shah A. Complete microcrystalline p-i-n solar cell – crystalline or amorphous cell behavior. Appl Phys Lett 1994;65:860–2. [38] Poruba A, Fejfar A, Remes ̌ Z, et al. Optical absorption and light scattering in microcrystalline silicon thin films and solar cells. J Appl Phys 2000;88:148–60. [39] Meier J, Torres P, Platz R, et al. On the way towards high efficiency thin film silicon solar cells by the “Micromorph” concept. MRS Proc 1996;420:3–7. [40] Sai H, Maejima K, Matsui T, et al. High-efficiency microcrystalline silicon solar cells on honeycomb textured substrates grown with high-rate VHF plasma-enhanced chemical vapor deposition. Jpn J Appl Phys 2015;54:8S1. [41] Taylor AA, Major JD, Kartopu G, et al. A comparative study of microstructural stability and sulphur diffusion in CdS/CdTe photovoltaic devices. Sol Energy Mater Sol Cells 2015;141:341–9. [42] Liyanage WPR, Wilson JS, Kinzel EC, Durant BK, Nath M. Fabrication of CdTe nanorod arrays over large area through patterned electrodeposition for efficient solar energy conversion. Sol Energy Mater Sol Cells 2015;133:260–7. [43] Bonnet D, Rabenhorst H. New results on the development of a thin film p-CdTe/n-CdS heterojunction solar cell. In: Proceedings of 9th IEEE photovoltaic specialist conference, New York; 1972. p. 129–31. [44] Ferekides C, Britt J, Ma Y, Killian L. High efficiency CdTe solar cells by close spaced sublimation. In: Record of the IEEE photovoltaic specialists conference 1993; 389–393. [45] Romeo N, Bosio A, Canevari V, Podestà A. Recent progress on CdTe/CdS thin film solar cells. Sol Energy 2004;77:795–801. [46] Green MA, Emery K, Hishikawa Y, Warta W, Dunlop ED. Solar cell efficiency tables (version 48). Prog Photovolt Res Appl 2016;24:905–13. [47] Romeo A, Terheggen M, Abou-Ras D, et al. Development of thin-film Cu(In,Ga)Se2 and CdTe solar cells. Prog Photovolt Res Appl 2004;12:93–111. [48] Contreras M, Tuttle J, Du D, et al. Graded band-gap Cu(In,Ga)Se2 thin-film solar cell absorber with enhanced open-circuit voltage. Appl Phys Lett 1993;63:1824–6. [49] Solomon I, Equer B, Helm P. Thin film cells on electrodeposited CuInSe2. In: Photovoltaic solar energy conference II; 1988. p. 1023–725.

656

Solar Cells

[50] Nakada T, Mizutani M. 18% efficiency Cd-free Cu(In, Ga)Se2 thin-film solar cells fabricated using chemical bath deposition (CBD)-ZnS buffer layers. Jpn J Appl Phys, Part 2 Lett 2002;41:L165–7. [51] Farunhofer Institute for Solar Energy Systems. Photovoltaics report; 2013: 1–43. [52] Sariciftci NS, Smilowitz L, Heeger AJ, Wudl F. Photoinduced electron transfer from a conducting polymer to buckminsterfullerene. Science 1992;258:1474–6. [53] Yu G, Heeger AJ. Charge separation and photovoltaic conversion in polymer composites with internal donor/acceptor heterojunctions. J Appl Phys 1995;78:4510–5. [54] Hoppe H, Sariciftci NS, Meissner D. Optical constants of conjugated polymer/fullerene based bulk-heterojunction organic solar cells. Sol Cells 2002;385:233–40. [55] Roncali J. Synthetic principles for bandgap control in linear π-conjugated systems. Chem Rev 1997;97:173–206. [56] Hoppe H, Sariciftci N. Organic solar cells: an overview. J Mater Res 2004;19:1924–45. [57] Heeger AJ. Semiconducting and metallic polymers: the fourth generation of polymeric materials. Curr Appl Phys 2001;1:247–67. [58] Wudl F. The chemical properties of buckminsterfullerene (C60) and the birth and infancy of fulleroids. Acc Chem Res 1992;25:157–61. [59] Rowell MW, Topinka MA, McGehee MD, et al. Organic solar cells with carbon nanotube network electrodes. Appl Phys Lett 2006;88:123109–19. [60] Nunzi J-M. Organic photovoltaic materials and devices. Comptes Rendus Phys 2002;3:523–42. [61] Mozer AJ, Sariciftci NS. Conjugated polymer photovoltaic devices and materials. Comptes Rendus Chim 2006;9:568–77. [62] Hiramoto M, Fujiwara H, Yokoyama M. Three-layered organic solar cell with a photoactive interlayer of codeposited pigments. Appl Phys Lett 1991;58:1062–4. [63] Parker ID. Carrier tunneling and device characteristics in polymer light-emitting diodes. J Appl Phys 1994;75:1656–66. [64] Brabec CJ, Cravino A, Meissner D, et al. Origin of the open circuit voltage of plastic solar cells. Adv Funct Mater 2001;11:374–80. [65] Scharber MC, Mühlbacher D, Koppe M, et al. Design rules for donors in bulk-heterojunction solar cells – towards 10% energy-conversion efficiency. Adv Mater 2006;18:789–94. [66] Mola GT, Abera N. Correlation between LUMO offset of donor/acceptor molecules to an open circuit voltage in bulk heterojunction solar cell. Phys B Condens Matter 2014;445:56–9. [67] Malliaras GG, Salem JR, Brock PJ, Scott JC. Photovoltaic measurement of the built-in potential in organic light emitting diodes and photodiodes. J Appl Phys 1998;84:1583–7. [68] Liu J, Shi Y, Yang Y. Solvation-induced morphology effects on the performance of polymer-based photovoltaic devices. Adv Funct Mater 2001;11:420–4. [69] van Duren JKJ, Loos J, Morrissey F, et al. In-situ compositional and structural analysis of plastic solar cells. Adv Funct Mater 2002;12:665–9. [70] Bulle-Lieuwma CWT, van Gennip WJH, van Duren JKJ, et al. Characterization of polymer solar cells by TOF-SIMS depth profiling. Appl Surf Sci 2003;203–204:547–50. [71] Wu CC, Wu CI, Sturm JC, Kahn A. Surface modification of indium tin oxide by plasma treatment: an effective method to improve the efficiency, brightness, and reliability of organic light emitting devices. Appl Phys Lett 1997;70:1348–50. [72] Sugiyama K, Ishii H, Ouchi Y, Seki K. Dependence of indium–tin–oxide work function on surface cleaning method as studied by ultraviolet and X-ray photoemission spectroscopies. J Appl Phys 2000;87:295–8. [73] Scott JC, Carter SA, Karg S, Angelopoulos M. Polymeric anodes for organic light-emitting diodes. Synth Met 1997;85:1197–200. [74] Brown T, Kim J, Friend R, et al. Built-in field electroabsorption spectroscopy of polymer light- emitting diodes incorporating a doped poly(3,4-ethylene dioxythiophene) hole injection layer. Appl Phys Lett 1999;75:1679–81. [75] Soci C, Hwang IW, Moses D, et al. Photoconductivity of a low-bandgap conjugated polymer. Adv Funct Mater 2007;17:632–6. [76] Campos LM, Tontcheva A, Günes S, et al. Supporting information extended photocurrent spectrum of a low-bandgap polymer in a bulk heterojunction solar cells. Chem Mater 2005;17:1–12. [77] Perzon E, Wang X, Admassie S, Inganäs O, Andersson MR. An alternating low band-gap polyfluorene for optoelectronic devices. Polymer (Guildf) 2006;47:4261–8. [78] Cravino A, Loi MA, Scharber MC, et al. Spectroscopic properties of Pedotehiitn, a novel soluble low band-gap conjugated polymer. Synth Met 2003;137:1435–6. [79] Wienk MM, Struijk MP, Janssen RAJ. Low band gap polymer bulk heterojunction solar cells. Chem Phys Lett 2006;422:488–91. [80] Bundgaard E, Krebs FC. Low-band-gap conjugated polymers based on thiophene, benzothiadiazole, and benzobis(thiadiazole). Macromolecules 2006;39:2823–31. [81] Bundgaard E, Krebs FC. Large-area photovoltaics based on low band gap copolymers of thiophene and benzothiadiazole or benzo-bis(thiadiazole). Sol Energy Mater Sol Cells 2007;91:1019–25. [82] Winder C. Sensitization of low bandgap polymer bulk heterojunction solar cells. Thin Solid Films 2002;403–404:373–9. [83] Moule AJ, Bonekamp JB, Meerholz K. The effect of active layer thickness and composition on the performance of bulk-heterojunction solar cells. J Appl Phys 2006;100:94503–14. [84] Gupta D, Mukhopadhyay S, Narayan KS. Fill factor in organic solar cells. Sol Energy Mater Sol Cells 2010;94:1309–13. [85] Kim MS, Kim BG, Kim J. Effective variables to control the fill factor of organic photovoltaic cells. ACS Appl Mater Interfaces 2009;1:1264–9. [86] Barrau S, Andersson V, Zhang F, et al. Nanomorphology of bulk heterojunction organic solar cells in 2D and 3D correlated to photovoltaic performance. Macromolecules 2009;42:4646–50. [87] Nelson J, Kwiatkowski JJ, Kirkpatrick J, Frost JM. Modeling charge transport in organic photovoltaic materials. Acc Chem Res 2009;42:1768–78. [88] Shaheen S, Brabec CJ, Sariciftci NS. 2.5% efficient organic solar cells. Appl Phys Lett 2001;78:841–3. [89] Padinger F, Rittberger RS, Sariciftci NS, et al. Effects of postproduction treatment on plastic solar cells. Adv Funct Mater 2003;13:85–8. [90] Kim JY, Kim SH, Lee HH, et al. New architecture for high-efficiency polymer photovoltaic cells using solution-based titanium oxide as an optical spacer. Adv Mater 2006;18:572–6. [91] Blouin N, Michaud A, Gendron D, et al. Toward a rational design of poly (2,7-carbozole) derivatives for solar cells. J Am Chem Soc 2008;130:732–42. [92] Park SH, Roy A, Beaupre S, et al. Bulk heterojunction solar cells with internal quantum efficiency approaching 100%. Nat Photonics 2009;3:297–303. [93] Ng A. Enhanced performance of PTB7/C71 solar cells via different morphologies of gold nanoparticles. ACS Appl Mater Interfaces 2014;6:20676–84. [94] Dou L, You J, Yang J, et al. Tandem solar cells featuring a spectrally matched low band gap polymer. Nat Photonics 2012;6:180–5. [95] Tayebeh Ameri CL, Dennler G, Brabec CJ. Organic tandem solar cells: a review. Energy Environ Sci 2009;2:347–63. [96] Dharmadasa IM. Third generation multi-layer tandem solar cells for achieving high conversion efficiencies. Sol Energy Mater Sol Cells 2005;85:293–300. [97] Hiramoto M, Suezaki M, Yokoyama M. Effect of thin gold interstitial layer on the photovoltaic properties of tandem organic solar cell. Chem Lett 1990;19:327–30. [98] Yakimov A, Forrest SR. High photovoltage multiple-heterojunction organic solar cells incorporating interfacial metallic nanoclusters. Appl Phys Lett 2002;80:1667–9. [99] Zhou H, Zhang Y, Mai CK, et al. Polymer homo-tandem solar cells with best efficiency of 11.3%. Adv Mater 2015;27:1767–73. [100] Dennler G, Scharber MC, Ameri T, et al. Design rules for donors in bulk heterojunction tandem solar cells towards 15% energy conversion efficiency. Adv Mater 2008;20:579–83. [101] Ren S, Chang L-Y, Lim S-K, et al. Inorganic-organic hybrid solar cell: bridging quantum dots to conjugated polymer nanowires. Nano Lett 2011;11:3998–4002. [102] Chandrasekaran J, Nithyaprakash D, Ajjan KB, et al. Hybrid solar cell based on blending of organic and inorganic materials – an overview. Renew Sustain Energy Rev 2011;15:1228–38. [103] Dayal S, Kopidakis N, Olson DC, Ginley DS, Rumbles G. Photovoltaic devices with a low band gap polymer and CdSe nanostructures exceeding 3% efficiency. Nano Lett 2010;10:239–42. [104] Wang L, Liu Y, Jiang X, Qin D, Cao Y. Enhancement of photovoltaic characteristics using a suitable solvent in hybrid polymer/multiarmed CdS nanorods solar cells. J Phys Chem C 2007;111:9538–42. [105] Jiang X, Chen F, Weiming Q, et al. Effects of molecular interface modification in CdS/polymer hybrid bulk heterojunction solar cells. Sol Energy Mater Sol Cells 2010;94:2223–9.

Solar Cells

[106] [107] [108] [109] [110] [111] [112] [113] [114] [115] [116] [117] [118] [119] [120] [121] [122] [123] [124] [125] [126] [127] [128] [129] [130] [131] [132] [133] [134] [135] [136] [137] [138] [139] [140] [141] [142] [143] [144] [145] [146] [147]

657

Arici E, Sariciftci NS, Meissner D. Hybrid solar cells based on nanoparticles of CuInS2 in organic matrices. Adv Funct Mater 2003;13:165–70. Arici E, Hoppe H, Schäffler F, et al. Hybrid solar cells based on inorganic nanoclusters and conjugated polymers. Thin Solid Films 2004;451–452:612–8. Gao F, Ren S, Wang J. The renaissance of hybrid solar cells: progresses, challenges, and perspectives. Energy Environ Sci 2013;6:2020–40. Avasthi S, Lee S, Loo YL, Sturm JC. Role of majority and minority carrier barriers silicon/organic hybrid heterojunction solar cells. Adv Mater 2011;23:5762–6. Davenas J, Dkhil SB, Cornu D, Rybak A. Silicon nanowire/P3HT hybrid solar cells: effect of the electron localization at wire diameters. Energy Proc 2012;31:136–43. Sang Y, Liu A, Liu W, Kang D. Investigation of P3HT/n-Si heterojunction using surface photovoltage spectroscopy. Vacuum 2012;86:2158–61. Zielke D, Niehaves C, Lövenich W, et al. Organic-silicon solar cells exceeding 20% efficiency. Energy Proc 2015;77:331–9. Dennler G, Lungenschmied C, Neugebauer H, et al. A new encapsulation solution for flexible organic solar cells. Thin Solid Films 2006;511–512:349–53. Waldauf C, Morana M, Denk P, et al. Highly efficient inverted organic photovoltaics using solution based titanium oxide as electron selective contact. Appl Phys Lett 2006;89:1–4. Li C-Y, Wen T-C, Lee T-H, et al. An inverted polymer photovoltaic cell with increased air stability obtained by employing novel hole/electron collecting layers. J Mater Chem 2009;19:1643–7. Peng R, Yang F, Ouyang X, et al. Enhanced photovoltaic performance of inverted polymer solar cells by tuning the structures of titanium dioxide. Thin Solid Films 2013;545:424–8. Yavuz N, Yuksel SA, Karsli A, Gunes S. Inverted structure hybrid solar cells using CdS thin films. Sol Energy Mater Sol Cells 2013;116:224–30. Yuksel SA, Ongul F, Bozar S, et al. Improvement of photovoltaic performance and stability of AnE-PV:PCBM based organic solar cells using solution processed inverted geometry. Vacuum 2015;122:161–7. Ongul F, Ulutas U, Yuksel SA, Yesilkaya SS, Gunes S. Influences of annealing temperature and thickness on ZnS buffer layers for inverted hybrid solar cells. Synth Met 2016;220:1–7. Zhu JJ, Xu ZQ, Fan GQ, et al. Inverted polymer solar cells with atomic layer deposited CdS film as an electron collection layer. Org Electron Phys, Mater Appl 2011;12:2151–8. Alvarado-Tenorio G, Cortina-Marrero HJ, Nicho ME, Márquez Aguilar PA, Hu H. Improvement of photovoltaic performance of inverted hybrid solar cells by adding single-wall carbon nanotubes in poly(3-hexylthiophene). Mater Sci Semicond Process 2016;56:37–42. Cortina-Marrero HJ, Nair PK, Hu H. Conductive carbon paint as an anode buffer layer in inverted CdS/poly(3-hexylthiophene) solar cells. Sol Energy 2013;98:196–202. Aslan F, Adam G, Stadler P, et al. Sol–gel derived In2S3 buffer layers for inverted organic photovoltaic cells. Sol Energy 2014;108:230–7. Nam S, Seo J, Woo S, et al. Inverted polymer fullerene solar cells exceeding 10% efficiency with poly(2-ethyl-2-oxazoline) nanodots on electron-collecting buffer layers. Nat Commun 2015;6:1–9. Wang Y. Recent research progress on polymer electrolytes for dye-sensitized solar cells. Sol Energy Mater Sol Cells 2009;93:1167–75. Mathew S, Yella A, Gao P, et al. Dye-sensitized solar cells with 13% efficiency achieved through the molecular engineering of porphyrin sensitizers. Nat Chem 2014;6:242–7. Li B, Wang L, Kang B, Wang P, Qiu Y. Review of recent progress in solid-state dye-sensitized solar cells. Sol Energy Mater Sol Cells 2006;90:549–73. Yun S, Freitas JN, Nogueira AF, et al. Dye-sensitized solar cells employing polymers. Prog Polym Sci 2015;59:1–40. Tennakone K, Perera VPS, Kottegoda IRM, Kumara G. Dye-sensitized solid state photovoltaic cell based on composite zinc oxide tin (IV) oxide films. J Phys D-Appl Phys 1999;32:374–9. O’Regan B, Schwartz DT. Efficient dye-sensitized charge separation in a wide-band-gap p-n heterojunction. J Appl Phys 1996;80:4749–54. Schmidt-Mende L, Grätzel M. TiO2 pore-filling and its effect on the efficiency of solid-state dye-sensitized solar cells. Thin Solid Films 2006;500:296–301. Kim J, Koh JK, Kim B, et al. Enhanced performance of I2-free solid-state dye-sensitized solar cells with conductive polymer up to 6.8%. Adv Funct Mater 2011;21:4633–9. Cao F, Oskam G, Searson PC. A solid state, dye sensitized photoelectrochemical cell. J Phys Chem 1995;99:17071–3. Wang P, Zakeeruddin SM, Moser JE, Humphry-Baker R, Graetzel M. A solvent-free, SeCN-/(SeCN) based ionic liquid electrolyte for high-efficiency dye-sensitized nanocrystalline solar cells. J Am Chem Soc 2004;126:7164–5. Im J-H, Lee C-R, Lee J-W, Park S-W, Park N-G. 6.5% efficient perovskite quantum-dot-sensitized solar cell. Nanoscale 2011;3:4088–93. Lee MM, Teuscher J, Miyasaka T, Murakami TN, Snaith HJ. Efficient hybrid solar cells based on meso-superstructured organometal halide perovskites. Science 2012;338:643–7. Xue Q, Chen G, Liu M, et al. Improving film formation and photovoltage of highly efficient inverted-type perovskite solar cells through the incorporation of new polymeric hole selective layers. Adv Energy Mater 2016;6:1–9. Adam G, Kaltenbrunner M, Głowacki ED, et al. Solution processed perovskite solar cells using highly conductive PEDOT:PSS interfacial layer. Sol Energy Mater Sol Cells 2016;157:318–25. Yang WS, Noh JH, Jeon NJ, et al. High-performance photovoltaic perovskite layers fabricated through intramolecular exchange. Science 2015;348:1234–7. Kaltenbrunner M, Adam G, Głowacki ED, et al. Flexible high power-per-weight perovskite solar cells with chromium oxide–metal contacts for improved stability in air. Nat Mater 2015;14:1032–9. Lattante S. Electron and hole transport layers: their use in inverted bulk heterojunction polymer solar cells. Electronics 2014;3:132–64. Chen D, Zhang C, Wang Z, et al. Performance comparison of conventional and inverted organic bulk heterojunction solar cells from optical and electrical aspects. IEEE Trans Electron Devices 2013;60:451–7. Chapin DM, Fuller CS, Pearson GL. A new silicon p-n junction photocell for converting solar radiation into electrical power. J Appl Phys 1954;25:676–7. Tao M. Inorganic photovoltaic solar cells: silicon and beyond. Electrochem Soc Interface 2008;17:30–5. Rühle S. Tabulated values of the Shockley–Queisser limit for single junction solar cells. Sol Energy 2016;130:139–47. Shockley W, Queisser HJ. Detailed balance limit of efficiency of P-N junction solar cells. J Appl Phys 1961;32:510–9. Yella A, Lee HW, Tsao HN, Yi CY, Chandiran AK. Porphyrin-sensitized solar cells with cobalt (II/III)-based redox electrolyte exceed 12 percent efficiency. Science 2011;334:629–34.

Further Reading Deng X, Schiff EA. Amorphous silicon-based solar cells. In: Luque A, Hegedus S, editors. Handbook of photovoltaic science and engineering. Chichester: John Wiley & Sons; 2003. p. 505–65. Geens W, Aernouts T, Poortmans J, Hadziioannou G. Organic co-evaporated films of a PPV-pentamer and C60: model systems for donor/acceptor polymer blends. Thin Solid Films 2002;403–404:438–43. Han G, Zhang S, Boix PB, Wong LH, Lien SY. Towards high efficiency thin film solar cells. Prog Mater Sci 2017;87:246–91. Lee YJ, Kim BS, Ifitiquar SM, Park C, Yi Y. Silicon solar cells: past, present and future. J Korean Phys Soc 2014;65:355–61. Li Z, Zhang W, Meng X, et al. High performance all-polymer solar cells by synergistic effects of fine-tuned crystallinity and solvent annealing. J Am Chem Soc 2016;138:10935–44.

658

Solar Cells

Nelson J. The physics of solar cells. London: Imperial College Press; 2003. Placzek-Popko E. Top PV market solar cells 2016. Opto-Electron Rev 2017;25:55–64. Shah AV, Schade H, Vanecek M, et al. Thin-film silicon solar cell technology. Prog Photovolt 2004;12:113–42. Sharber MC, Sariciftci NS. Efficiency of bulk heterojunction solar cells. Prog Polym Sci 2013;38:1929. Sharma S, Siwach B, Ghoshal SK, Mohan D. Dye sensitized solar cells: from genesis to recent drifts. Renew Sustain Energy Rev 2017;70:529–37. Spanggaard H, Krebs FC. A brief history of the development of organic and polymeric photovoltaics. Sol Energy Mater Sol Cells 2004;83:125–46. Sun SS, Sariciftci NS. Organic photovoltaics: mechanisms, materials and devices. Boca Raton, FL: CRC Press; 2005. Tang Q, Zhang H, He B, Yang P. An all-weather solar cell that can harvest energy from sunlight and rain. Nano Energy 2016;30:818–24. Wang Q, Soltani-Kordshuli F, Eslamian M. Progress in emerging solution-processed thin film solar cells-part I: polymer solar cells. Renew Sustain Energy Rev 2016;56:347–61. White MS, Sariciftci NS. Nanostructured organic bulk heterojunction solar cells. In: Kalyansundaram K, Graetzel M, editors. Book chapter in nanotechnology for light energy conversion; 2013. p. 1–34. Würfel P. Physics of solar cells, from principles to new concepts. Weinheim, Germany: Wiley-VCH; 2008. Yoshikawa K, Yoshida W, Irie T, Kawasaki H, Yamamoto K. Exceeding conversion efficiency of 26% by heterojunction interdigitated back contact solar cell with thin film Si technology. Sol Energy Mater Sol Cells 2017; doi:10.1016/j.solmat.2017.06.024. Zhao W, Qian D, Zhang S, et al. Fullerene-free polymer solar cells with over 11% efficiency and excellent thermal stability. Adv Mater 2016;28:4734–9.

Relevant Websites http://news.energysage.com/what-are-the-most-efficient-solar-panels-on-the-market/ Energy sage. http://spectrum.ieee.org/energywise/energy/renewables/efficiency-of-solar-cells-continues-to-climb IEEE Spectrum. http://www.jku.at/ipc/content/e175559/e175566 JKU. http://www.jku.at/ipc/content/e175559/e175980 JKU. http://www.jku.at/ipc/content/e175559/e175981 JKU. http://science.sciencemag.org/content/347/6221/522.full Science. https://www.sciencealert.com/researchers-have-broken-the-record-for-solar-panel-efficiency-again Science alert. https://www.technologyreview.com/s/603497/10-breakthrough-technologies-2017-hot-solar-cells/ Technology Review. http://onlinelibrary.wiley.com/doi/10.1002/pip.2855/abstract Wiley Online Library.

4.16 Solar Ponds Ibrahim Dincer and Arda Yapicioglu, University of Ontario Institute of Technology, Oshawa, ON, Canada r 2018 Elsevier Inc. All rights reserved.

4.16.1 4.16.2 4.16.3 4.16.3.1 4.16.3.1.1 4.16.3.1.2 4.16.3.1.3 4.16.3.1.4 4.16.4 4.16.4.1 4.16.4.1.1 4.16.4.1.1.1 4.16.4.1.1.2 4.16.4.1.1.3 4.16.4.1.1.4 4.16.4.1.1.5 4.16.4.1.1.6 4.16.4.1.1.7 4.16.4.2 4.16.4.3 4.16.4.3.1 4.16.4.4 4.16.4.5 4.16.4.5.1 4.16.4.6 4.16.5 4.16.5.1 4.16.5.2 4.16.5.3 4.16.6 4.16.6.1 4.16.6.2 4.16.6.2.1 4.16.6.2.2 4.16.6.2.3 4.16.6.2.4 4.16.6.2.5 4.16.6.2.6 4.16.6.2.7 4.16.6.2.8 4.16.7 4.16.7.1 4.16.7.2 4.16.7.2.1 4.16.7.2.2 4.16.7.2.3 4.16.7.2.4 4.16.7.2.5 4.16.7.2.6 4.16.7.2.7 4.16.7.2.8 4.16.8 4.16.9

Introduction Historical Background Solar Ponds Important Parameters Temperature Salinity Transparency Soil Classification of Solar Ponds Salt Gradient Solar Ponds Experimental setup of a salinity solar pond at Cukurova University Experimental unit Data acquisition Data analysis Temperatures Brine density gradient Energy flows, efficiencies and losses Exergy flows, efficiencies and losses Partitioned Solar Ponds Viscosity Stabilized Solar Ponds Experimental setup of a viscosity stabilized solar pond Membrane Stratified Solar Ponds Saturated Solar Ponds Experimental setup of a saturated solar pond Shallow Solar Ponds Solar Pond Applications Thermal Applications Power Generation Desalination Thermodynamic Analyses of Solar Ponds Energy Analysis Energy Efficiency Calculations for the Upper Convective Zone Energy efficiency calculations for the nonconvective zone Energy efficiency calculations for the heat storage zone Results of energy analysis Exergy analysis Exergy analysis for UCZ Exergy analysis for NCZ Exergy analysis for HSZ Results of exergy analysis Case Studies on Solar Ponds Case Study 1: Investigation of Turbidity Effect on Exergetic Performance of Solar Ponds Case Study 2: Performance Assessment of a Solar Pond With and Without Shading Effect Shading area analysis Shading area for the UCZ Shading area for the NCZ Shading area for the LCZ Energy analysis Upper convective zone (UCZ) Nonconvective zone (NCZ) Lower convective zone (LCZ) Future Directions Closing Remarks

Comprehensive Energy Systems, Volume 4

doi:10.1016/B978-0-12-809597-3.00427-2

660 661 662 663 663 663 664 664 664 665 665 665 666 666 668 668 668 670 671 671 671 672 672 673 673 674 674 674 674 675 675 675 676 677 677 678 678 679 679 680 680 680 685 686 687 687 687 687 687 688 688 689 690

659

660

Solar Ponds

References Further Reading Relevant Websites

Nomenclature

690 691 691

L LCZ m N NCZ Q r T UCZ X V

Thickness of the inner zones (m) Lower convective zone Mass Number of collectors Nonconvective zone Heat (J) Inner radius Temperature (1C) Upper convective zone Thickness of inner zones (m) Volume

Greek Letters Z Energy efficiency Exergy (J) Ex δ Thickness where long-wave solar energy is absorbed (m) b Incident beam entering rate into water

y r DS Dx DEx c

Angle (rad) Density (kg/m3) Entropy (J/ Kmol) Thickness of horizontal layers (m) Stored exergy (J) Exergy efficiency

Subscripts a dest dw g i in m net out

r rec s st surr sw sys up w

Refraction Recovered Sun Heat stored inner zones of the pond Surrounding Side wall System Just above zone Fresh water

Surface area (m2) Specific heat (kJ/kgK) Total solar energy reaching to the pond (MJ/m2) Absorbed energy fraction at a region of δthickness Flat plate collector Solar radiation ratio Heat storage zone Integrated solar pond Thermal conductivity (W/m K )

A C E F FPC h HSZ ISP k

4.16.1

Ambient air Destruction Down wall Gained Incident Energy input Mean Net irradiation Energy output

Introduction

As a known fact, solar radiation is ready for use all around the world and it is considered as a perfect renewable energy resource replacement for depleting fossil fuel sources. Solar ponds offer an alternative way to collect and store solar energy, which can be used to supply thermal energy for various applications [1], such as refrigeration, drying, power generation, and space heating. Thermal energy storage is labeled as an important technique for storing energy. Regarding these properties solar ponds seem to have a considerable potential in collecting and storing solar energy. The efficiency of a system can be determined by investigating its manufacturing and maintenance costs and its thermal energy storage capacity [2]. Recently solar ponds have been receiving a lot of attention, many theoretical and experimental studies have been conveyed and some are selected and reviewed in this chapter. Regarding the heat transfer occurring in a solar pond in most of the cases convection occurs at or near the top of the pond, which shows that it is partially transparent to solar radiation. In between many different convection suppressing methods the salt gradient seems to be receiving the most attention when it comes to the experimental setups used for research purposes [2]. As shown in Fig. 1, a salt gradient solar pond is a body of water that has three regions, starting from the bottom lower zone, gradient zone, and surface zone. A homogeneous layer of low-salinity water makes up the surface zone. Where, the gradient zone is defined as a thermal insulating layer that contains a salt gradient where water closer to the surface is always less salty compared to the water below it. Lastly, the lower zone is a concentrated salt solution that can either be temperature stratified or in convection. In some cases where the salt gradient is abundant, no convection occurs in the gradient zone if the heat is consumed on the bottom, as the saltier and hotter water stored in the bottom part of the gradient will be thicker than the less salty and

Solar Ponds

661

Sun Surface zone (upper convective zone)

Gradient zone (non-convective zone)

Storage zone (lower convective zone)

Heat exchanger Fig. 1 Cross-section view of a salt gradient solar pond. Reproduced from Dincer I, Rosen M. Thermal energy storage systems and applications; 2011.

cooler water above it. As water transmittance is high enough that it is visible to light but at the same time blurred to radiation, sunlight reaches the darkened bottom in the form of energy where it is absorbed and can escape only with conduction. If the gradient zone is relatively thick, the heat escapes upwards from the storage zone very slowly as the thermal conductivity of water is considered to be low that it establishes the ability to be an energy storage device and a thermal collector simultaneously [2]. When compared to other thermal technologies where the solar energy is absorbed, the solar ponds, specifically salt gradient ponds, have some advantages such as being relatively simple. A solar pond mainly consists of an excavation in the ground, water, and salt. Nature happens to supply these ingredients in many locations, which reduces the cost and makes the system easier to build up compared to the setups of other energy systems. In some cases, even if the efficiency of the system is only a small percentage because of the low costs, it justifies converting low temperature heat into electricity. The operating costs of the solar ponds are expected to be low as the fluid pumping is usually only necessary to extract the heat from the solar pond; collecting and storing the energy are completely passive processes [3]. As mentioned previously, nature contains all of the necessary inputs for the solar pond process to begin so as a result the salt gradient solar ponds occur naturally in lakes and rivers. Many examples have been found in sheltered parts of the earth. These natural solar ponds are observed over temperatures of 701C coupled with salt lakes and salt deposits throughout the world. It is strongly suggested that with minimal environmental impact artificial solar ponds are technically feasible in many locations. Just like other types of solar technologies, there are cunning effects, such as the hydrodynamics of double-diffusive convection that play a major role in the behavior of solar ponds. All of these should be taken into consideration when designing a solar pond. Therefore these effects must be understood before the use of solar ponds becomes more and more popular. Many large and small scaled prototype solar ponds have been built for research purposes but still this technology is yet to be proven from the economic perspective in the industry. Even though many concepts and designs regarding the solar ponds have been well understood with the help of many researches and experiments there are still basic questions left over to be answered before their performance is maximized and the cost is minimized [3].

4.16.2

Historical Background

Solar ponds were discovered as a natural occurrence in Medve Lake, Transylvania, Hungary. Solar ponds go back to the early 1960s, where they were invented in Israel in principle to be applied in basic thermal energy operations. They are designed to last for many years to come and require the least maintenance compared to other solar energy systems with the help of nature preventing the necessary tools to build up a solar pond [4]. One of the main advantages that a salinity solar pond offers is providing thermal energy storage and heat collection simultaneously, also the equipment used to preserve the salt gradient is cost effective compared to other solar energy systems. The ponds need simple maintenance similar to swimming pools such as cleaning in order to provide clear and visible water transparent to light in order to keep the efficiencies at highest possible levels. Many different types of research are conveyed in this field including experimental setups or discussions regarding the effects of distinct parameters such as the work done by Karakilcik concerning the investigation on the effect of shading on solar ponds [5]. As shown in Fig. 2 the solar pond has been around since the 1950s. The considered types of solar ponds in the chapter are salt gradient, partitioned, viscosity stabilized, membrane stratified, saturated, and shallow solar ponds [4]. Each type is tagged on the diagram periodically and will be discussed in a detailed way further in the chapter.

Solar Ponds

662

The historical development of solar ponds 1950

1960

1970

1980

Sat-gradient solar pond introduced

Viscosity stabilized solar pond introduced

Saturated solar pond introduced

1990

2000

Solar pond conceps Hungary 1948 Partitioned solar pond introduced

Membrane stratified solar pond introduced

Experiments Shallow solar pond introduced Trials

Hybrid applications Invention of solar ponds

1950

1960

1970

1980

1990

2000

Fig. 2 Historical development diagram of solar ponds.

4.16.3

Solar Ponds

Solar ponds are defined as integral devices used for collecting and storing solar energy with the help of high salinity water. Having a built-in thermal energy storage can be used as an advantage irrespective of time and season. When the sun rays heat up the water in an ordinary pond or lake, this heated water, being lighter, rises to the surface and loses its heat to the atmosphere resulting the pond water remaining at atmospheric temperature [6]. Solar pond theory relies on this phenomenon by dissolving salt into the bottom layer of this pond, which makes it too heavy to rise to the surface even when it reaches higher temperatures. As a result the salt concentration increases with depth, which forms a salinity gradient in the water pond. It is accepted that the sunlight that reaches the bottom of the water pond is trapped there [6]. Then the thermal energy stored in the solar pond is drawn in the form of hot brine [3]. The necessary elements to have an established high salinity solar pond consist of an abundant area of land, plenty of sunshine, and readily available salt. Other than the thermal energy storage a sensible cooling storage can be added to existing facilities by creating a small pond or lake on the site [6]. Solar ponds are usually large, deep bodies of water, oversized to provide community heating. When compared to natural occurring ponds solar ponds vary in various approaches such as being filled with clear water to ensure maximum penetration of sunlight, darkened bottom surface to absorb more solar radiation. Salt is added to increase the salinity, make the water denser at the bottom, and to restrict natural convection. The cooler water on the upper layer acts as insulation and prevents evaporation. Salt water can be heated to high temperatures, even above the boiling point of fresh water [6]. Once again as shown in Fig. 1 a crosssection of a typical salinity-gradient solar pond has three regions: surface zone, gradient zone, and lower convective zone. So as a result the water closer to the surface is always less concentrated than the water below it [4]. When the salinity gradient is large enough, there is no convection in the gradient zone even when heat is absorbed in the lower zone, because the hotter, saltier water at the bottom of the gradient remains denser than the colder, less salty water above it [7]. We will examine these areas in a more detailed fashion, starting from the lower convective zone or heat storage zone that is composed of salty water with the highest density. A considerable part of the solar energy is absorbed and stored in this region of the salinity solar pond. The highest temperature occurs at the lower convective zone, where the nonconvective zone or gradient zone is sandwiched in between the lower convective zone and the upper convective zone. The gradient zone is composed of salty water layers where the density gradually increases toward the lower convective zone. The gradient zone is the key transition zone for a working well-established solar pond. The transition zone allows the excessive solar radiation to get into the storage zone and at the same time restricts the solar radiation from escaping from the solar pond’s thermal storage by keeping the water opaque against infrared radiation.

Solar Ponds

663

The upper convective zone is the fresh water layer at the top of the pond. This zone is the least dense one, because it is supplied with water of a density small enough to preserve the transmission rate of the pond [5].

4.16.3.1

Important Parameters

Important parameters concerning the salinity solar pond can be broadly categorized into normal monitoring and research needs. The monitoring of a solar pond usually involves measurements of the temperature distribution, the salinity distribution, the radiation input, the heat extracted, water pH in the pond, and the heat lost to the earth. Whereas, the setups built for research purposes require similar information with greater accuracy or better resolution. These types of studies may also require study of particular processes, such as the effect of turbidity on the transmission of heat in a salinity solar pond. Each and every parameter affecting the solar pond’s performance and efficiency, because they may be subject to the corrosive effects of hot salt water or to large temperature variations in the solar pond, should be controlled carefully. The most effective parameters affecting the solar ponds are temperature, salinity, transmittance, and soil quality, and are discussed further in the chapter [8].

4.16.3.1.1

Temperature

The changes in temperature and the temperature profiles provide essential information about the current state of a pond. These kinds of data give information such as the thickness of the various zones and show the response of the surface zone to environmental effects or the effects of heat extraction on the storage zone and provide a record that is combined with radiation input and heat extraction data, which are essential for the calculation of the solar pond’s performance energetically and exergetically [9]. The temperature profiles can be measured either with the use of an array of fixed thermal sensors or from a single thermal sensor scanned in between the upper and the bottom layer of the pond. The array of sensors method may appear more appealing but the depth corresponding to every reading is known and is kept constant, and temperatures are readily recorded with a multichannel data-logger. But still unless extreme care is taken with both initial calibration and accuracy of readings, this system gives a less accurate representation of the temperature profile. The absolute error for the measurements tends to be around 0.51C, which corresponds to an uncertainty of 101C in the local gradient if a 5 cm spacing is used. Absolute temperature is usually not needed more accurate than 70.51C, but a gradient error of this magnitude becomes undesirable. An even more serious problem has arisen in some ponds where in order to limit the number of sensors and readings required, the sensors were spaced by 10 cm or even more. It resulted in undetected internal convective zones within the gradient zone. In one case where 10 cm spacing was used there were five undetected internal zones and the gradient thickness was less than one third of the apparent thickness as indicated by the distance between the top and bottom of the gradient zone. So as a result it is possible to say that the spacing in between the fixed sensors must be not more than 5 cm, especially at the gradient region. The 5 cm figure arises from the observation that internal convective zones thinner than about 5 cm are transient: they either disappear or they become thicker [4].

4.16.3.1.2

Salinity

The changes in salinity in a solar pond give more information regarding the zone boundary locations compared to temperature profiles, because there are sometimes fluctuations of several centimeters in the level observed for a temperature boundary. The growth of the surface zone from wind can easily be evaluated from salinity profiles. The salinity data also provides necessary information to monitor stability conditions and keep track of the salt inventory. In order to calculate the salt flux in the pond an accurate salinity knowledge is necessary as the salt diffusivity is low. As temperature and salinity affects the density measurements and these temperature measurements are already made as mentioned in the previous section. The measurements made to determine the density and the temperature is often substituted for a direct measurement of salinity. For accurate density measurements, a sample of fluid is taken from the pond and transferred to the laboratory, where a certain amount of the sample is accurately weighed at a known temperature. These measurements can also help detect the leaks that occur on the pond liner. It is important to keep in mind that this method requires fixed sampling locations to achieve accurate and consistent density measurements [10]. There are a couple of different density measurement techniques available for scanning devices that examine the entire depth of the pond. Many researchers have trialed these techniques and concluded that the hydrometer and vibrating U-tube are the most suitable for commercially used measurement devices. Better measurement results with smaller error percentages can be gathered if the pond can be protected from the wind. Measuring the electrical conductivity, which is a function of both salinity and temperature, is also a popular method of determining salinity. These electrical conductivity measurements give reasonable accuracy at low salinity, but the accuracy is not as stable at high concentrations. The surface condition of the electrodes, which gets affected upon exposure to salt water with time and recalibration differentiating the response of a conductivity probe. There are also several examples of solar ponds using electrodeless conductivity probes, which have better stability for long-term applications because there is no exposed electrode. The probes measure the inductance in between two coils whose windings are cased in plastic material. With the use of a tetra polar conductivity probe device, the current is generated by two outer electrodes, while the resulting electric field is measured by two inner electrodes where spacing between the two inner electrodes is as small as 2 mm and a spatial resolution of 5 mm was obtained. This device also has the problem with the two electrode probes where the response drifts with time so that it needs periodic recalibration. Unfortunately the spatial resolution of these electrodeless probes is only a few centimeters [11].

664

Solar Ponds

4.16.3.1.3

Transparency

The transparency of the pond’s surface strongly affects the thermal performance of a solar pond. Also the performance of a solar pond can be predicted only when the transmission function is known for the certain solar pond. The transmission of a solar pond should be monitored periodically in order to know the necessary elements to maintain good water clarity for maximum efficiency. There are mainly two different monitoring methods used to observe the optical quality of a pond’s surface. Absorption cells containing samples from various depths in the pond are used for transmittance and field measurements concerning the percentage solar energy penetrating to various depths in the pond. But still it is possible to say that both of these monitoring methods have limitations and problems [12]. The most common problem concerning the transparency of the pond is getting mixed up with a particulate inorganic or organic material. This is labeled as the main reason that the solar pond’s clarity is less shoddy compared to a fresh water ponds even though the effect of dissolved NaC1 or other types of salts are relatively small. When scattering occurs it may cause transmitted radiation, which results in no information about the transmission function of the pond with the use of laboratory absorption cell measurements. As it affects the geometry, multiple forward scattering in an absorption cell may allow some part of the incident light to exit the cell through the side wall and not intercept the sensor. But still, a large fraction of this scattered light will propagate into the lower zone layer. The observations regarding solar energy penetration into the pond can be monitored by comparing the readings of a measurement device placed inside the pond combined with the readings of a similar measurement instrument located above the pond. These measurement devices are essential for accurate data readings because even with good and clear weather conditions, there can be variations in the solar flux. The changes in radiation with path length in the water can be plotted with the use of necessary measurement devices that include flat responses such as thermal sensors. Photovoltaic measurement devices have also been trialed to help measure the transmittance of the pond and useful data have been obtained if the readings are corrected by the changes in the pond and angle of the radiation. As the temperature varies with depth in the pond, it is necessary to reflect this response to the measurements or to know the temperature dependence parameters. Also the changes in the outside environment from air to water should be considered for the measurements. The decrease caused by the reflectivity from the cover due to the smaller difference in the refraction between water and glass than between air and glass should also be taken into account. Other than the problems occurring as a result of the leaks in the pond and corrosion, there are also thermal and optical problems occurring on the measurement devices [13]. By looking at these considerations and problems it is possible to see why both laboratory and field measurements are valuable. The field measurements of radiation penetration to various depths provide an accurate enough way to determine the pond transmission function. But at the same time the laboratory measurements of transmission through pond samples provide more sensitive results compared to field measurements.

4.16.3.1.4

Soil

As mentioned in the previous sections the heat losses to the ground have an important influence on the solar pond’s performance. The heat transfer coefficient of the soil effects the calculations regarding the heat loss to the ground and this property can be effected by the amount of moisture, vapor, and water movement. The heat loss to the ground can be directly determined or calculated by measuring each parameter on which it depends. The moisture content can be measured with respect to the ground heat loss; primarily for leak detection, electrical conductivity devices have been installed under several ponds. As conductivity is an important parameter regarding both moisture and salinity these devices will be also helpful in this sense. Time-domain reflectivity is also used as a method to monitor the water content and electrical conductivity continuously of the soil type. This method observes and notes the return time of a pulse sent to two parallel metallic rods embedded in the soil. The water vapor transport component is important when temperature and soil moisture are set in a certain way. When it comes to the direct measurement of heat flux, it is extremely difficult because of the conventional heat flux sensors to form a solid cover to the vapor flow, especially tweaking the results. The thermal conductivity can be estimated from temperature measurements if the heat capacity is known. The temperature and moisture fluctuations in the soil under the pond may increase or decrease the horizontal vapor transport. Calculating the heat flux becomes difficult because of these fluctuations so placing heat flux sensors on the bottom of the pond, rather than underneath the soil, might be a good idea to get accurate and useful information regarding the losses [14].

4.16.4

Classification of Solar Ponds

The types of solar ponds investigated throughout this chapter are salt gradient, partitioned, viscosity stabilized, membrane stratified, saturated, and shallow solar ponds [4]. All the types shown on Fig. 3 will be discussed in a detailed way in this section with experimental setup investigations built for each type from all around the world. The experimental setups built for research purposes for the solar ponds are gathered in this section and discussed briefly by mainly focusing on the setup built in Adana, Turkey at Cukurova University [15]. Then three different setups built for different purposes are also discussed in the section.

Solar Ponds

665

Solar ponds

Salt gradient solar ponds

Partitioned solar ponds

Viscosity stabilized solar ponds

Membrane stratified solar ponds

Saturated solar ponds

Shallow solar ponds

Fig. 3 Solar pond types flowchart.

4.16.4.1

Salt Gradient Solar Ponds

Salt gradient solar ponds are labeled as the most popular and common type; these ponds are typically 1–2 m deep and the bottom is painted black to maximize convection. As explained previously the working mechanism is once again the same, convection currents develop with hot water circulating at the bottom and cold water circulating at the top combined with density gradient from bottom to top. The density gradient is obtained by using a high concentration of suitable salts at the bottom of the pond such as NaCl. The thermal conductivity of the salt solution becomes less than a fresh water pond and decreases with the increase of salinity by the addition of salt to the solution and acts as an insulating layer. Once again the solar pond has three layers, the top surface layer is known as the convection zone, which is a zone of constant temperature and salinity. Usually the thickness of the surface layer ranges between 0.1 m and 0.4 m and it is formed as a result of upward salt transport, surface heating and cooling, and wave action [4]. Then comes the second layer, which is also referred to as the nonconvective or gradient zone with a thickness ranging in between 0.6 m and 1.0 m that acts as an insulating layer of the pond. The depth of the pond is directly proportional to its density at that depth. The last one that lies on the bottom of the pond is the third or storage layer, which has the highest temperature compared to the layers in the pond. The temperature and salinity rates are always kept constant in this layer by the continuous addition of salt. The useful heat is extracted from this layer then the thickness of this layer depends on the amount of thermal energy stored. Many different concepts have been introduced by researchers to improve the performance of the salt gradient solar ponds. The researchers have succeeded in improving two qualities regarding the salinity solar ponds; the overall salinity of the pond was increased and a stratified flowing layer was established in the lower part of the gradient zone. The increase in salinity is achieved mainly on the surface layer in order to reduce evaporative heat loss but this also results in increased salinity throughout the whole pond. The stratified flowing layer is used to maintain stability for additional heat extraction that is similar to the flow that would be established in the lower layer for a similar purpose. So as a result the extracted heat over the pond is also recovered, which might have been conducted upwards from the lower conductive zone at the first place [16]. The salt concentration gradient in the pond can be generated by various methods such as natural diffusion, stacking, redistribution, and falling. In the natural diffusion method, the upper half is filled with water where the top and bottom concentrations are maintained constant by periodically washing the surface and adding salt to the pond. With the help of upward diffusion of salt, a salinity gradient is established in the pond. This is a considerably slow method of establishing the salt gradient and should only be considered if the pond is very large, or if the starting time is not an issue [14].

4.16.4.1.1

Experimental setup of a salinity solar pond at Cukurova University

The experimental solar pond setup located in Adana, Turkey at Cukurova University [6] will be discussed in this section of the chapter regarding how it is built, its purpose, and lastly the parts used in the making of the setup. Temperature distributions, energy and exergy losses, and efficiencies are determined in the experiment and the pond performance can be obtained experimentally for the duration of the experiments using the allowed data. Zone thickness, reflected solar radiation, and wall insulation can be labeled as the significant factors affecting performance [5]. As it can be seen from Fig. 4, a common pond has contrasting properties from the solar pond, in terms of the way the water is heated and the buoyancy adjusted, which results in heat loss by getting closer to the surface. By increasing water temperature with the addition of salt causing the water to get denser and become unable to rise to the surface. Different than regular water ponds the energy gathered from the sun can be captured with use of black painted bottom surface in a solar pond. When a saline concentration gradient is formed, depth becomes directly proportional to the salt concentration. The increase in salt concentration at the same time prevents natural convection by making the water on top, which has a lower temperature, operate as insulation and restrict evaporation. As the density of the water increases, its boiling point becomes greater at the same time. The other different properties can be listed as the black painted surface inclusion for the solar pond and using fresh water to maximize solar penetration. Hot brine can be described as the energy expelled from the solar pond. Another advantage that the solar ponds bring is the requirement for cost efficient maintenance and as a result they offer an extensive lifespan. To maintain the solar gradient uncomplicated equipment is necessary. The solar pond’s construction, maintenance, and the storage zone capacity are the features that affect the performance of a solar pond [13,17]. A backup system is normally not required for solar ponds, which decreases the cost necessities for the system. 4.16.4.1.1.1 Experimental unit Fig. 5 includes a photograph of the experimental unit used in the study that has a depth of 1.5 m and a bottom layer with 2  2 m in length. The lower convective layer, gradient layer and the upper convective layer thicknesses are 0.8 m, 0.6 m and 0.1 m, respectively.

666

Solar Ponds

Sun

Upper convective zone Nonconvective zone

Heat exchanger

Storage zone

Fig. 4 Solar pond and its three zones. Adapted from Karakilcik M, Dincer I. Exergetic performance analysis of a solar pond. Int J Therm Sci 2008;47(1):93–102.

Fig. 5 Photo of the experimental setup. Adapted from Karakilcik M, Dincer I. Exergetic performance analysis of a solar pond. Int J Therm Sci 2008;47(1):93–102.

NaCl and fresh water makes up the solution, where the zones are having a density of 1000–1045 kg/m3, 1045–1170 kg/m3 and 1170–1200 kg/m3 with respect to increasing depth in the solar pond. Five-mm-thick iron sheets are used as insulation material for the side walls with the addition of 50 mm thick glass wool. 20 mm wood feet are used under the solar pond [5,6]. Painting is used as an anticorrosion coating for the inner surfaces of the side walls, where Fig. 6 represents the inner zones of the solar pond and Fig. 7 shows the solar radiation penetrating the pond and the thickness values of the lower convective zone, gradient zone upper convective zone by X3–X2, X2–X1, and X1, respectively. Table 1 lists the other properties regarding the data for the solar pond [6]. 4.16.4.1.1.2 Data acquisition The measurement methods are discussed in a detailed fashion in this section [5,6]. Temperature measurements are made in the pond at different depths of 0.05, 0.30, 0.55, 0.70, 0.80, 1.05, 1.35, and 1.50 m for heights from the bottom of the side wall of 0, 0.35, 0.65, 0.75, 1.00, and 1.35 m with respect to increasing depth hourly during the day. The thermal sensors (1N4148 semiconductor devices) used in the measurements have an accuracy of 70.11C with a range of 651C to þ 1551C. The experimental data and temperature profiles are obtained by using these sensors. A pyranometer is used to obtain solar energy based data combined with environmental conditions acquired from a local meteorological station [7]. 4.16.4.1.1.3 Data analysis In order to have a better understanding of the thermal performance regarding the solar pond, absorption rates that occurred as a result of incident solar radiation are obtained with plotted distributions of temperature and salinity. The solar radiation is absorbed and reflected simultaneously, where the rest is used by the pond to be converted into electricity later on. The solar

Solar Ponds

667

Qsolar

Re f

lec

te

d

be

am

m ea tb en cid In

Qwa Qstored, UCZ (TUCZ) Q I,NCZ

ns Tra

Qsw, UCZ

mit ted

Qstored, NCZ (TNCZ)

i rad

Qsw, NCZ

atio n

QI, HSZ Qstored, HSZ (THSZ)

Qsw, HSZ Qb Insulated wall

Fig. 6 Energy flows for experimental solar pond. Adapted from Karakilcik M, Dincer I. Exergetic performance analysis of a solar pond. Int J Therm Sci 2008;47(1):93–102.

n

iatio

r rad

ola ent s

Incid

X1

Upper convective zone

X2 Non-convective zone X3

Heat storage

rea

ga

in had

S

N

Fig. 7 Behavior of incident solar radiation in experimental solar pond. Adapted from Karakilcik M, Dincer I. Exergetic performance analysis of a solar pond. Int J Therm Sci 2008;47(1):93–102.

Table 1

Data given for the experimental setup [5] Storage substance

Experimental container

Surroundings

Property

Brine

Water

Insulation

Painted wall

Air

Density (kg/m3) Specific heat (kJ/kg K) Thermal conductivity (W/mK)

1185 – –

998 4.182 2.160

200 0.670 0.143

7849 0.460 21.20

1.16 1.007 0.0947

Source: Adapted from Karakilcik M, Dincer I. Exergetic performance analysis of a solar pond. Int J Therm Sci 2008;47(1):93–102.

radiation is penetrated through the layers and the leftover reaches the lower convection zone, where it is converted to heat energy and stored there. As the concentration of the water solution differs with depth simultaneously with the changes in absorption rate. Similar to seawater the fluid that flows in the upper convective zone has the lowest salinity values throughout the pond. For the

668

Solar Ponds

gradient zone, depth acts directly proportional to temperature and salinity, where the fluid becomes membraned due to higher concentration and density in the heat storage zone [5]. Just like the regular solar ponds the experimental setup includes three zones that are also divided into 30 inner layers varying in terms of temperature. Constantly changing and adjustably complex factors make the measurement of the experimental data much more complicated than the simple solar pond system, e.g., transmission and absorption properties of the used material, incident solar radiation, pond design dimensions, shading, solar pond fluid thermophysical properties, structure and insulation, and surrounding climate. 4.16.4.1.1.4 Temperatures Experimental temperature distributions plotted with respect to depth are investigated for the inner zones seen in Table 2 and Fig. 8, which are used to calculate heat losses from the solar pond. The measurements have been conveyed monthly for the experimental setup. The table clearly shows that monthly temperature measurements seem to vary throughout the year for surrounding, heat storage zone, nonconvective zone, and upper convective zone ranging from 101C to 281C, 171C to 551C, 141C to 431C, and 101C to 341C, respectively. The minimum and maximum temperature values are measured during August and January, respectively. The incident solar flux seems to increase the temperature for each and every zone. 4.16.4.1.1.5 Brine density gradient Fig. 9 demonstrates the variation of brine density in the experimental setup monthly. The weather conditions reflect information regarding the absorption and reflection of solar radiation at the pond surface that is not available for instant usage and the heat losses to air combined with the thermophysical properties of the brine layer. In summertime, the density and temperature are inversely related. At upper and nonconvective layers evaporation of water causes increase in temperatures. These effects are adjusted with the addition of fresh water or salt accordingly to the situation occurring. Also when the cleaning and maintenance systems are not used, significant changes to the measurements occurred as a result of low transmittance [6]. 4.16.4.1.1.6 Energy flows, efficiencies and losses Fig. 6 demonstrates the energy flows for each zone. Incident solar radiation, shading and reflection, transmission and absorption, as well as heat flows to surroundings and across zones are labeled as the factors affecting the thermal performance of the Table 2

Mean average of temperatures (1C) of solar pond zones and surroundings measured monthly for 11 months

Upper convective zone (UCZ) Nonconvective zone (NCZ) Heat storage zone (HSZ) Surroundings

Jan.

Feb.

Mar.

Apr.

May

July

Aug.

Sep.

Oct.

Nov.

Dec.

10 14 17 10

12 15 18 11

14 19 22 14

18 22 28 18

27 36 40 22

33 42 52 28

34 43 55 28

33 41 50 26

28 32 41 21

20 22 28 16

18 20 23 11

Source: Adapted from Karakilcik M, Dincer I. Exergetic performance analysis of a solar pond. Int J Therm Sci 2008;47(1):93–102.

70 0.05 m 0.80 m

0.30 m 1.05 m

0.55 m 1.35 m

0.70 m 1.50 m

60

Temperature (C)

50 40 30 20 10 0 Jan.

Feb.

Mar.

Apr.

May

July

Aug.

Sep.

Oct.

Nov.

Dec.

Months Fig. 8 Monthly mean temperatures in the experimental setup for various depths. Adapted from Karakilcik M, Dincer I. Exergetic performance analysis of a solar pond. Int J Therm Sci 2008;47(1):93–102.

Solar Ponds

1250

Jan. May Sep.

Feb. Jun. Oct.

Mar. July. Nov.

669

Apr. Aug. Dec.

Density (kg/m3)

1200

1150

1100

1050

1000 0.05

0.30

0.55

0.70

0.80

1.05

1.35

1.50

Height from the bottom (m) Fig. 9 Changes in salt density for the experimental solar pond with height in the inner zones. Adapted from Karakilcik M, Dincer I. Exergetic performance analysis of a solar pond. Int J Therm Sci 2008;47(1):93–102.

3000

Energy and exergy contents (MJ)

Energy (HSZ) Exergy (HSZ)

Energy (NCZ) Exergy (NCZ)

Energy (UCZ) Exergy (UCZ)

2500

2000

1500

1000

500

0 Jan.

Feb.

Mar.

Apr.

May

Jun. Jul. Months

Aug.

Sep.

Oct.

Nov.

Dec.

Fig. 10 Monthly mean energy and exergy contents of the zones in the solar pond. Adapted from Karakilcik M, Dincer I. Exergetic performance analysis of a solar pond. Int J Therm Sci 2008;47(1):93–102.

solar pond. The performance gets highly affected with the occurrence of heat losses significant at the pond surface but kept very small from the sides and bottom by insulation [6]. The wall shading occurring on the heat storage zone seems to affect the sunlit area and temperature of the zones. The average sunny area and shaded areas respectively are determined to be 2.63 m2 and 1.37 m2 for the HSZ, 3.13 m2 and 0.87 m2 for the NCZ, and 3.93 m2 and 0.07 m2 for the UCZ. For the net average values of solar radiation incident on January, May, and August are 439, 2077, and 2042 MJ for the UCZ; 352, 1662, and 1634 MJ for the NCZ; and 193, 914, and 899 MJ for the HSZ, respectively. Just a small partition of incident solar radiation is reflected from the upper and gradient zone. Most of the incident radiation penetrates the lower zone from the gradient zone and the absorbed radiation from the gradient zone is emitted in the lower convective zone, where only a small portion of the incident solar radiation is deflected from the lower zone to the upper zones in the solar pond [3,6]. Fig. 10 illustrates the stored energy for each zone; in January and August values are at 4 and 93 MJ, 311 and 225 MJ, and 19 and 253 MJ at UCZ, NCZ, and HSZ, respectively. It is possible to say that the highest values are observed in the heat storage zone [6]. Fig. 11 represents the zone energy efficiencies varying from 0.9% to 4.5%, 3.2% to 13.8%, 9.7% to 28.1% for months January and August, respectively starting from the upper zone and going down. Even though the UCZ receives the greatest incident solar

670

Solar Ponds

35 Exergy (UCZ) Energy (UCZ)

30

Exergy (NCZ) Energy (NCZ)

Exergy (HSZ) Energy (HSZ)

Efficiency (%)

25 20 15 10 5 0 Jan.

Feb.

Mar.

Apr.

May

July Aug. Months

Sep.

Oct.

Nov.

Dec.

Fig. 11 Monthly mean energy and exergy efficiencies of the zones in the solar pond. Adapted from Karakilcik M, Dincer I. Exergetic performance analysis of a solar pond. Int J Therm Sci 2008;47(1):93–102.

radiation, it has the lowest efficiencies amongst all zones as its thickness is small and surface heat losses are large. Shading is the main reason for the lowest efficiency values at the UCZ. Using the solar pond as a thermal storage is taking advantage of one of the main attributes of solar ponds; the performance of the solar pond depends upon the total radiation reaching each and every zone. Most of the incident solar radiation is trapped by the blackened bottom layer. The increase in the shading area with respect to depth is inversely related with the solar radiation transmitted. The efficiencies are seemingly low since the stored energy is smaller compared to the incident solar radiation for the zone surfaces. Energy efficiency reduces with the increase in energy losses from heat transfer to air from the upper convective zone reduces energy efficiency. The temperatures of the brine and surrounding air are labeled as the factors affecting efficiency. The changes in between different zone temperatures influence the diffusion of salt molecules from the bottom layer and the heat losses. To improve the performance, and the accuracy of the exergy analysis, it is useful to experiment by using the true magnitudes of thermodynamic efficiencies and losses for the solar pond. 4.16.4.1.1.7 Exergy flows, efficiencies and losses As the energy analysis of solar pond system is already conducted, it is possible to point out the weaknesses and use this information to increase the accuracy of the exergy analysis. Exergy analysis assesses meaningful efficiencies in order to find out the useful amount of energy stored in the system. Fig. 5 demonstrates the exergy flows for the corresponding energy flows for each and every zone located in the pond. The energy and exergy efficiencies gathered from the experimental analyses are compared to the results of three other experimental solar pond setups. Fig. 10 contains the monthly energy and exergy contents for each zone included in the solar pond zones, determined using the mean monthly temperature values in Table 2. The lowest and highest monthly average exergy values are calculated in January and July, respectively. The energy efficiencies are seemingly higher than the exergy contents. The only energy losses are heat emissions to the surroundings as the energy is conserved. The surroundings may also cause some decreases in exergy values and it is also destroyed in each zone due to irreversibilities because of processes such as mixing fluids of different temperatures and the temperature of the surroundings affecting energy and exergy losses since both cause heat losses to the ambient air [17]. Table 3 contains the monthly variations in exergy input, exergy recovered, and exergy destruction and losses for the zones. The greatest values are found in July as the solar irradiation is at its greatest and the remaining exergy terms may vary with regard to the exergy input. For the upper conductive zone the exergy accumulation is assumed as it is less than 1%, also it can be neglected for the gradient zone. Starting from January to July the recovered exergy ranges from 392 MJ to 1682 MJ. Also the exergy recovered in the gradient zone is transferred to the lower convective zone. Exergy is stored rather than recovered in the heat storage zone as the name suggests. Less exergy is stored in the upper zones compared to the exergy input and the exergy destruction and losses. For the gradient zone in January and July the exergy recovered from the gradient zone ranges from 170 MJ to 743 MJ in July [5,6]. Fig. 11 demonstrates the monthly energy and exergy efficiencies for each zone of the solar pond, where the exergy efficiencies are lower than the energy efficiencies for each pond zone. In the winter the difference between energy and exergy efficiencies seems to be smaller than in summer. For the lower convective zone the efficiencies are higher than the efficiencies for the upper and nonconvective zones. The exergy destruction and losses significantly affect the performance and detract from system efficiency. The pond inner zones store more exergy in the summer than the winter [5].

Solar Ponds

Table 3

671

Mean average of exergy parameters (MJ) for solar pond zones (monthly) Jan.

Feb.

Mar.

Apr.

May

July

Aug.

Sep.

Oct.

Nov.

Dec.

417 335 188

644 517 291

1161 931 525

1700 1363 768

1976 1588 885

2168 1748 959

1982 1601 869

1740 1404 767

1300 1049 573

783 629 350

506 408 224

Recovered or storeda UCZ 329 NCZ 188 HSZ 17

511 291 27

920 525 53

1348 768 89

1553 885 141

1682 958 204

1525 869 218

1345 766 181

1005 573 133

614 350 57

393 224 28

Lossb UCZ NCZ HSZ

133 226 264

241 406 472

352 595 679

423 703 744

486 790 755

457 732 651

395 638 586

295 476 440

169 279 293

113 184 196

Input UCZ NCZ HSZ

88 147 171

a

Values for HSZ are stored exergy and for UCZ and NCZ are recovered exergy.

b

Includes exergy destruction and waste exergy emission. Source: Karakilcik M, Dincer I. Exergetic performance analysis of a solar pond. Int J Therm Sci 2008;47(1):93–102. Dinçer I, Rosen MA. Energy and exergy analyses of thermal energy storage systems. Therm Energy Storage 2010;1038(December 1998):233–4.

4.16.4.2

Partitioned Solar Ponds

Because of the common occurring problems in solar ponds researchers and scientists have come up with optional ways and methods to get rid of the following problems: biological growth of bacteria, dirt falling into the pond and decreasing its transparency, evaporation causing too high concentration at the top, and disturbance of the concentration gradient while extracting heat. The solution to the problems were found via installing two transparent partitions one on top or few centimeters below the surface of the pond and the other at a depth of 1–2 m. This layer above the top partition has advantages and disadvantages at the same time such as being placed in windy locations, including evaporative cooling, and increased reflectivity due to wave action. But when it comes to the advantageous side of things, there is a decrease in reflective losses because the water has a lower index of refraction than plastics, so that reflective losses at a water–plastics boundary are small. The lower partition separates the insulating layer from the convective layer, improves the stability of the pond, and facilitates the extraction of heat. Buoyancy may result in instabilities in the system but this can easily be avoided by either making the lower partition stiff (e.g., glass panes) or with the use of a flexible partition or filling the convection zone with salt water. To improve convection, heat is extracted just below the partition either by removing hot water or brine directly or by running fresh water through a network of heat exchanging plastic pipes [18].

4.16.4.3

Viscosity Stabilized Solar Ponds

The layers of solar ponds that are not convecting actively are mainly composed of salt gradient layers. Salt gradient solar ponds, however, have a number of difficulties that may cause environmental pollution as a result of salt leakage and the salt gradient layer needs frequent maintenance. To get over these problems, Shaffer proposed a new type of solar pond using a transparent polymer gel as a nonconvecting layer. The polymer gel has low thermal conductivity and is used at a near solid state, so that it will not convect [19].

4.16.4.3.1

Experimental setup of a viscosity stabilized solar pond

Mainly the first experimental setup built regarding the gel pond was performed by Wilkins in 1980 at the University of New Mexico with results on experimental and theoretical studies of the gel pond, which included a cost benefit economic analysis, comparing the economics of a gel pond with a conventional salt gradient pond [20]. There are still some concerns on the gel techniques; research and development may still be necessary in order to learn how to manufacture gel on a large scale, may be recommended that the nonconvecting layer is composed by the viscous polymer solution rather than the near-solid gel. But still as the liquids in gradient zone of this pond are Newtonian fluids the membrane spacing for convection should be kept small. Bigger viscosity values may occur where the polymer concentrations are increased. However as the concentration becomes larger, the light transmittance becomes smaller as a result, and the efficiency of the solar pond reduces. The values concerning the critical concentration for convection become smaller and smaller with the decrease in layer thickness, when the polymer layer is divided with the help of transparent membranes, finally a polymer solution with less concentration can be utilized. After that, the transmittance of the polymer layer becomes greater. For viscosity stabilized solar ponds, the light transmittance through the insulating layer of polymer and film reduces as the number of membranes increase. The reason behind this situation is absorption and reflection losses upon the membranes. The determination of the thickness for the insulating layer and the number of membranes is necessary for design purposes [20].

672

Solar Ponds

Motor

Heater

Thermocouple Transformer Low temperature layer Polymer layer

Wattmeter

Pump High temperature layer

Electric heater

Water

Insulator

Fig. 12 Apparatus used for the experimental setup. Adapted from Taga M, Matsumoto T, Ochi T. Studies on membrane viscosity stabilized solar pond. Sol Energy 1990;45(6):315–24.

In this experimental study, the following steps were followed and these experiments were conveyed as fundamental research: investigation to determine the suitable polymer thickener and on the suppression of the polymer thickener’s convection, lastly outdoor experiments by a small scaled viscosity stabilized solar pond. Then the theoretical results were compared with experimental ones to achieve the optimum design conditions for a viscosity stabilized solar pond. The experimental setup consists of a square space insulated in a surrounding wall as shown in Fig. 12. The surface area (73  73 cm2) was designed to model a layer of infinite horizontal extent. The thickness of the liquid layer (L) can be set by the setting different heights for the upper water pond and is kept at a temperature around 251C by adjusting the voltage of the heater placed inside the outer storage tank. The flow rate of the water is controlled by an adjusting tank and a lower chamber is provided in order to heat the test layer uniformly from below with the use of an electrical heater. In order to stabilize the temperature the high and low temperature layers are heated up before the experiments. Once again the electrical power of the heater is controlled by a voltage adjuster, and is measured with the use of a wattmeter. Thermocouples are placed on each layer and on the piping as illustrated in Fig. 12 to measure the temperature differences between the upper and lower surfaces of the test polymer layer [20].

4.16.4.4

Membrane Stratified Solar Ponds

Membrane stratified solar ponds are classified amongst nonsalt solar ponds, which contain a body of liquid sandwiched in between transparent membranes. The spacing for the membrane layers should be very small and include a large number of high transparent films to maximize the efficiency of the solar pond. The weight of water balances out the buoyancy effect so that the solar radiation can easily be converted into sensible heat. Horizontal sheets, vertical tubes, and vertical sheets are the most commonly used types for the membrane stratified solar ponds [8].

4.16.4.5

Saturated Solar Ponds

Regarding the problems found regarding the maintenance of salt density in the conventional salt gradient solar pond, scientists have come up with new methods and ways to increase solubility with temperature. These types of saturated ponds have no diffusion problems and the gradients depend on the temperature of the corresponding layer, as a result the main advantage of such

Solar Ponds

673

a pond is its stabile density gradient and the prevention of vertical diffusion; as a result reducing the pond maintenance costs to minimum rates. Salt gradient solar ponds can also be labeled as long-term thermal energy storage but still nonsalt solar ponds; membrane stratified ponds and shallow solar ponds are more suitable for short-term energy storage situations as the temperature changes in the pond are occurring more rapidly. To establish the performance of these nonsalt solar ponds field tests are conveyed by using the reference data obtained from the results of the experiments and analysis for design of these solar ponds [8].

4.16.4.5.1

Experimental setup of a saturated solar pond

In this study, an experimental solar pond with the area of 0.72 m2 and a depth of 1.10 m was built in Cukurova University in Adana, Turkey. The pond’s bottom and side-wall was insulated by using 0.10 m thickness glass wool. A solar pond consists of two main regions, i.e., outer and inner regions. First, the outer region is called the insulation region to prevent the heat losses by conduction from inner region to surrounding of the pond. Second, the inner region is a large body of salty water with a salinity gradient to prevent heat loss by convection. The body of the region generally consists of three zones (e.g., surface zone, middle zone, and bottom zone). The surface zone is called the upper convective zone (UCZ). UCZ is the fresh water layer at the top of the pond. The middle zone is called the nonconvective zone (NCZ). NCZ is composed of different salty water layers whose density gradually increases toward the bottom of the pond. This zone plays a key role in the solar pond because this zone constitutes a transparent insulating layer to prevent convective heat losses from the bottom zone to the UCZ. In this regard, the size of NCZ is very important to increase the performance of a solar pond so that Husain et al. developed a rational analytical insight for judicious selection of NCZ size considering optimum thermal performance as well as stability aspects [21]. Finally, the bottom zone of the pond is composed of salty water with the highest density. Thanks to this feature, the solar radiation that that reaches the bottom of the pond is absorbed and converted to heat, and stored in the heat storage zone (HSZ). Fig. 13 shows a schematic representation of the experimental solar pond system built in a salt production system. In the inner region of the pond, the ranges of magnesium chloride water density in UCZ, NCZ, and HSZ are 1000–1020 kg/m3, 1030–1150 kg/m3, and 1170–1200 kg/m3, and the thicknesses of the zones are 0.10, 0.50, 0.50 m, respectively. The density distributions are also measured and analyzed by taking samples from at the same point of the temperature sensors. As seen in Fig. 1 the salt gradient protection system is used to protect the density gradient against erosion of the magnesium chloride water in the inner zones of the pond. The protection system was a system based on the natural circulation of water caused by density difference [22].

4.16.4.6

Shallow Solar Ponds

The shallow type solar ponds are solar energy collectors that are designed to supply large amounts of heat for industrial applications at a moderate cost in contrast to fossil fuels. Many investigations have been made on this field in order to use its conversion ability of solar energy into low-grade thermal energy. As the name implies the depth of these types of ponds is very Solar energy Ta

Salt gradient protection system

LUCZ=0.10 m UCZ=1000−1020 kg/m3 Saturated salty water inlet

Holes

LNCZ=0.50 m

NCZ=1030−1150 kg/m3

Temperature sensors

HSZ=1170−1200 kg/m3

LHSZ=0.50 m

Fig. 13 Apparatus used for the experimental setup. Adapted from Bozkurt I, Deniz S, Karakilcik M, Dincer I. Performance assessment of a magnesium chloride saturated solar pond. Renew Energy 2015;78:35–41.

674

Solar Ponds

small compared to salinity solar ponds, typically only a few centimeters, which looks similar to a conventional solar still combined with a blackened tray holding some water in it. The shallow water takes advantage of evaporation of salt water by solar heat and increases the conversion efficiency of the pond. The shallow level is covered with a plastic film in a way that the film is in contact with the top surface of the water and it prevents the cooling effect occurring due to evaporation. Compared to conventional ones it is capable of heating a larger quantity of water with reasonable temperatures, and regarding its simplicity in working it is a promising method for using solar energy efficiently. Usually the water is placed within a bag that is generally constructed from clear upper plastic film and a black lower plastic film. The depth ranges in between 4 and 15 cm and the collection efficiency is directly proportional to water depth and as a result the water temperature is inversely proportional to the water depth. For this system the solar energy is converted to thermal energy by heating the water during the day and is withdrawn from the solar pond before sunset in order to utilize energy for the thermal energy storage [23].

4.16.5

Solar Pond Applications

Solar ponds are employed to work and collaborate with well-established technologies for most of the construction and general operation practices such as construction of earth berms, installation of pond liners, pumping of fluids, and delivery of heat to a load. The maintenance of a pond’s transparency can often be achieved by using similar techniques used for swimming pool maintenance techniques. The details regarding the applications are discussed later in the section under power generation, thermal applications and desalination subsections. The main requirement for a solar pond is establishing a salt gradient must and maintaining this gradient and the transmittance of the pond throughout its operation [16]. Solar energy is collected and stored in solar ponds to be used at temperatures below the boiling point of the lower zone. The cost for the use of this technology is much lower compared to other types of solar energy systems. The disadvantages regarding the solar ponds include the impossibility of mounting them on roofs or tilting for high latitude usage and the heat losses occurring on the earth that make uninsulated small ponds inefficient. By taking these losses into account, it can be seen that systems that contain a water pond of only a few hundred square meters area for conventional houses are not economically competitive compared to other alternatives [24].

4.16.5.1

Thermal Applications

It is estimated that solar pond construction and operating costs show that the cost of pond heat will be two cents per kilowatt hour thermal in locations where salt must be transported and where impermeable plastic liners must be used. Compared to other types of solar systems, this is much less than the usual cost of electric resistance heat and the maintenance costs and times are much less than the cost of heat from propane or fuel oil. For a large scale water heating operation, where electricity or propane is the energy source the pond can be labeled as a promising lower cost alternative. Also for other processes containing heat applications the pond has higher efficiency when used at lower temperatures and may be one of the most valuable energy sources when used in this mode combined with conventional energy sources to reach the necessary temperatures [25].

4.16.5.2

Power Generation

When the heat is used directly low temperature solar heat usually becomes the most favorable energy source compared to other energy sources used to generate electricity. The low efficiency occurring from the solar pond’s thermodynamic conversion to produce electricity excludes solar thermal power except in some special cases. For a 5-MW solar pond peaking power plant it is estimated that electricity can be produced for 10–15 cents/kWh [26]. If the temperature difference is around 501C this leads to a Carnot efficiency of 14% and an actual practical efficiency of around 5%, which means that when power station costs are accounted for, heat must be supplied by the pond at less than one half cent per kWh to yield electricity at 10 cents. But still, for a situation where the cost of heat is very low, there is no demand for low temperature heat as a source and the only use for the pond is for power, providing that it can be produced at low enough cost.

4.16.5.3

Desalination

Desalination can be given as an example for hybrid applications where solar ponds are used. Using the multiflash desalination units along with a solar pond might be a good idea for getting distilled water because the multiflash desalination plant works below 1001C, which can easily be achieved by a solar pond. It will be a creative and useful idea to use this system at places where water is short on supply and salty water is available. According to the theoretical estimations made, 4700 m3 of distilled water can be obtained from a pond of 0.31 km2 area with a multieffect distillation unit. Thermal desalination using a solar pond is one of the most promising solar desalination technologies where the generated thermal energy by the solar ponds is used to drive a desalination plant, and has been investigated by many researchers such as Tabor [27], Tleimat [28], and Posnansky [29]. There are many advantages that this multienergy offers, such as using solar ponds’ ability to trap energy with built-in longterm energy storage capacity, producing three times more energy than the heat produced by burning the same amount of coal in the combustion chamber, and it is pollution free. So by looking at these advantages it can be concluded that the solar pond is an

Solar Ponds

675

efficient source of renewable, environmentally sustainable source for energy that can also be used as a built-in long-term thermal energy storage, which no other solar collection device can match. The implementation of an acceptable means of salt recycling brings a huge advantage for it to be compiled with desalination operations [30].

4.16.6

Thermodynamic Analyses of Solar Ponds

The thermodynamic analysis of the solar pond is conveyed with the use of the experimental data gathered from the experiment in Adana, Turkey, which was mentioned previously in the chapter, and the rate of incident solar radiation, absorption, and transmission of the zone is considered to determine heat losses, and energy efficiencies of the zones accordingly are examined. The data allow pond performance to be obtained experimentally for three representative months: january, May, and August. Then the exergy analyses of the solar pond are performed and compiled with the energy analyses. Once again as mentioned previously in the chapter, the solar pond was built at Cukurova University in Adana, Turkey. The salt water solution is prepared by dissolving the NaCl reagent into fresh water. The thicknesses of the UCZ, NCZ, and HSZ are 0.1 m, 0.6 m, and 0.8 m respectively. The range of salt gradient in the inner zones is such that the density is 1000–1045 kg m 3 in the UCZ, and 1045–1170 kg m 3 in the NCZ, 1170–1200 kg m 3 in HSZ. Temperature variations are measured at the inner and outer zones of the pond. The bottom and the side walls of the pond are plated with iron sheets of 5 mm thickness, and contain glass wool of 50 mm thickness as an insulating layer. The solar pond is situated on a steel base 0.5 m above the ground and insulated with 20 mm thick wood slats positioned on the steel base. Inner and outer sides of the pond are covered with anticorrosion paint [15]. The measurement points are placed on the south side of the inner walls and solar radiation entering the pond with respect the shading area is calculated in the solar ponds. 30 saline water layers make up the inner zones with different densities with a layer thickness of 5 cm. The temperature distributions of the layers with the use of temperature sensors in each zone. Inner zone layers and in the insulated walls of the pond include 16 temperature distributions with the use of data acquisition systems at heights from the bottom of the pond of 0.05, 0.30, 0.55, 0.70, 0.80, 1.05, 1.35, and 1.50 m, and, from the bottom of the pond downwards into the insulated bottom, at 15 and 45 mm, and for heights from the bottom of the side wall of 0, 0.35, 0.65, 0.75, 1.00, and 1.35 m [5].

4.16.6.1

Energy Analysis

Each and every zone included in the solar pond starting from up and going down the solar pond are X1, X2–X1 and X3–X2, respectively. The working solution in the LCZ is stratified due to its high salinity and different density with both concentrations and temperatures increasing linearly with increasing pond depth, and lastly the working solution in the UCZ has uniform and low salinity. Part of the solar radiation incident on the solar pond is absorbed, part is reflected at the surface, and the remaining part is transmitted. Most of the incident ray is transmitted through the layers and part of the transmitted ray that reaches the HSZ is converted to heat and stored there. The absorption by the salty water solutions changes with concentration of the solution [5]. Analysis of an experimental solar pond is generally complicated due to the differences of inner and outer conditions. Here, we consider the following key parameters: zone thicknesses, temperatures in the layers, shading on the layers by the side walls, incident solar radiation absorbed by the layers, incident radiation reaching on the surface, heat losses through the insulated side walls, and thermal conductivity of the solution. To understand the thermal performance of a solar pond, the rates of absorption of the incident solar radiation by zone and the temperature distributions of its regions need to be determined. To realize this, the pond is treated as having three zones, which are separated into 30 layer inner zones. The temperature variations of some layers depend on incident solar radiation on the horizontal surface, rates of absorption by the layers, local climate conditions, pond structure, time, and insulation [31].

4.16.6.2

Energy Efficiency Calculations for the Upper Convective Zone

The reflected radiation from the upper convective zone surface to air and lost where the rest of the incident solar radiation is emitted from the upper convective zone to lower zones. The energy efficiency for the upper convective zone can generally be expressed as Z¼

Qnet Qin

ð1Þ

Here, Qnet is the net heat addition to the pond and equals Qstored, which is defined as Qstored ¼ Qin

Qout ¼ ðQsolar þ Qdown Þ

ðQside þ Qwa Þ

ð2Þ

Here, Qstored is the net heat stored in the UCZ, Qsolar is amount of the net incident solar radiation absorbed by the UCZ, Qdown is the total heat transmitted to the zone from the zone immediately below, Qside is the total heat loss to the side walls of the pond, and Qwa is the total heat lost to the surroundings from the upper layer. Substituting Eq. (1) in to Eq. (2) for the UCZ yields the following expression for the energy efficiency: ZUCZ ¼ 1

fQside þ Qwa g Qsolar þ Qdown

ð3Þ

676

Solar Ponds

ZUCZ ¼ 1

• • • • • • • • • •




A01 Rps ½Tucz

n bEAðUCZ;IÞ ½1

Tside Š þ Uwa A½Tucz

ð1

Tamb Š

δފ þ kA X1 ½Tdown

FÞhðX1



Tucz Š

ð4Þ

o

Tamb is the ambient air temperature, the value of which is taken to be that for the time of year, X1 is the thickness of the UCZ, A01 is the surface area of the painted metal sheet on the side wall (8  0.05 ¼0.4 m2), δ is the thickness of the layer in the UCZ which absorbs incident long-wave solar radiation, E is the total solar radiation incident on the pond surface, A is the upper surface area of the pond, r is the density of the layers in the UCZ, C is the specific heat of the layers in the UCZ, k is the thermal conductivity of the layers in the UCZ, RPS is the thermal resistance of the painted metal sheet surrounding the first layer. Rps ¼

kp ks Sp ks þ Ss kp

ð5Þ

Here SP and Ss are the corresponding thicknesses, kP and kS are thermal conductivities of the paint and iron sheet, lastly b is the fraction of the incident solar radiation that enters the pond, and is expressed as     sinðyi yr Þ 2 tanðyi yr Þ 2 0:4 ð6Þ b ¼ 1 0:6 sinðyi þ yr Þ tanðyi þ yr Þ where yi and yr are the angles of incident and reflected solar radiation. The ratio of the solar energy reaching the bottom of layer I to the total solar radiation incident on to the surface of the pond can be expressed as   ðX1 δÞ hI ¼ 0:727 0:056 ln ð7Þ cos yr Here, AUCZ is the net upper surface area of the UCZ is defined as AUCZ ¼ LW ⌊LL

ðδ þ ðI

1ÞDxÞtanyr m

ð8Þ

where yr is the angle of the reflected incidence, Dx is the thickness of each layer in the UCZ and taken as 0.005 m in the calculations, and LW and LL are the width and length of the pond, respectively.

4.16.6.2.1

Energy efficiency calculations for the nonconvective zone

The part of the incident solar radiation on the surface of the pond is transmitted from the UCZ to the solar radiation incident on the surface of the NCZ. Some part of the rest of incident solar radiation on the NCZ is reflected from the NCZ to the UCZ. Part of the incident solar radiation is transmitted to the HSZ while part of the incident solar radiation is absorbed by the NCZ. The reflected part of the incident solar radiation increases the UCZ efficiency. The solar radiation is absorbed by and transmitted into the NCZ, and part of the absorbed radiation is stored in the zone. So, the NCZ is heated and the zone’s temperature increases. Thus, a temperature gradient occurs in this zone. Heating increases the NCZ efficiency. We can write an energy balance for the NCZ as Qnet ¼ QNCZ;solar þ Qdown

Qup

ð9Þ

Qside

where QNCZ,solar is amount of the solar radiation entering the NCZ that is transmitted from the upper convective zone after attenuation of incident solar radiation in the upper convective zone, and Qup is the heat loss from the NCZ to the above zone. We can then write the energy efficiency for the NCZ as
 Qside þ Qup ð10Þ ZNCZ ¼ 1 QNCZ;solar þ Qdown ZNCZ ¼ 1


kA

DX ½TUCZ




bEAðNCZÞ ½ð1

FÞ½hðX1

 TNCZ Š þ A01 Rps ½TNCZ Tside Š kA δÞ hðX1 δ þ DxފŠ þ DX ½Tdown

 TNCZ Š

ð11Þ

where F is the fraction of incident solar radiation absorbed by the pond’s upper layer and DXNCZ ¼ (X2 X1) is the thickness of the UCZ. Also, A01,NCZ is the surface area of the painted metal sheet on the side walls surrounding of NCZ (8  0.60 ¼ 4.8 m2). We define ANCZ as the net upper surface area of the NCZ that receives the incident solar radiation as ANCZ ¼ LW ⌊LL where I varies from 2 to 14.

ðX1 þ ðI

1ÞDxÞtanyr m

ð12Þ

Solar Ponds 4.16.6.2.2

677

Energy efficiency calculations for the heat storage zone

Part of the solar radiation incident on the solar pond is transmitted through the UCZ and NCZ, after attenuation, to the HSZ. Part of the transmitted solar radiation from the NCZ to the HSZ is reflected from the bottom and the majority of the solar radiation is absorbed in the HSZ. So, the HSZ temperature is increased and a temperature gradient develops in the zone. An energy balance for the HSZ of the solar pond can be written as Qnet ¼ QHSZ;solar

Qbottom

Qup

ð13Þ

Qside

where Qbottom is the total heat loss to the bottom wall from heat storage zone. The energy efficiency for the HSZ of the solar pond then becomes:   Qbottom þ Qup þ Qside ZHSZ ¼ 1 QHSZ;solar n  ARps ½Tdown THSZ Š þ DXAkHSZ THSZ Tup þ A01 Rps ½THSZ
 ZHSZ ¼ 1 bEAðHCZ;IÞ ½ð1 FÞðhðX3 δÞފ

ð14Þ o Tside Š

ð15Þ

where DXHSZ ¼(X3 X2) is the thickness of the HSZ of the pond. Also, A01,HSZ is the surface area of the painted metal sheet on the side walls surrounding the HSZ (taken as 8  0.80 ¼ 6.4 m2). Note that the net surface area of the HSZ is equal to the net surface area at the bottom of the NCZ [32].

4.16.6.2.3

Results of energy analysis

The performance of the solar pond depends on not only the thermal energy flows, but also the incident solar radiation flows (accounting for reflection, transmission, and absorption). Also, shading decreases the performance of the zones. Part of the incident solar radiation is reflected on the surface, some is absorbed by the layer and part is transmitted through the UCZ to the NCZ. The average sunny area of the UCZ is determined to be 3.93 m2, and the average shaded area 0.07 m2. The net average solar radiation incident on the sunny area of the UCZ is calculated for January, May, and August as 439.42 MJ, 2076.88 MJ, and 2042.00 MJ, respectively. The greatest part of the incident solar radiation is transmitted to the NCZ from the UCZ. Part of the incident solar radiation is absorbed by the NCZ layers. The incident solar radiation transmitted from the NCZ to the HSZ is significant and little incident solar radiation is reflected from the NCZ to the UCZ. The average sunny area for the NCZ is found to be 3.13 m2, and the average shading area 0.87 m2. The net average solar radiation on the sunny area of the NCZ is calculated for January, May, and August as 351.54 MJ, 1661.50 MJ, and 1634.05 MJ, respectively. A significant part of the incident radiation reaches the HSZ from the NCZ. This transmitted solar radiation from the NCZ is absorbed in the HSZ, while little of the incident solar radiation is reflected from the HSZ to the upper zones. The average sunny area for the HSZ is found to be 2.63 m2, and the average shaded area 1.37 m2. The net average solar radiation incident on the sunny area of the HSZ is calculated for January, May, and August as 193.34 MJ, 913.83 MJ, and 898.73 MJ, respectively [3]. The primary reason for differences during different months is likely the higher temperature in summer. This change is mainly attributable to the thermophysical property of the salty water, heat losses from the pond to the air, and the absorption and reflection of incident solar radiation on the surface. The reason for the fluctuations in the saline density in the upper convective and nonconvective zones is the increase in saline density of these zones due to the evaporation of water at the upper region. These changes can be reduced by continuously adding fresh water to the top of the pond. When not using one of the salt gradient protection systems for cleaning purposes in a month, significant changes occurred in the nonconvective and upper convective regions. The averaged experimental density variations of salty water versus height from the pond bottom for 12 months show little differences between the density distributions in January, April, and July, due to the temperature changes and evaporation of salty water from the pond. As expected, increasing temperature decreases the density more in the summer months. Heat losses by heat transfer from the pond during a day are determined by calculating the temperature differences for daily profiles of related months. To determine the heat losses from the inside of the solar pond, experimental temperature distribution profiles for the inner zones are obtained. The monthly average temperatures at the respective points are found with use of zone temperatures measured throughout the months. It is clear that the zone temperatures vary with month of year, depending on the environment temperature and incoming solar radiation. Incident solar energy per unit area of surface is directly proportional to the temperatures of the zones generally increase with. The performance is affected with the heat losses occur for each zone. Performance can be improved and the efficiency can be increased with reduced losses. Figs. 11–13 represent the temperature distributions that indicate the temperature of the UCZ maximum and minimum at 35.01C and 10.41C in August and January, respectively. Similarly, the temperature of the NCZ is 44.81C in August and minimum at 13.91C in January where the temperature of the HSZ is maximum at 55.21C in August and minimum at 16.91C in January. The energy stored in the UCZ for January, May, and August to be 3.99 MJ, 59.49 MJ, and 92.90 MJ, respectively. Similarly, the energy stored in the NCZ for January, May, and August to be 311.16 MJ, 143.03 MJ, and 225.43 MJ, respectively, while the energy stored in the HSZ for January, May, and August to be 18.70 MJ, 160.31 MJ, and 252.65 MJ, respectively. The UCZ efficiencies 0.90%, 2.86%, and 4.54% for January, May, and August, respectively. This zone has little effect on the performance of the pond in January, and more impact in May and August. The efficiency of the UCZ is low because of the shading area rather than heat losses. The NCZ efficiencies are seen to be 3.17%, 8.60%, and 13.79% for January, May, and August, respectively. Shading decreases the performance of the NCZ. Shading area also has an important effect

678

Solar Ponds

on the performance of the HSZ, for which the zone efficiencies are seen to be 9.67%, 17.54%, and 28.11% for January, May, and August, respectively. A significant amount of incident solar radiation is absorbed by the HSZ in August and little of the incident solar radiation is reflected from the bottom wall of the pond. Decreasing shading area from the top to the bottom of the pond allows less solar radiation to pass through and decreases the thermal potential of the pond and hence its performance. The performance of the thermal energy storage depends upon the total radiation reaching the pond’s zones. The performance of the heat storage zone can be usefully determined in part using energy efficiencies. But in a solar pond, the stored energy is very low compared to incident solar radiation on the surface of the zones, so the efficiencies are also very low. The efficiencies are low in part due to the low thermal conductivity of the pond filled with salty water. The efficiencies are dependent on the temperatures of the salty water and ambient air. The temperature differences of the zones between January, May, and August alter the inner zone temperatures, the diffusion of salt molecules up from the bottom, and heat losses. This analysis illustrates the effect on pond efficiency of shading by the side wall and absorption, transmission, and the thicknesses of the zones [9]. The maximum energy efficiencies of the inner zones are seen to occur in August, and the minimum efficiencies in January. Although the greatest amount of solar radiation is incident on the upper convective zone, the lowest efficiencies are found for this zone. This is because of the zone’s small thickness and its large heat losses to air from its upper surface. The temperature distribution profiles for the inner zones usually differ, causing the zone efficiencies to differ also. Despite the decrease in solar radiation intensity when it reaches the surface of the NCZ, that zone incurs lower heat losses and thus has a higher efficiency than the UCZ. The temperature distributions thus have an important effect on the performance of the pond. The energy efficiency of the pond is negatively affected by the energy losses due to heat transfer from the UCZ to air. A low fraction of the incident solar radiation is stored in the pond and the UCZ efficiency is negligible especially compared to that of the NCZ. The NCZ efficiency consequently has a greater effect on the performance of the pond. Most of the energy is stored in the HSZ. The inner regions of the pond thus store more energy in August than in January due to the considerable temperature differences between the zones. Heat storage, heat losses, shading areas, and solar radiation absorption should be carefully considered when determining the thermal performance of solar ponds as their effects can be significant [9].

4.16.6.2.4

Exergy analysis

Exergy analysis permits many of the shortcomings of energy analysis of solar pond systems to be overcome, and thus appears to have great potential as a tool for design, analysis, evaluation, and performance improvement. An exergy analysis of each zone is presented in this part of the chapter.

4.16.6.2.5

Exergy analysis for UCZ

The exergy balance for the upper convective zone can be written as Exsolar þ Exg;NCZ ¼ Exr;UCZ þ Ex d;UCZ þ Exa þ Exsw;UCZ

ð16Þ

where Exsolar is the exergy of the solar radiation reaching the UCZ surface, Exg,NCZ is the exergy gained from the NCZ, Exr,UCZ is the recovered exergy of the UCZ for the NCZ, Exd,UCZ is the exergy destruction in the UCZ, Exa,UCZ is the exergy loss from the UCZ to the ambient air, and Exsw,UCZ is the exergy loss through the side walls. Here Exr,UCZ can be written according to Eq. (16) as     Ex d;UCZ þ Ex a þ Ex sw;UCZ ð17Þ Ex r;UCZ ¼ Exti Extl ¼ Ex solar þ Exg;NCZ where Extl is the total exergy losses, including exergy destruction, and Exti is the total exergy input to the UCZ. The exergy of the solar radiation can be expressed as follows: "

 # 4T0 1 T0 4 þ ð18Þ AUCZ Ex solar ¼ Enet 1 3T 3 T The exergy gained from the NCZ can be expressed as Ex g;NCZ ¼ mNCZ Cp;NCZ





Tm;NCZ

TUCZ



 Tm;NCZ T0 ln TUCZ

ð19Þ

where Enet is the net incident solar radiation reaching the UCZ surface; AUCZ is the net surface area of the UCZ; and T is the sun’s surface temperature, taken to be 6000K; mNCZ ¼ rNCZVNCZ is the mass of salty water in the NCZ; rNCZ is the averaged density; and VNCZ is the volume of the salty water in the NCZ (VNCZ ¼ 2.4 m3). The exergy destruction in the UCZ can be written as Ex d;UCZ ¼ T0 DSnet

ð20Þ

where DSnet is the net entropy change of the UCZ, which is DSnet ¼ DSsys þ DSsurr. After substituting each of the entropy change terms, Eq. (20) becomes 



 Qg;NCZ Qsw;UCZ TUCZ Qwa Qsw;UCZ þ þ þ ð21Þ Ex d;UCZ ¼ T0 mUCZ Cp;UCZ ln T0 TUCZ T0 TNCZ T0

Solar Ponds

In addition, we can write the exergy losses to the ambient air and through the side walls as follows: 

 TUCZ Ex a;UCZ ¼ mUCZ Cp;UCZ ðTUCZ Ta Þ T0 ln Ta 

   TUCZ T0 ln Ex sw;UCZ ¼ mUCZ Cp;sw TUCZ Tsw;UCZ Tsw;UCZ

679

ð22Þ ð23Þ

where mUCZ ¼ rUCZVUCZ is the mass of salty water in the UCZ; rUCZ is the averaged density and VUCZ is the volume of the salty water in the UCZ (VUCZ ¼0.4 m3); Cp,UCZ and Cp,sw are the respective specific heats of the UCZ and insulating material; Ta and T0 are the ambient temperature and the reference environment temperature, respectively; and TUCZ, Tsw,UCZ, and Tm,NCZ denote the average temperatures of the UCZ, the side wall, and the nonconvective zone, respectively. We can now define the exergy efficiency for the UCZ as the ratio of the exergy recovered from the UCZ to the total exergy input to the UCZ: cUCZ ¼

4.16.6.2.6

Exr;UCZ ¼1 Ex ti

Exd;UCZ þ Ex a þ Ex sw;UCZ Exsolar þ Ex g;NCZ

ð24Þ

Exergy analysis for NCZ

An exergy balance equation for the flows in the NCZ can be written as Ex r;UCZ þ Exg;HSZ ¼ Exr;NCZ þ Exd;NCZ þ Ex l;NCZ þ Ex sw;NCZ

ð25Þ

where Exr,UCZ is the exergy recovered from the UCZ, Exg,HSZ is the exergy gained from the HSZ, Exr,NCZ is the recovered exergy of the NCZ for the HSZ, Exd,NCZ is the exergy destruction in the NCZ, Exl,NCZ is the exergy loss from the NCZ to the UCZ (which is equivalent to Exg,NCZ), and Exsw,NCZ is the exergy loss through the side walls. Here Exr,NCZ can be expressed using Eq. (25) as     Ex d;NCZ þ Ex l;NCZ þ Ex sw;NCZ ð26Þ Ex r;NCZ ¼ Exti;NCZ Ex tl;NCZ ¼ Ex r;UCZ þ Ex g;HSZ where

 Exg;HSZ ¼ mHSZ Cp;HSZ ðTHSZ

TNCZ Þ

 THSZ T0 ln TNCZ

ð27Þ

Here, mHSZ ¼rHSZVHSZ is the mass of salty water in the HSZ; rHSZ is the average density; and VHSZ is the volume of salty water in the HSZ (VHSZ ¼ 3.2 m3). The exergy destruction in the NCZ can then be written as Ex d;NCZ ¼ T0 ðDSnet;NCZ Þ

ð28Þ

where DSnet,NCZ is the net entropy change of the NCZ, which is DSnet,NCZ ¼ DSsys þ DSsurr. The exergy losses, including the exergy destruction in the NCZ, can be derived as follows: 



 Qg;NCZ Qsw;NCZ Qg;HSZ Qsw;NCZ Tm;NCZ Ex d;NCZ ¼ T0 mNCZ Cp;NCZ ln þ þ þ ð29Þ Tm;NCZ Tm;NCZ T0 T0 T0 

   Tm;NCZ T0 ln ð30Þ Ex l;NCZ ¼ mNCZ Cp;NCZ Tm;NCZ TUCZ TUCZ 

   Tm;NCZ T0 ln ð31Þ Exsw;NCZ ¼ mNCZ Cp;sw Tm;NCZ T sw;NCZ Tsw;NCZ

where Cp,NCZ is the specific heat of the NCZ and THSZ is the temperature of the HSZ. We can now define the exergy efficiency for the NCZ as the ratio of the exergy recovered from the NCZ to the total exergy input to the NCZ: cNCZ ¼

4.16.6.2.7

Ex r;NCZ ¼1 Exti

Ex d;NCZ þ Ex l;NCZ þ Exsw;NCZ Exr;UCZ þ Ex g;HSZ

ð32Þ

Exergy analysis for HSZ

The exergy flows and zone exergy balance can be written as   Ex d;HSZ þ Ex l;HSZ þ Ex sw;HSZ þ Ex b;HSZ ¼ DEx st Ex r;NCZ

ð33Þ

where Exr,NCZ is the recovered exergy from the NCZ for the HSZ, Exd,HSZ is the exergy destruction in the HSZ, Exl,HSZ is the exergy loss from the HSZ to the NCZ, Exsw,HSZ is the exergy loss through the side walls. Exb,HSZ is the exergy loss through the bottom wall and DExst is the exergy stored in the HSZ. Here Exd,HSZ is the exergy destruction in the HSZ, which can be written as Exd;HSZ ¼ T0 ðDSnet;HSZ Þ where DSnet,HSZ is the net entropy change of the HSZ and expressed as DSnet,HSZ ¼ DSsys þ DSsurr. The exergy losses, including exergy destruction within the NCZ, can be written as follows: 

  Qg;HSZ Qsw;HSZ THSZ Qb Ex d;HSZ ¼ T0 mHSZ Cp;HSZ ln þ þ T0 T0 THSZ T0

ð34Þ

ð35Þ

680

Solar Ponds

 THSZ T0 ln Tm;NCZ

ð36Þ

where Cp,HSZ is the specific heat of the salty water in the HSZ. For the side wall, 

   THSZ T0 ln Exsw;HSZ ¼ mHSZ Cp;sw THSZ Tsw;HSZ Tsw;HSZ

ð37Þ

Exl;HSZ ¼ mHSZ Cp;HSZ

 

THSZ

Tm;NCZ



Exb,HSZ ¼Exsw,HSZ due to the fact that both the side wall and the bottom layer have the same insulating materials and are surrounded by ambient air. The exergy efficiency for the HSZ is expressible as the ratio of the exergy stored in the HSZ to the total exergy input to the HSZ, which is essentially the exergy recovered from the NCZ:
 Ex d;HSZ þ Exl;HSZ þ Ex sw;HSZ þ Ex b;HSZ DExst ð38Þ ¼1 cHSZ ¼ Ex r;NCZ Exr;NCZ

4.16.6.2.8

Results of exergy analysis

The exergy content distributions in the zones are then calculated monthly for average temperatures and it is found that the exergy contents are less than the corresponding energy contents. Although energy is conserved, some exergy is destroyed in each zone in addition to the exergy losses to the surrounding air. The lowest exergy contents occur in January and the highest in July. The temperature of the surroundings play a key role since the energy and exergy losses are rejected to the ambient air. The distribution of the energy and exergy contents by month follows the solar irradiation profile closely. The variations of exergy input, exergy recovered, and exergy destruction and losses for the UCZ over the year are taken into consideration other than June when no measurements were made due to maintenance and cleaning. No exergy accumulation is assumed to occur in UCZ as the calculations show it is less than 1%. In July the exergy input is highest, when the incoming solar irradiation is greatest, and the other exergy terms appear to be proportional to the input. The exergy recovered in this zone is transferred to the NCZ. The maximum and minimum exergy recovered are 1681.57 MJ in July and 392.42 MJ in January, respectively. The exergy inputs are equal to the sum of the exergy recovered and exergy destruction and losses. No exergy accumulation is assumed. Also, the exergy is highest in July when solar irradiation is at its greatest and the other exergy terms are directly proportional to the exergy input and it is recovered in this zone and gets transferred to the HSZ. The maximum and minimum exergy recovered are 958.48 MJ and 187.77 MJ in June and January, respectively [5]. The distributions of exergy input, exergy stored, and exergy destruction and losses for the HSZ are taken into consideration over the year. In this zone, exergy is stored instead of recovered. This storage capability allows solar ponds to undertake daily and/or seasonal storage. The exergy input is equal to the sum of the exergy recovered and the exergy destruction and losses. The exergy stored is much smaller than the exergy input and exergy destruction and losses in the HSZ, and reaches a maximum in July of 743.10 MJ and a minimum in January of 169.68 MJ [3].

4.16.7

Case Studies on Solar Ponds

The case studies that have been conveyed for research purposes regarding the effects of different parameters on the solar ponds are gathered in this section and discussed briefly by mainly focusing on each parameter one by one.

4.16.7.1

Case Study 1: Investigation of Turbidity Effect on Exergetic Performance of Solar Ponds

A study on the exergetic performance assessment of a solar pond and experimental investigation of turbidity effect on the system performance is conveyed in this study. There are various types of solar energy applications including solar ponds. One of the significant parameters to consider in the assessment of solar pond performance is turbidity, which is caused by dirt over time. Thus, the turbidity in the salty water decreases solar energy transmission through the zones. In this study, the samples are taken from the three zones of the solar pond and analyzed using a spectrometer for three months. The transmission aspects of the solar pond are investigated under calm and turbidity currents to help distinguish the efficiencies. Furthermore, the maximum exergy efficiencies are found to be 28.40% for the calm case and 22.27% with turbidity effects for the month of August, respectively. As a result, it is confirmed that the solar pond performance is greatly affected by the turbidity effect. In general the effect of turbidity on the performance of the pond through exergy efficiency is investigated. The specific parameter is tackled in terms of theoretical and experimental studies under regular conditions and turbidity currents where the energy and exergy contents are determined and compared for three different zones [1]. For the experimental studies, two solar ponds were tested in parallel during the experiments as turbid and clean ponds in Adana, Turkey. The surrounding environmental factors, particles, algae, and bacterial population’s properties of the turbid pond kept it dirty throughout a year of experiments where the other one was filled by using a clean salty solution with high transmittance. Afterwards, the collected samples were analyzed by using spectrometers and sensors for three months. Thermocouples were placed into the inner zones of the solar pond in order to plot the experimental temperature distributions. Heat storage zone has a height 0.80 m with a density of 1180 kg/m³ with the addition of salt water. The gradient zone is formed with five layers at different concentrations with a layer thickness of 0.20 m. The decreasing between 1100 and 1015 kg/m³ was graded for each layer. So, these constitute nonconvective zone as salty gradient zone. The surface zone, UCZ, is the fresh water layer at the top of

Solar Ponds

681

the pond. The solar pond’s maintenance, density distributions, sustainability of salinity gradient, and salty water clarity are labeled as key factors regarding the heat storage performance of the solar pond. 10 unit transparent plastic hoses with 5 mm diameter and 0.20 m distance on 2 m length are placed on the board to plot the density distributions of the solar pond. Hoses measure the density and transmission of the turbid and clean salty water by using hydrometers and spectrometers. The density of the liquid samples are manually measured with the use of a hydrometer that consists of a thin elongated cylindrical glass bulb. A metric scale is included on the thin side of the solar pond to measure the relative density of the samples. Small lead balls are used to weight the cylindrical glass bulb making the balls float upright to sink in the saline water container with a cylinder that has a volume of 250 ml [1]. The properties of light over a specific portion of the electromagnetic spectrum are measured with the use of a spectrometer [15]. The following salts were studied: mgCl2, Na2SO4, NaNO3, KNO3, Na2CO3, and the quartz–glass sample containers of 50 mm length were of good quality [12]. The measurement samples contained a solution of distilled water and of normal grade salt with a transmission range of 300–1200 nm. The black painted part on the bottom is used to trap heat energy. The experiment was firstly carried out in order to determine the temperature and density variations of the solar pond, and secondly to measure the effect turbidity on the performance of the solar pond by using a spectrometer. Fig. 15 represents the comparison of the density distributions for the turbid and clean water solar ponds. In both Figs. 14 and 15, the differences of the salinity gradient are kept approximately stable for two different solar ponds. The monthly total global solar energy and exergy is given in Fig. 16 for Adana, Turkey. As seen in Fig. 16, the maximum total solar energy in Adana is 713.91 MJ in June, while the minimum is 218.48 MJ in January. The maximum total solar exergy in Adana is 666.32 MJ in June, while the minimum is 204.77 MJ in January.

Solar energy

UCZ

LUCZ = 0.20 m

NCZ

LNCZ = 1.00 m

Exinput

Exup,loss

Exside,loss HSZ

Exdestruction

∆Exstored

LHSZ = 0.80 m

Exdown, loss Fig. 14 The representation of solar pond and exergy fluxes. Adapted from Atiz A, Bozkurt I, Karakilcik M, Dincer I. Investigation of turbidity effect on exergetic performance of solar ponds. Energy Convers Manag 2014;87:351–8.

1200

Aug. Sep. Oct.

Density (kg/m3)

1150 1100 1050 1000 950 900 UCZ HSZ NCZ Turbidity solar pond

HSZ NCZ UCZ Clear solar pond

Fig. 15 The comparison of the density distribution for turbid and clean water solar pond. Adapted from Atiz A, Bozkurt I, Karakilcik M, Dincer I. Investigation of turbidity effect on exergetic performance of solar ponds. Energy Convers Manag 2014;87:351–8.

682

Solar Ponds

800 Energy Exergy

Energy and exergy (MJ/m2)

700 600 500 400 300 200 100 0 Jan.

Feb.

Mar.

Apr.

May

Jun. Jul. Month

Aug.

Sep.

Oct.

Nov.

Dec.

Fig. 16 The monthly total global solar energy and exergy in Adana, Turkey. Adapted from Atiz A, Bozkurt I, Karakilcik M, Dincer I. Investigation of turbidity effect on exergetic performance of solar ponds. Energy Convers Manag 2014;87:351–8.

60

Aug. Sep. Oct.

Temperature (°C)

50 40 30 20 10 0 HSZ

NCZ

UCZ

Turbidity solar pond

HSZ

UCZ NCZ Clear solar pond

Fig. 17 The comparison of the temperature distributions for turbid and clean of the water solar pond. Adapted from Atiz A, Bozkurt I, Karakilcik M, Dincer I. Investigation of turbidity effect on exergetic performance of solar ponds. Energy Convers Manag 2014;87:351–8.

Fig. 17 demonstrates the comparison of the temperature distribution for turbidity and clear solar pond. Turbidity occurred due to decreased solar radiation penetrating the lower convective zone, which affects the temperature of the solar pond. Fig. 17 also illustrates the peak temperature at 30.331C in August. Also, the temperature of the gradient zone is observed to reach a maximum of 40.151C in August. While the temperature of the lower convective zone peaks at 41.871C in August. Secondly, for the clean water of the solar pond, the temperature of UCZ is observed to be maximum at 30.301C in August, a minimum at 21.911C in October. Similarly, the temperature of NCZ is determined to be maximum at 44.281C in August and minimum at 30.451C in October, whereas the temperature of HSZ is measured to be a maximum at 52.421C in August and minimum at 38.621C in October. As expected significant temperature increases were obtained for the clean water of the solar pond. The transmission of the layers of the solar pond is determined measuring the turbid and clean water samples by using the spectrometer. The transmissions of turbid and clean water samples were correlated with each other. The transmission of the clean and turbid water is shown in Figs. 18–20 for three months. As seen in Fig. 18, the transmission of the solar energy is determined for HSZ of the clean and turbid water as 30.20% and 19.35% in August, respectively. As understood from the figure, the reaching solar energy of HSZ is decreased strongly depending on turbidity. Fig. 19 shows the transmission of solar energy for clean and turbid pond in September. As seen in Fig. 19, the transmission of the solar energy is determined for HSZ of the clear and turbid pond as 26.80% and 17.20% in September, respectively. Similarly, as seen in Fig. 20, the transmission of the solar energy is determined for HSZ of the clean and turbid water of the pond as 24.20% and 15.40% in October, respectively. Figs. 21 and 22 show the variations of the exergy input, stored, destruction, and losses of the clean and turbid water of the pond. As seen in the figures, the exergy stored of the solar pond for clean and turbid water appear to be maximum 63.67 MJ and

Solar Ponds

683

100 90

Transmission (%)

80 70 60 50 40 30 20 Clear Turbidity

10 0 0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

Height form the bottom (m) Fig. 18 The transmission of the clear and turbid water in the pond in August. Adapted from Atiz A, Bozkurt I, Karakilcik M, Dincer I. Investigation of turbidity effect on exergetic performance of solar ponds. Energy Convers Manag 2014;87:351–8.

100 90

Transmission (%)

80 70 60 50 40 30 20 Clear Turbidity

10 0 0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

Height form the bottom (m) Fig. 19 The transmission of the clear and turbid pond in September. Adapted from Atiz A, Bozkurt I, Karakilcik M, Dincer I. Investigation of turbidity effect on exergetic performance of solar ponds. Energy Convers Manag 2014;87:351–8.

33.29 MJ in August, and to be minimum 29.58 MJ and 14.65 MJ in October, respectively. As seen in the figures, the exergy input is higher in the clean water than in the turbid water of the pond. The turbidity in the solar pond has negative effect on solar energy transition in the layers. The performance of the solar pond is low because the reaching solar energy of HSZ is much smaller than the incident solar radiation on the surface. To increase the reaching solar energy of HSZ, the turbidity should be decreased. As seen in Fig. 23, the maximum exergy efficiencies were found to be 28.40% and 22.27% for clean and turbid water in August, respectively. Furthermore, the minimum exergy efficiencies were found to be 21.51% and 15.98% for clean and turbid water in October, respectively. The turbidity of the solar pond has an important effect on exergy efficiency. If the salty water of the solar pond is kept clean, the solar pond stores more exergy. In this study, two solar ponds (one clean and one turbid) were employed to experimentally investigate the turbidity effect on the solar pond performance through exergy efficiency under various weather conditions and concentrations. In this regard, various thermal and concentration measurements are performed. The molar and absorption coefficients of each layer are calculated using the experimental percentage transmission in order to calculate according the general transmission function, which is found to be influencing the exergetic efficiency. The exergy efficiencies are expressed using exergy balance equations for the inner zones.

684

Solar Ponds

100 90

Transmission (%)

80 70 60 50 40 30 20 Clear Turbidity

10 0 0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

Height form the bottom (m) Fig. 20 The transmission distributions of the turbid and clear water of the pond in October. Adapted from Atiz A, Bozkurt I, Karakilcik M, Dincer I. Investigation of turbidity effect on exergetic performance of solar ponds. Energy Convers Manag 2014;87:351–8.

250

Exergy input Exergy stored Exergy destruction and losses

Exergy (MJ)

200 150 100 50 0 August

September Month

October

Fig. 21 Variations of the exergy input, stored, destruction, and losses of the clean water of the solar pond. Adapted from Atiz A, Bozkurt I, Karakilcik M, Dincer I. Investigation of turbidity effect on exergetic performance of solar ponds. Energy Convers Manag 2014; 87:351–8.

160

Exergy input Exergy stored Exergy destruction and losses

140 Exergy (MJ)

120 100 80 60 40 20 0 August

September Month

October

Fig. 22 Variations of the exergy input, stored, destruction, and losses of the turbid water of the solar pond. Adapted from Atiz A, Bozkurt I, Karakilcik M, Dincer I. Investigation of turbidity effect on exergetic performance of solar ponds. Energy Convers Manag 2014; 87:351–8.

Solar Ponds

Exergy efficiency (%)

30

685

Clear Turbidity

25 20 15 10 5 0 August

September Month

October

Fig. 23 Exergy efficiencies of the clear and turbid water of the solar pond. Adapted from Atiz A, Bozkurt I, Karakilcik M, Dincer I. Investigation of turbidity effect on exergetic performance of solar ponds. Energy Convers Manag 2014;87:351–8.

The following concluding remarks are extracted from this study:

• • •

The differences between turbid and clean salty waters for the storage zone of the percentage transmissions (DT%) are found to be 10.85 T% in August, 9.60 T% in September, and 8.80 T% in October, and the temperatures (DT) 10.551C in August, 7.51C in September, and 5.901C in October during the three months. The turbidity reduces the percentage transmission (T%) and hence the solar radiation reaching the HSZ and the exergy efficiency of the pond. The exergy efficiency differences between the clean and turbid salty waters for the HSZ are found to be 6.13% in August, 6% in September, and 5.53% in October.

In summary, the exergetic efficiencies depend significantly on the turbidities of the zones during the three months because the attenuation in the turbid salty water increases more sharply than the clean salty water in the inner zones of the pond. All these affect the amount of heat storage in the HSZ [1].

4.16.7.2

Case Study 2: Performance Assessment of a Solar Pond With and Without Shading Effect

In this study, an experimental investigation of energy distribution, energy efficiency, and ratios of the energy efficiency with respect to shading effect on each zone of a small rectangular solar pond is presented. The system is filled with salty water in order to form upper convective, nonconvective, and lower convective zones. A data acquisition device is used to measure and record the hourly temperatures at various locations in different solar pond zones (distributed vertically within and at the bottom of the pond, and horizontally and vertically within the insulated side-walls). A shading model is developed to gain a more profound understanding of the energy performance of the pond. The model results of the each zone are compared with and without shading effect, based on the corresponding energy efficiencies. The shading surface area of the zones does not contribute to the thermal performance of the pond but it takes place in nonsunny area in the zones by shading. Thus, the efficiency of the solar pond decreases with increasing the shading area. The energy efficiencies of the inner zones with and without the shading effect for each zone in the energy analysis are specified as the average representative solar energy for each month of the year. The highest energy efficiencies for the cases with and without shading area are found for the month of August to be 4.22% and 4.30% for the upper convective zone, 13.79% and 16.58% for the nonconvective zone, and 28.11% and 37.25% for the lower convective zone, respectively. The results confirm that the solar pond storage efficiency can be increased by eliminating the effect of shading area. Moreover, the ratios of shading effect are found to be 0.651 at the lower convective zone, 0.279 at the nonconvective zone, and 0.068 at the upper convective zone [33]. The energy efficiency for each component in the system is determined regarding the effects of shading and energy losses. Energetic performance of system components is determined by the shading effect, its ratios and heat losses in the system. The case study aims to investigate the solar pond performance with and without shading effect and comparison of the energy efficiencies for the upper convective zone, nonconvective zone, and lower convective zones, as well as determination of the shading coefficients each zone of the experimental solar pond. In the experimental work, a solar pond with a surface area of 2 m  2 m and a depth of 1.5 m was constructed at Cukurova University in Adana, Turkey and was used for experimental purposes. Temperatures of different parts of the solar pond were measured during different hours in the day at the bottom and side-walls of the pond. The bottom and the side-walls of the pond were plated with the iron sheets in 0.005 m thickness, and in between with a glass wool of 50 mm thickness as the insulating layer [33]. Fig. 24 illustrates shading areas on the inner zones of the solar pond. The saline water layers with various densities made up the inner zones. 16 temperature sensors were used in the temperature measurements, the sensors were placed into the inner zones and

686

Solar Ponds

m

nt ide

bea

Inc Normal

z

r Ash,UCZ

fs 0.1 m 0.6 m

UCZ

I=2

Ash,NCZ NCZ

I=9

rf SI

0.8 m

Ash,HSZ LCZ

I=23

Anet,UCZ Anet,NCZ North Anet,HSZ 2m

2m Fig. 24 Schematic representation of the rectangular solar pond. Adapted from Karakilcik M, Dincer I, Bozkurt I, Atiz A. Performance assessment of a solar pond with and without shading effect. Energy Convers Manag 2013;65:98–107.

the insulated walls of the pond. The temperature distribution profiles of these parts of the pond at any time were experimentally acquired by a data acquisition system. The temperature distributions of various regions were measured with the use of several temperature sensors, which were also placed at starting heights from the bottom, at 0.05, 0.30, 0.55, 0.70, 0.80, 1.05, 1.35, and 1.50 m heights from the bottom downwards into the insulated bottom, at 15 and 45 mm and into the side-walls, the heights from the bottom, at 0, 0.35, 0.65, 0.75, 1.00, and 1.35 m [1]. Data recording, monitoring, and processing systems were used for the data acquisition system, which was connected to a computer. The temperature sensors with a range of 651C to þ 1551C and a measurement accuracy of 0.11C were used at the inner zones and insulated side-wall of the pond to measure the temperature. A hydrometer measured the experimental density changes. The slim hoses were placed into the inner zones to measure the density distributions of various layers. Also a pyranometer was used to measure the solar energy data, hourly average air, and daily average insulator temperatures taken from a local meteorological data as input parameters for the modeling part below were used; further information on experimental system and measurement details, as well as some thermophysical properties of materials and fluids are available elsewhere [17]. As previously mentioned, in order to understand the real performance of a solar pond one needs to study the effect of shading area for each zone. The solar pond efficiencies with and without shading areas were investigated for the zones of a small rectangular solar pond. The incident solar beam reaching the pond surface enters in as to be absorbed and transmitted by refraction. The part of this transmitted beam reaches the highly dense bottom zone (LCZ) of the pond and most of the incident beam is transmitted through the layers, then it is then converted into thermal energy and stored in there.

4.16.7.2.1

Shading area analysis

The angle that the refracted ray makes with the normal line, which is called the angle of refraction, defined by the Snell law as yrf ¼ sin 1(1.33sinyi), where yi is called the incidence angle, which is equal to the zenith angle (yz), is the angle between the normal of the surface of the solar pond and incident solar radiation and is defined as yz ¼ cos 1[cos(δd)cos(j)cos(yh) þ cos(δd) cos(j)]. Here δd is declination angle which can generally be calculated by the Cooper equation as δd ¼23.45sin[360(284 þ n)/ 365]. (Here, n is any day of the year) [28]. j is calculated according to latitude angle that is defined as 90ojo þ 90, which is the solar elevation angle and has a plus sign for the Northern hemisphere and a minus sign for the Southern hemisphere. We use 351180 East longitude and 361590 North latitude for the location of the system at the Cukurova University in Adana, Turkey. yh is the hour angle which yh is equal to zero while the sun is at the highest point in the sky at 12 pm and its value in the morning becomes positive ( þ ) and also in the afternoon becomes negative ( ) [10]. The shading area for the rectangular solar pond is defined as Ash ¼ Lw SI

ð39Þ

where Lw is the width of the rectangular small solar pond. Dx is the thickness of the layer, SI is the shading length of Ith layer and defined by [17] as SI ¼ ½ðδ þ ðI

1ÞDxÞtanyrf Š

ð40Þ

where I varies from 1 to 30. SI is calculated by using the depth from the pond surface and the angle of refraction (yrf). The angle of refraction is determined by using Snell law and incidence angle (yi).

Solar Ponds 4.16.7.2.2

687

Shading area for the UCZ

The UCZ is occurred from two layers and varies from 1 to 2. The average shading effect SI for I ¼2 can be determined as Ash;ucz ¼ Lw ½SI ¼ 2 Š ¼ Lw ½ðδ þ DxÞtanyz Š

ð41Þ

The net unshaded area for UCZ is defined as Aucz ¼ Lw ½Ll

SI ¼ 2 Š ¼ Lw ⌊Ll

ðδ þ DxÞtanyz m

ð42Þ

where Dx is the thickness of each layer in the UCZ and taken as 0.005 m in the calculations.

4.16.7.2.3

Shading area for the NCZ

The nonconvective zone (NCZ) has 12 layers, varying from 3 to 14. The average shading area for I¼ 7 in NCZ becomes: Ash;NCZ ¼ Lw ½ðδ þ 6DxÞtanyz Š

ð43Þ

The average area of the NCZ is the effective area that receives incident solar radiation and is defined without shading effect as ANCZ ¼ Lw ½Ll

4.16.7.2.4

ðδ þ 6DxÞtanyz Š

ð44Þ

Shading area for the LCZ

The shading area for the LCZ consists 16 layers (I¼ 16) as Ash;LCZ ¼ Lw ½ðδ þ 15DxÞtanyz Š

ð45Þ

The average area of the LCZ is the effective area that receives incident solar radiation and is defined without shading effect as ALCZ ¼ Lw ½Ll

ðδ þ 15DxÞtanyz Š

ð46Þ

The total surface area of the UCZ, NCZ, and HSZ including the shading area each zone of the solar pond is given as At;UCZ ¼ At;NCZ ¼ At;LCZ ¼ Lw Ll

ð47Þ

where Lw and Ll are the width and length and as taken 2 m of the solar pond.

4.16.7.2.5

Energy analysis

The energy efficiencies of the all the zones covered using the rectangular solar pond for comparison with the corresponding with and without shading effect on energy efficiencies, where the solar pond zones will be calculated through an energy analysis. The efficiencies are then calculated and compared for the case with shading effect and without shading effect.

4.16.7.2.6

Upper convective zone (UCZ)

The ratio of the heat stored in the upper convective zone to the heat entering the upper convective zone is defined as the shading effect on energy efficiency for the charging period was defined as. The net energy efficiency with shading effect for the UCZ is formulated as
   A01;UCZ Rps TUCZ Tsw;UCZ þ Uwa AUCZ ðTUCZ Ta Þ Qst;UCZ Qsw;UCZ þ Qwa o ð48Þ ¼1 ¼1 n ZUCZ ¼ Qin;UCZ Qns;UCZ þ QNCZtoUCZ w AUCZ ðTNCZ TUCZ Þ bEðAUCZ Þ½1 ð1 FÞhðXI δފ þ kDX UCZ

where Qst,UCZ is the heat energy stored in the UCZ, Qin,UCZ is the input energy to the UCZ, Qsw,UCZ is the heat loss from side walls to outside, Qwa is the heat loss from upper layer to air. Qns UCZ is the net solar energy to reach the surface of the upper layer and QNCZtoUCZ is the thermal energy transfer from the NCZ to the UCZ. A01,UCZ is the surface area of the painted metal sheet on the side walls (8  0.05 ¼ 0.40 m2); TUCZ is the temperature of the UCZ, Tsw,UCZ is temperature of the side wall of the UCZ, Uwa is overall heat transfer coefficient from the UCZ to air, AUCZ is the net area (including the shading area) of the UCZ, TUCZ is the temperature of the UCZ, Ta is the average air temperature. kw is the thermal conductivity of the layers in the UCZ. DXUCZ is the thickness of UCZ as the value taken for the time of year considered. TNCZ is the temperature of the NCZ. E is the total solar radiation incident on the pond surface, δ is the thickness of the layer in the UCZ that absorbs the long-wave solar incident radiation, F is the absorbed energy fraction at a region of the δ-thickness and Rps is the thermal resistance of the painted metal sheet surrounding the first layer and can be written as Rps ¼ ⌊(kpks)/(SPks þ kpSs)m. Here, kp and kS are thermal conductivities of the paint and iron sheet and Sp and SS are the corresponding thicknesses. XI is the thickness of I layer in UCZ of the pond. The ratio of the solar energy reaching the bottom of layer I to the total solar radiation incident falling on the surface of the pond, hI ¼ 0:727 0:056 ln⌊ðXI δÞ=ðcosyrf Þm as given by Bryant and Colbeck [34]. b is the fraction of the incident solar radiation that enters the pond, and is written as     sin yi sin yrf 2 tan yi tan yrf 2 0:4 ð49Þ b ¼ 1 0:6 sin yi þ sin yrf tan yi þ tan yrf where yi and yrf are the angles of incident and refraction solar radiation. The ratios of incoming solar radiations for different angles are calculated. The total energy efficiency without shading effect of the UCZ is defined as Zt;UCZ ¼

Qt;st;UCZ ¼1 Qt;in;UCZ

Qsw;UCZ þ Qwa Qns;UCZ þ Qshs;UCZ þ QNCZtoUCZ

688

Solar Ponds

¼1

n


 A01;UCZ Rps Tt;UCZ

bEðAt;UCZ Þ½1

ð1

   Tt;sw;UCZ þ Uwa At;UCZ Tt;UCZ Ta o kw At;UCZ  FÞhðXI δފ þ DX Tt;NCZ Tt;UCZ UCZ

ð50Þ

where Qt,st,UCZ is the total heat energy stored in the UCZ, Qt,in,UCZ is the total input energy to the UCZ, Qshs,UCZ is the shading area solar energy in the UCZ. Tt,UCZ is the total average temperature of the UCZ, Tt,sw,UCZ is the total average temperature of the side wall of the UCZ, At,UCZ is the total average area of the UCZ. Tt,NCZ is the total average temperature of the NCZ and Tt,UCZ is the total average temperature of the UCZ. The shading efficiency ratio (SER) for the UCZ is defined as Zsh;UCZ Zt;UCZ ZUCZ SER UCZ ¼ ¼ ð51Þ Zt;sh Zsh;UCZ þ Zsh;NCZ þ Zsh;LCZ where Zt,sh is the total efficiency of the shading areas of the solar pond. The difference between the efficiencies without and with shading effects is written as Zsh,UCZ ¼ Zt,UCZ ZUCZ.

4.16.7.2.7

Nonconvective zone (NCZ)

With and without shading effect on charging period was defined as the ratio of the heat stored in the nonconvective zone to heat entering the NCZ. The energy efficiency with shading effect is defined as ZNCZ ¼

¼1

Qst;NCZ ¼1 Qin;NCZ

QNCZtoUCZ þ Qsw;NCZ Qns;NCZ þ QLCZtoNCZ

n o   k ANCZ TUCZ Þ A01;NCZ Rps TNCZ Tsw;NCZ þ w;NCZ ðDXNCZ Þ ðTNCZ n o k ANCZ bEANCZ ½1 ð1 FÞhðX2 δފ þ w;NCZ TNCZ Þ ðDXLCZ Þ ðTLCZ

ð52Þ

where Qst,NCZ is the heat energy stored in the NCZ. Qin,NCZ is the input energy to the NCZ. QNCZtoUCZ is the heat loss from the NCZ to the UCZ. Qsw,NCZ is the heat loss from side walls to outside. Qns,NCZ is the net solar energy to reach the surface of the NCZ. QLCZtoNCZ is the thermal energy transfer from the LCZ to the NCZ. A01,NCZ is the surface area of the painted metal sheet on the side walls (and taken as 8  0.60¼ 4.8 m2); TNCZ is the temperature of the NCZ, Tsw,NCZ is temperature of the side wall of the NCZ, TNCZ is the temperature of the NCZ, TUCZ is the temperature of UCZ. kw,NCZ is the average thermal conductivity of the layers in the NCZ. ANCZ is the net area (with shading area) of the UCZ, DXNCZ ¼(X2–X1) is the thickness of NCZ, DXLCZ ¼(X3–X2) is the thickness of the LCZ. X1 is the thickness from bottom of UCZ to upper surface, and X3 is the thickness from bottom of the LCZ to upper surface of the pond, and X2 is the thickness from the NCZ to upper surface of the pond. The total energy efficiency without shading effect of the NCZ is defined as Zt;NCZ ¼

¼1

Qt;st;NCZ ¼1 Qt;in;NCZ

n  A01;NCZ Rps Tt;NCZ n bEAt;NCZ ½1 ð1

Qt;NCZtoUCZ þ Qt;sw;NCZ Qns;NCZ þ Qshs;NCZ þ Qt;LCZtoNCZ o  k At;NCZ  Tt;NCZ Tt;UCZ Tt;sw;NCZ þ w;NCZ ðDXNCZ Þ  o kA FÞhðX2 δފ þ ðDXt;NCZ Tt;LCZ Tt;NCZ LCZ Þ

ð53Þ

where Qt,st,NCZ is the total thermal energy storage of the NCZ. Qt,in,NCZ is the total solar energy to reach the surface of the NCZ. Qt, is the total thermal energy transfer from the NCZ to the UCZ, Qt,sw,NCZ is the total heat loss from the NCZ to side walls, Qns,NCZ is the total solar energy on the surface of the LCZ, Qshs,NCZ is the solar energy to reach shading area surface of the NCZ, Qt, LCZ toNCZ is the total heat transfer from the LCZ to the NCZ, Tt,NCZ is the total temperature of the NCZ. Tt,sw,NCZ is the total temperature of the sides wall of the NCZ, Tt,UCZ is the total average temperature of the UCZ, and Tt,LCZ is the total average temperature of the LCZ. The shading efficiency ratio (SER) for the nonconvective zones: Zsh;NCZ Zt;NCZ ZNCZ SER NCZ ¼ ¼ ð54Þ Zsh;total Zsh;UCZ þ Zsh;NCZ þ Zsh;LCZ NCZ toUCZ

where Zsh.NCZ is the shading efficiency in the NCZ of the solar pond.

4.16.7.2.8

Lower convective zone (LCZ)

With and without shading effect on charging period was defined as the ratio of the heat stored in the lower convective zone to heat entering the LCZ. The energy efficiency with shading effect is defined as ZLCZ ¼ n

 A01;LCZ Rps TLCZ

Qst;LCZ ¼1 Qin;LCZ

Qdw;LCZ þ Qsw;LCZ þ QLCZtoNCZ Qns;LCZ

 k ALCZ Tsw;LCZ þ w;LCZ ðDXLCZ Þ ðTLCZ

 TNCZ Þ þ Adw;LCZ Rps TLCZ

Tdw;LCZ

o

ð55Þ fbEALCZ ½1 ð1 FÞhðX3 δފg where Qst,LCZ is the stored heat energy in the LCZ, Qin,LCZ is the input energy in the LCZ, Qdw,LCZ is the heat losses from LCZ to down wall of the pond, Qsw,LCZ is the heat losses from side walls to outside of the LCZ, QLCZ toNCZ is the thermal energy transfer from LCZ to NCZ. Qns,LCZ is the net solar energy to reach on the surface of the LCZ. A01,LCZ is the surface area of the painted metal sheet on the side walls of the LCZ (and taken as 8  0.80 ¼ 6.4 m2), TLCZ is the temperature of the LCZ. Tsw,LCZ is the temperature ¼1

Solar Ponds

689

of the side walls of the LCZ, kw,LCZ is the average thermal conductivity of the layers in the LCZ, At,dw,LCZ is the surface area of the painted metal sheet on the down wall (and taken as 2  2 ¼ 4 m2), Tdw,LCZ is the temperature of the bottom wall of the LCZ, ALCZ is the net area of the LCZ. The total energy efficiency without shading effect of the LCZ is defined as Zt;LCZ ¼

¼1

n  A01;LCZ Rps Tt;LCZ

Qt;st;LCZ ¼1 Qt;in;LCZ

Qt;dw;LCZ þ Qt;sw;LCZ þ Qt;LCZtoNCZ Qt;LCZ

   k At;LCZ  Tt;LCZ Tt;NCZ þ At;dw;LCZ Rps Tt;LCZ Tt;sw;LCZ þ w;LCZ ðDXLCZ Þ
 bEAt;LCZ ½1 ð1 FÞhðX3 δފ

Tt;dw;LCZ

o

ð56Þ

where Qt,st,LCZ is the total stored thermal energy, Qt,in,NCZ is the total solar energy to reach the surface of the NCZ, Qt,dw,LCZ is the gross heat loss from LCZ to down wall, Qt,sw,LCZ is the heat loss from LCZ to side wall. Qt,LCZ toNCZ is total thermal energy transfer from LCZ to NCZ, Qt,LCZ is the total solar energy falling on the surface of LCZ. Where Tt,LCZ is the total averaged temperature of the LCZ, Tt,sw,LCZ is the total averaged temperature of the side wall of LCZ, At, LCZ is averaged total area of the LCZ, Tt,dw,LCZ is the total averaged temperature of the down wall. The shading efficiency ratio for the lower convective zone: SER LCZ ¼

Zsh;LCZ Zt;LCZ ZLCZ ¼ Zt;sh Zsh;UCZ þ Zsh;NCZ þ Zsh;LCZ

ð57Þ

where Zsh,LCZ is the energy efficiency of shading area in the LCZ of the solar pond. An experiment has been conveyed to investigate the effect of shading on the energy efficiency of the each zone in order to demonstrate the effect of shading on the thermal performance of the solar pond. The incident radiation, zone thicknesses, shaded surface area of the zones, and heat losses from upper surface area, bottom wall and side walls are the factors that determine the temperature of each zone. So, to achieve higher efficiency and stability of the pond and increase the performance of the pond, the zone thicknesses are adjusted with the use of careful design parameter selections and using incoming solar radiation reaching the zones is increased by eliminating shading. The efficiencies for each layer of the zones for a real insulated solar pond is determined with the use of the experimental data. Another important parameter that plays a crucial role in practical applications is the energy efficiency of the inner zones of a solar pond. The shading effect in the zones and losses to the surroundings cause the energy efficiencies to reduce and vary from zone to zone throughout the pond. Lastly it is crucial to work with the true magnitudes of these shading effects and losses for performance improvement studies for the future [35].

4.16.8

Future Directions

Regarding the future development of solar ponds there are still some problems to overcome such as the implementation of salt recycling. This is a substantial point as it will be of interest for the consumers that may be interested in using a solar pond as an energy source. One of the greatest advantages the solar ponds have in store is that they can be used as a built-in long-term thermal storage, which no other solar collection device can match. Many of the problems have been sorted out regarding the solar ponds with the research made in the field and the performance can easily be predicted but still some improvements regarding their efficiency should be discussed further in upcoming research [8]. As shown in Fig. 25, after the discovery of each solar pond as mentioned in the historical background section of the chapter, scientists and engineers started to work on ways to use solar ponds to produce electricity by conveying experiments, trials, and designing multistaged energy systems to make use of the solar ponds as efficiently as possible for hybrid applications.

in

so

lar

po

nd

te

ch

no

log

y

Integrated multigeneration systems

Pr

og re

ss

Hybrid applications

Advanced applications Discovery of solar pond types Fig. 25 Flowchart of the improvements and the future of solar pond technology.

690

Solar Ponds

4.16.9

Closing Remarks

As mentioned throughout the chapter in the past decade many advances and researches have been made in order to understand the basic phenomena regarding solar ponds. Amongst all types salt-gradient solar ponds have been labeled and demonstrated as the most commonly used types to work in many different climates and appear to have economic potential in a wide variety of thermal and power generation applications that can be affected by temperature, salinity, transmittance, and soil quality. With researches made up until now, the thermal behavior, including the design parameters and diverse aspects of heat loss to the ground, is now relatively well understood. Also a good understanding of gradient zone stability exists and a good understanding of the fundamentals of zone is available for existing solar pond designs. Different instrumentation has been developed in order to better study the aspects of solar ponds both in the laboratory and in the field. Several alternative solar pond designs have been shown to have good potential. Even though the past researches can be labeled as successful, there are still important problems that need to be solved before the solar ponds can successfully compete in the solar energy industry as a commercially sold system. Many experimental setups have been built to verify the theories and procedures based on results obtained in small scaled experimental solar ponds, which require operation and monitoring of larger scaled ponds to ensure that the scale dependence is not affecting the results in order to develop operating techniques that will also work in these large scaled solar ponds. Regarding the energy and exergy analyses carried out throughout the chapter for an insulated salt gradient solar pond that is located in Cukurova University, Adana, Turkey seems to strongly affect the pond’s performance by the temperature of the lower convective zone and the temperature profile with respect to pond depth. The temperature profiles plotted with respect to pond depth for the sunny areas of the lower convective zone are sensitive to wall shading and the presence of insulation, heat losses from the sides and bottom of the pond are negligibly small. Heat losses from upper zone, bottom and side walls, reflection, and shading areas in the NCZ and HSZ should be decreased in order to increase the efficiency for the storage zone of the pond. The incident radiation, zone thicknesses, shading areas of the zones, and overall heat losses seem to have an effect on the temperature of each layer of the solar pond. There are methods that can be used to maximize the solar pond’s performance such as optimizing the zone thicknesses and setting design parameters so that the incoming solar radiation penetrating the zones is increased.

References [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14] [15] [16] [17] [18] [19] [20] [21] [22] [23] [24] [25] [26] [27] [28] [29] [30] [31] [32] [33] [34] [35]

Atiz A, Bozkurt I, Karakilcik M, Dincer I. Investigation of turbidity effect on exergetic performance of solar ponds. Energy Convers Manag 2014;87:351–8. Dinçer ˙I, Rosen MA. EXERGY: energy, environment and sustainable development. Amsterdam: Elsevier Science; 2012. Dincer I, Rosen M. Thermal energy storage systems and applications; 2011. El-Sebaii AA, Ramadan MRI, Aboul-Enein S, Khallaf AM. History of the solar ponds: a review study. Renew Sustain Energy Rev 2011;15(6):3319–25. Karakilcik M, Dincer I. Exergetic performance analysis of a solar pond. Int J Therm Sci 2008;47(1):93–102. Dinçer ˙I, Rosen MA. Energy and exergy analyses of thermal energy storage systems. Therm Energy Storage 2010;1038(December 1998):233–334. Dincer I, Rosen M. Exergy analysis of renewable energy systems; 2013. Kaushika ND. Solar ponds: a review. Energy Convers Manag 1984;24(4):353–76. Karakilcik M, Dincer I. Investigation of exergy ratios of a solar pond. In: Progress in exergy, energy, and the environment; 2014. p. 267–78. Bernad F, Casas S, Gibert O, Akbarzadeh A, Cortina JL, Valderrama C. Salinity gradient solar pond: validation and simulation model. Sol Energy 2013;98(PC):366–74. Valderrama C, et al. Solar energy storage by salinity gradient solar pond: pilot plant construction and gradient control. Desalination 2011;279(1–3):445–50. Lund PD, Keinonen RS. Radiation transmission measurements for solar ponds. Sol Energy 1984;33(3-4):237–40. Jaefarzadeh MR. Thermal behavior of a small salinity-gradient solar pond with wall shading effect. Sol Energy 2004;77(3):281–90. Velmurugan V, Srithar K. Prospects and scopes of solar pond: a detailed review. Renew Sustain Energy Rev 2008;12(8):2253–63. Karakilcik M, Dincer I, Rosen MA. Performance investigation of a solar pond. Appl Therm Eng 2006;26(7):727–35. Valderrama C, Luis Cortina J, Akbarzadeh A. Solar ponds. In: Letcher TM, editor. Storing energy: with special reference to renewable energy sources. Amsterdam: Elsevier; 2016. p. 273–89. Karakilcik M, Kiymaç K, Dincer I. Experimental and theoretical temperature distributions in a solar pond. Int J Heat Mass Transfer 2006;49(5-6):825–35. Tabor H. Solar ponds. Sol Energy 1981;27(3):181–94. Shaffer LH. Viscosity stabilized solar ponds. In: proc. international solar energy society congress; 1975. p. 1171–5. Taga M, Matsumoto T, Ochi T. Studies on membrane viscosity stabilized solar pond. Sol Energy 1990;45(6):315–24. Husain M, Sharma G, Samdarshi SK. Innovative design of non-convective zone of salt gradient solar pond for optimum thermal performance and stability. Appl Energy 2012;93:357–63. Akbarzadeh A, Macdonald RWG. Introduction of a passive method for salt replenishment in the operation of solar ponds. Sol Energy 1982;29(1):71–6. Sorour MM, Estafanous SF. Performance of Shallow Solar Ponds. Int J Sol Energy 1986;4(6):335–51. Mahian O, Kianifar A, Kalogirou SA, Pop I, Wongwises S. A review of the applications of nanofluids in solar energy. Int J Heat Mass Transfer 2013;57(2):582–94. Duffie JA, Beckman WA. Solar engineering of thermal processes. 4th ed. New York: Wiley; 2013. Ranjan KR, Kaushik SC. Thermodynamic and economic feasibility of solar ponds for various thermal applications: a comprehensive review. Renew Sustain Energy Rev 2014;32:123–39. Tabor H. Solar ponds as heat source for low-temperature multi-effect distillation plants. Desalination 1975;17(3):289–302. Tleimat BW, Howe ED. Comparative productivity of distillation and reverse osmosis desalination using energy from solar ponds. Trans. ASME J Sol Energy Eng 1982;104 (4):299–304. Posnansky M. Technical and economical aspects of solar desalination with particular emphasis on solar pond powered distillation plants. Desalination 1987;67(C):81–95. Saifullah AZA, Iqubal AMS, Saha A. Solar pond and its application to desalination. Asian Trans Sci Technol 2012;2(3):1–25. Atiz A, Karakilcik M, Bozkurt I, Dincer I. Investigation of effect of using evacuated tube solar collector on solar pond performance; 2015. Appadurai M, Velmurugan V. Performance analysis of fin type solar still integrated with fin type mini solar pond. Sustain Energy Technol Assessments 2015;9:30–6. Karakilcik M, Dincer I, Bozkurt I, Atiz A. Performance assessment of a solar pond with and without shading effect. Energy Convers Manag 2013;65:98–107. Bryant HC, Colbeck I. A solar pond for London? Sol Energy 1977;19(3):321–2. Suárez F, Tyler SW, Childress AE. A fully coupled, transient double-diffusive convective model for salt-gradient solar ponds. Int J Heat Mass Transfer 2010;53(9–10):1718–30.

Solar Ponds

Further Reading Duffie JA, Beckman WA. Solar engineering of thermal processes. New York, NY: Wiley; 2006. Enteria N, Akbarzadeh A. Solar energy sciences and engineering applications; 2013. Kalogirou SA. Solar energy engineering: processes and systems. Nielsen P. Solar ponds. Science 1974;186(4169):1074–5. Reddy PJ. Solar power generation; 2011. p. 214. Srinivasan J. Solar pond technology. Sadhana 1993;18(1):39–55.

Relevant Websites https://www.britannica.com/technology/solar-pond Encyclopaedia Britannica. http://energyeducation.ca/encyclopedia/Solar_pond Energy Education. http://www.solar-energy-for-homes.com/solar-ponds.html Solar Energy for Homes. http://soilwater.com.au/solarponds/ Solar Ponds. http://omp.gso.uri.edu/ompweb/doee/science/physical/chsal1.htm University of Rhode Island – Office of Marine Programs.

691

4.17 Solar Tower Systems Reiner Buck, DLR, Stuttgart, Germany Peter Schwarzbözl, DLR, Köln, Germany r 2018 Elsevier Inc. All rights reserved.

4.17.1 4.17.2 4.17.3 4.17.3.1 4.17.3.1.1 4.17.3.1.2 4.17.3.1.2.1 4.17.3.1.2.2 4.17.3.1.2.3 4.17.3.1.2.4 4.17.3.1.2.5 4.17.3.1.2.6 4.17.3.1.3 4.17.3.1.3.1 4.17.3.1.3.2 4.17.3.1.3.3 4.17.3.1.4 4.17.3.1.5 4.17.3.1.6 4.17.3.2 4.17.3.3 4.17.3.4 4.17.3.5 4.17.3.6 4.17.3.7 4.17.4 4.17.4.1 4.17.4.2 4.17.4.2.1 4.17.4.2.1.1 4.17.4.2.1.1.1 4.17.4.2.1.1.2 4.17.4.2.2 4.17.4.3 4.17.4.4 4.17.4.5 4.17.4.5.1 4.17.4.5.2 4.17.4.6 4.17.4.6.1 4.17.4.6.2 4.17.4.6.3 4.17.4.6.4 4.17.4.7 4.17.5 4.17.6 4.17.6.1 4.17.6.2 4.17.6.3 4.17.7 4.17.7.1 4.17.7.1.1

692

Introduction Fundamentals Components and Systems Concentrator System Heliostat types Heliostat design characteristics Unit size Mirror facets Support structure Rotational axes and drives Foundation Control system Heliostat errors Imaging errors Tracking errors Energy losses Heliostat field Secondary concentrators Beam down optics Heat Transfer Medium Receiver Tower Storage Power Block Hybridization Analysis and Assessment Efficiency Parameters Economic Parameters Investment cost (CAPEX) Heliostat investment cost Tower investment cost Receiver investment cost Annual cost of operation and maintenance (OPEX) Levelized Cost of Electricity Additional Value of Dispatchability Layout and Performance Simulation Heliostat field layout Annual performance calculation Plant Operation and Control Definition of control tasks Heliostat field control Aim point distribution Operation strategy Material Lifetime and Degradation Case Study for a Solar Tower Plant Examples of Solar Tower Plants Ivanpah Solar Energy Generating System Crescent Dunes Solar Tower Jülich Future Directions Future Power Cycles Advanced steam power cycles

Comprehensive Energy Systems, Volume 4

693 697 699 699 700 700 700 701 701 701 701 702 702 702 702 702 703 705 706 707 708 709 710 712 712 712 712 713 713 714 714 714 714 714 715 715 715 716 717 717 717 718 719 719 720 722 723 723 724 725 725 725

doi:10.1016/B978-0-12-809597-3.00428-4

Solar Tower Systems 4.17.7.1.2 Gas turbine cycles 4.17.7.1.3 Supercritical CO2 cycles 4.17.7.2 Future Heat Transfer Media and Receivers 4.17.7.3 Storage Technology 4.17.7.4 Other Improvement Options 4.17.7.5 Further Application Options 4.17.7.5.1 Hybrid plants 4.17.7.5.2 Process heat applications 4.17.8 Closing Remarks Acknowledgment References Further Reading Relevant Websites

Nomenclature

725 726 727 728 729 729 729 729 730 730 730 732 732

i LV P r TH

Interest rate Heliostat vertical length [m] Power [W] Radial distance [m] Tower height [m]

Greek symbols a Absorptivity [-] incident angle of sun light on heliostat [1]

y Z

Acceptance angle of secondary concentrator [rad] Efficiency [-]

Subscripts abs atm b&s cond conv cos el field

Absorbed Atmospheric attenuation Blocking and shadowing Conductive Convective Cosine Electric Heliostat field

Hel int nb pb refl rad rec th

Heliostat Intercepted No blocking Power block Reflection Radiative Receiver Thermal

Acronyms CAPEX CPC CSP CRS DAR DNI

Capital expenses Compound parabolic concentrator Concentrating solar power Central receiver system Direct absorption receiver Direct normal insolation

DP FCR HTF HTM LCoE OPEX PV

Design point Fixed charge rate Heat transfer fluid Heat transfer medium Levelized cost of electricity Operational expenses Photovoltaic

Symbols A E I

4.17.1

Area [m²] Energy [kWh] Solar flux [W/m²]

693

Introduction

Today’s energy supply is mainly based on fossil fuels like coal, oil, and natural gas. Sources of these fuels are finite, especially for natural gas the resources are quite limited. Probably even more important is the increasing CO2 content in the Earth’s atmosphere, resulting from fossil fuel combustion. The emission of this greenhouse gas is considered responsible for global warming, which is already visible in rising temperatures worldwide. Simulation programs predict severe changes in the climate over the coming decades, with drastic consequences for mankind. As this threat is now widely accepted, political initiatives are under way to limit the consequences. For example, the Paris Agreement is an agreement within the United Nations Framework Convention on Climate Change (UNFCCC) dealing with greenhouse gas emissions mitigation, adaptation, and finance [1].

694

Solar Tower Systems

Transforming energy generation from fossil fuels to renewable energy systems plays an important role in the attempt to fight climate change. Photovoltaic (PV) and wind energy are well known renewables nowadays, and have reached a certain share in power production worldwide. Concentrating solar power (CSP) systems are another option for renewable power supply. CSP systems are based on conventional thermal power cycles. The main difference is that the heat source is not coming from fossil fuels or nuclear fission processes, but from concentrated solar radiation. Unlike PV power, only direct solar radiation can be used, as only the limited view angle of the sun disk allows the required concentration of the sunlight. Therefore, solar thermal power plants are economically most attractive in regions with high direct insolation levels. Generally, sites with an annual direct normal insolation (DNI) value above 2000 kWh/m²a are considered as attractive for the implementation of solar thermal power systems. Fig. 1 shows the annual DNI values for the world. Excellent sites can be found, for example, in Chile (Atacama desert), South Africa, and Australia; good sites can be found in several other regions in the world’s sunbelt. As a consequence of the first oil crisis in the last century, solar thermal power technology experienced a first boom. In the period from 1984 to 1990 the first commercial solar power plants were built in southern United States, with 354 MW total capacity. These plants are still in operation, due to regular maintenance. After 1990, in a period of low energy prices, no new CSP plants were built due to economic reasons. When energy prices increased and the effect of global warming from greenhouse gas emissions became evident, the implementation of renewable energy systems into the power supply became more important. Around the year 2007 the installation of new CSP plants started, supported by political and legislative support (e.g., “Renewable Portfolio Standard” in the United States, “Feed-in Tariff” in Spain). Since then, the total installed capacity of CSP plants has significantly grown. By the end of 2016, the installed capacity totaled up to about 5 GW. A major advantage of CSP technology is the ability to integrate thermal storage, as storage of heat is simpler and cheaper than storage of electricity. Excess solar energy, collected during sunshine hours, can be easily stored for later conversion to electricity. Thus, a CSP with storage can deliver dispatchable power supply. The plant capacity factor can be selected by design in a wide range according to the grid requirements. Another option is the integration of an additional burner that allows providing heat to the power cycle even in case of longer periods with reduced solar radiation. Thus, full availability of the power supply can be guaranteed, a significant contribution to grid stability. Because of these unique features, CSP plants are considered an important factor in the future energy mix with high shares of renewables. CSP with storage is not competing with fluctuating renewables like PV and wind but plays a complementary role, enabling even higher shares of fluctuating renewables. Two different concentration principles are applied in CSP systems: line focus and point focus concentration (Fig. 2). Line focus systems concentrate the direct solar radiation to a focal line, typical concentration levels are up to 100. Parabolic trough and linear Fresnel plants are representatives of line focus systems. Point focus systems concentrate the direct solar radiation to a focal point, with typical concentration levels up to 1000. Solar tower and parabolic dish systems are representatives of point focus systems.

Direct normal irradation

Long-term average of

Annual sum < 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 3600 3800 > kWh m−2 < 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 8.5 9.0 9.5 10.0 10.5 > Daily sum

Fig. 1 Solar annual direct insolation map of the world. Reproduced from Solargis, Available from: http://solargis.com/assets/graphic/free-map/ DNI/Solargis-World-DNI-solar-resource-map-en.png; 2016 [accessed 26.08.16].

Solar Tower Systems

Linear fresnel reflector (IFR)

Central receiver

Parabolic dish

695

Parabolic trough

Solar tower Curved mirrors Reflector Absorber tube

Receiver/ engine

Absorber tube and reconcentrator

Heliostats

Solar field pipimg

Reflector

Fig. 2 Concentrating solar power (CSP) technologies. Reproduced from IEA, Technology roadmap solar thermal electricity – 2014 edition; 2014.

Fig. 3 Parabolic trough collector (left) and Linear Fresnel collector (right). Courtesy of DLR/Steur.

Line-focus collectors allow efficient operation in the temperature range between 400 and 5501C. Parabolic trough collectors (Fig. 3 left) are built from mirror segments with a parabolic curvature that are tracked in one axis to follow the sun’s movement. In the focal line of the mirrors the absorber tube is installed. A heat transfer medium (HTM) is flowing through the absorber tube, and is heated by the absorbed solar radiation. The hot medium is then transported to the power cycle or storage. Linear Fresnel collectors (Fig. 3 right) consist of a number of parallel long and slightly curved facets. The facets are tracked independently in one axis and concentrate the solar radiation onto a fixed absorber tube. Since the mirror facets are small and near ground level, wind loads are reduced and the structures can be built more lightweight and at lower cost. However, this comes with slightly reduced optical performance, especially in off-design conditions. Point-focus systems allow obtaining significantly higher concentration levels. With higher concentration levels, the receiver and thus the power cycle can operate at higher temperatures, enabling better system efficiency. The most important point-focus system is the solar tower (power tower, or central receiver system (CRS)) system (Fig. 2). In a solar tower system, a huge number of individually tracked mirrors (“heliostats”) reflect the solar radiation to the top of a tower and create a focal spot. In the focal spot the central receiver is installed to convert the concentrated solar radiation into heat. Solar tower systems achieve typically concentration levels of 500–1000, typical receiver temperatures are in the range of 500–10001C. The power level of commercial solar tower systems ranges from 100 kW to several hundred MW. Fig. 4 shows the solar tower plant Crescent Dunes in Nevada, United States, with a rated power of 110 MW and a 10 h storage capacity. The parabolic dish concentrator is another point-focus system. It consists of a mirrored paraboloid (“dish”) that is tracked in two axes to point directly to the sun. In the focal spot of the concentrator a receiver converts the solar radiation to heat that is directly converted to electricity in a power cycle (usually a Stirling engine). Wind loads on the concentrator structure limit the maximum size of the system, an electric power level of about 50 kW is seen as the limit. Larger power levels are obtained by

696

Solar Tower Systems

Fig. 4 Commercial solar tower plant Crescent Dunes, Nevada, United States.

Operation

Construction

Development

Solar tower Parabolic trough Linear fresnel Dish

5112 MW

3190 MW

5343 MW

CSPtoday project tracker data from 12-02-2017

Fig. 5 Concentrating solar power (CSP) share by technology. Data from CSP Today global tracker. Available from: http://social.csptoday.com/ tracker/projects; 2017 [accessed 12.02.17].

connecting several dish modules to a power plant. Since the integration of storage to dish systems is difficult, such systems are not widely introduced. Fig. 5 shows the share of the different solar concentrating technologies in the market. Currently the most implemented technology is the parabolic trough. However, for plants under installation or in preparation, the share of solar tower technology is strongly increasing. For the solar thermal plants under development, solar tower technology reaches already a share of nearly 70%. The reason for the increasing share is the high cost reduction potential which is expected with solar tower technology in the future. Most technology studies predict significant further cost reductions for future solar towers which will make these systems the least-cost solar thermal power technology. For example, a recent IRENA study [2] predicts for 2025 parabolic trough plants with levelized cost of electricity (LCoE) of about USD 0.11/kWh for a reference plant, while solar tower systems are expected to come down to about USD 0.09/kWh (Fig. 6). In September 2016 China’s 1st phase CSP pilot project list was officially announced [3]. Out of the 20 selected projects, nine are solar tower, seven are parabolic trough, and four Compact Linear Fresnel systems. Another indicator for the increased importance of solar tower systems was the bidding price for a solar tower plant in Chile at 6.3 US¢/kWh [4]. This chapter describes in detail about the current status, the potential and future development trends of solar tower technology.

Solar Tower Systems

2015

0.25

697

2025

2015 USD/kWh

0.20 0.15 0.10 DNI 2 550 0.05

DNI 2 000-DNI 2 900 PPAs NOOR

0.00 Parabolic trough

Solar tower

Parabolic trough

Solar tower

Fig. 6 Levelized cost of electricity (LCoE) of parabolic trough and solar tower technologies, 2015 and 2025. Reproduced from IRENA, The power to change: solar and wind cost reduction potential to 2025; 2016.

2015: 42.8% 2025: 43.9% G

Hot tank 2015: T=565°C 2025: T=600°C

T=290°C

Cold tank Pump Heat exchanger

Heliostat field

Tower and receiver

Food water tank

Storage system

Power block

Fig. 7 Scheme of a state-of-the-art solar tower system. Reproduced from IRENA, The power to change: solar and wind cost reduction potential to 2025; 2016.

4.17.2

Fundamentals

Basically, a concentrated solar power system is a conventional power block where the heat for the power cycle is provided by solar energy instead of fossil fuels or nuclear energy. A solar tower plant consists of the following main components:

• • • • •

heliostat field receiver tower thermal storage (optional) power block

A scheme of a solar tower system (in this case using molten salt as heat transfer fluid (HTF)) is shown in Fig. 7. The heliostat field concentrates the direct solar radiation onto the receiver. It is composed of a large number of so-called heliostats. Each heliostat is tracked in two axes to reflect the solar radiation to the receiver. Heliostats are built from one or

698

Solar Tower Systems

multiple mirror facets, usually with back-silvered low iron glass as reflector material. The mirror facets can be slightly curved to achieve higher concentration. The receiver absorbs the concentrated solar radiation, thus reaching high temperatures. It transfers the heat to a HTM. In current commercial solar tower systems water/steam or molten salt are used as HTF, allowing temperatures more than 5501C. Most receivers use metallic tubes, irradiated from the outside, with the HTF passing through the tube. The tower is necessary to install the solar receiver in a suitable height. The thermal storage decouples the collection of the solar energy from the production of electricity. In current solar tower plants mainly sensible heat storage systems are applied. The storage is charged during solar operation by the oversized solar collection system. When no or insufficient solar energy is collected the storage is discharged to power the thermal cycle for electricity production. The power block is a conventional thermal power block, namely a Rankine cycle with superheated steam. The design of the power block is adapted to the specific operation conditions of the solar system. Wet, dry, or hybrid cooling techniques are applied for the condenser section. The actual typical rating of a solar tower system is in the range of 100–150 MW, with storage capacity for about 10 h of full load operation. Solar energy collection in a solar tower system depends on the availability of DNI. The following figures describe a fictive solar tower plant based on the following assumptions:

• • • • •

power level: 100 MWe, heat transfer and storage medium: molten salt, receiver design power: 682 MWth (design point (DP): 21.3. 12:00), storage capacity: about 15 h full load operation, and plant location: Chile, southern hemisphere.

More details on this case study can be found in Section 4.17.5. Fig. 8 shows the predicted daily thermal power production from the receiver, for 3 days representing the different seasons. It is obvious that in the Chilean winter (June) less thermal energy is available than in summer (December). In general, the thermal power follows a sine-like curve over the day. Fig. 9 shows the accumulated average daily thermal energy produced by the receiver. Again the seasonal influence is visible, with high values in Chile’s summer and low values in winter. The main reason for the differences is the sunshine duration varying with season. The calculated values are based on real DNI measurements for the selected site in Chile, which is a site with excellent solar conditions. Unlike other renewables like PV or wind turbines, solar tower plants offer different operation modes that enable controlled power production and support grid stability. Fig. 10 explains these modes for a hybrid CSP plant (i.e., with an additional fuel burner to ensure full availability), in terms of thermal power delivered to the power cycle:

• • • • •

mode 1: hybrid operation, with decreasing burner power after sunrise, mode 2: solar-only operation, excess solar power is used to charge storage, mode 3: solar-only operation; when the storage is fully charged, part of the available power is dumped (by defocusing an appropriate number of heliostats), mode 4: toward sunset, solar thermal power is decreasing, and additional power is delivered from storage, and mode 5: when storage is discharged, the burner can provide the needed power.

The power level, the amount of storage capacity and the amount of co-firing the burner can be selected in a wide range during the plant design phase. This allows adaptation to the local demand and grid situation.

Thermal receiver power (MW)

800 700 600 500 400 21.03.

300

21.06.

200

21.12.

100 0 6

8

Fig. 8 Receiver power as function of season and time of day.

10

12 Time of day

14

16

18

Solar Tower Systems

699

Daily receiver energy yield (GWh/d)

8 7 6 5 4 3 2 1 0 Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Fig. 9 Typical solar tower energy production over a year.

Thermal power

To storage +QS

QDumping QAux. burner QD QA From storage −QS

QAux. burner QA

1

2 Solar heat input QC

3

4

5

Time

Thermal load QL

Fig. 10 Operation modes of a solar tower plant.

4.17.3 4.17.3.1

Components and Systems Concentrator System

Solar towers or CRS together with the solar dish systems belong to the point focusing technologies. Unlike solar dishes, where the concentrating mirror has the ideal geometric shape of a paraboloid the concentrator of a CRS is fragmented into a large number of individual mirrors that are fixed on the ground. Each of these mirrors is rotated individually around two axes to reflect the sun’s image to the receiver. Therefore, these so-called heliostats (from Greek helios ¼ sun and statos ¼ stationary) are equipped with two independent drives to track the apparent movement of the sun in the sky during the course of a day. The heliostat units together with their power and control connection and the central control unit constitute the concentrator system. Peripheral systems are the tracking control infrastructure and the mirror cleaning equipment. A heliostat unit typically consists of one or more mirror facets that are attached to a rigid metal support structure which is mounted movably on a pedestal or pylon that is fixed to the ground, as shown in Fig. 11. In the classical T-shape design the axis of the primary movement lies vertically in the pedestal while the secondary rotational axis is perpendicular to that and therefore horizontal. The motions are usually performed by geared DC step motors implemented as rotary drives or as linear drives with cantilever. The heliostats are rotated so that their normal vector bisects the angle between the vector that points from the heliostat to the sun and the vector that points from the heliostat to the receiver. As the latter depends on the heliostat’s position the heliostat orientation is different for each unit and has to be calculated and controlled individually. This task is taken over by the heliostat control system consisting of the local controller boards and the central control unit. Tracking movements are usually performed discontinuously with update intervals depending again on the heliostat positions. The communication link between local and central control unit is realized by cable or wireless by radio transmission. Electric power is either supplied centrally by wire connection or locally by PV generator sets with battery.

700

Solar Tower Systems

Fig. 11 Typical T-shaped heliostat on PSA in front and back view. Courtesy of DLR/Ernsting.

(A)

(B)

(C)

Fig. 12 Heliostat types with different structural arrangement (green: moving parts; blue: stationary parts; red: rotational axes).

4.17.3.1.1

Heliostat types

Heliostats can be categorized roughly by their structural arrangement. In the classical design (Fig. 12(A)) the mirror facets are attached to a rigid support structure that is moved as a whole relative to a fixed single pylon. This arrangement is still the most common design in all existing commercial and noncommercial plants with unit sizes from only a few square meters up to 150 m² and beyond and facet numbers from one single facet up to around 30 facets per heliostat. In contrast to the classical design is a heliostat type whose facets are distributed horizontally and are attached to a large nonmoving support structure (Fig. 12(B)). The facets have at least one individual rotation axis and are moved either coupled (“ganged”) as described by Amsbeck et al. [5] or independently as presented by Schell [6]. The other extreme is a heliostat type where the reflector and the support structure are movable in total (Fig. 12(C)). The primary movement is a rotation directly on the ground, on the foundation, or on rails, usually by wheels. The secondary rotation around the horizontal axis is often performed with rim drives. Examples for this heliostat type can be found in Pfahl [7].

4.17.3.1.2

Heliostat design characteristics

Heliostat design is dominated by the task to deliver the maximum annual yield of concentrated radiation at the lowest overall cost for a specific tower plant. It is therefore influenced by a number of parameters and many alternative designs exist. The different characteristics of the main components are described briefly in this chapter. More details can be found in literature (e.g., Ref. [7]). 4.17.3.1.2.1 Unit size Known heliostat designs vary from around 1 m² to more than 150 m² reflective area per unit and there is no general rule for an optimum size. While it is no problem to design a very precise high quality heliostat it is quite challenging to build a very good

Solar Tower Systems

701

heliostat at very low specific cost. Two different design philosophies can be identified: designers of small area heliostats rely on simple low-cost mass-product components, partially preassembled heliostats and a simple installation process on site. Small heliostat designs also take advantage of lower wind speed at their low height and generally lower specific weight per unit reflective surface [8]. Usually the lower optical quality of small heliostats has to be compensated by low component and labor cost. Large heliostats usually exhibit fewer parts but more weight per unit mirror area. They are commonly designed to have a good optical quality because their large annual energy yield per unit allows using higher-quality components and spending more work effort during installation. Large heliostats are usually assembled on-site in project-specific assembly lines. Generally spoken, the cost driver for large heliostats lies in the support structure while for small heliostats the drives, cabling and control are dominant [7]. 4.17.3.1.2.2 Mirror facets Back-silvered low-iron glass is usually used as mirror. Front-silvered mirrors show higher degradation due to environmental influences and are therefore only used when the UV portion of the sunlight is important, as, for example, in photochemical applications or test installations. Mirror facets usually have a size of several square meters. Thick glass mirrors (B4 mm) have sufficient structural stability themselves and they can be attached directly to the support structure, usually consisting of metal beams. As glass and metal vary in their thermal expansion ratio mirrors have to be fixed to the steel frame structure with flexible connections. Thin glass mirrors (B1 mm) can be employed to improve the optical quality. Thin glass has to be attached to a support layer made from metal or plastics. Stamped metal support structures offer high stiffness at low specific weight. Sandwich panels with cores of foam, honeycomb or other porous structures provide high structural stiffness at low total weight. Mirror facets can be flat or spherically curved to reduce the image size. The main concentration is achieved by canting, i.e., the facets are assembled on the supporting frame so that their reflected images overlay at the desired focal distance. A special case is the stretched membrane heliostat, a single-facet mirror made of a steel membrane covered with thin-glass mirror stripes. The curvature here is attained by vacuum in the void between the facet and the back structure. 4.17.3.1.2.3 Support structure The task of the support structure is to provide the stiffness to assure a precise orientation of the mirror facets throughout the day and to guarantee the mechanical integrity of the heliostat during storm conditions. The design depends strongly on the mirror surface area and the facet type. Framework or torque tube elements and their combinations are commonly used. As special cases heliostats made out of concrete and heliostats with inflatable back structure shall be mentioned here. The main design parameters for the heliostat support structure are:

• • •

the total weight, the wind speed during operation, and the maximum wind speed in stow position (survival wind speed).

The design wind speed has a strong influence on the heliostat cost. The relevant design wind loads must be defined sitedependent according to the local wind conditions (statistical information about wind velocity and direction). Generally, for locations with higher wind speed smaller heliostats are preferable. The mean and peak loads resulting from the design wind speed are usually determined experimentally by measurements of model heliostats in boundary layer wind tunnels. In the past, normally only static wind loads were considered for heliostat design. Recent studies showed that dynamic wind loads which can be caused by turbulences in the wind flow or instabilities in the shear layers can have a very large impact due to resonance effects [7]. When the heliostat support structure is dimensioned well to survive at stormy conditions it is usually stiff enough so that wind loads during operation do not cause deformations that lead to significant losses of intercepted energy. 4.17.3.1.2.4 Rotational axes and drives The rotational axes can be arranged in the classical T-shape orientation with vertical primary axis (azimuth movement) and horizontal secondary axis (elevation movement) as pointed out in the previous chapter. This arrangement is characterized by the fact that the lower edge of the heliostat is always parallel to the ground. The azimuth movement is often performed by a slew drive, the elevation movement by a slew or linear drive. As alternatives also hydraulic drives and rim drives have been proposed. Some heliostat designs favor different axes orientations to improve the performance/cost ratio [7]. For example, a horizontal primary axis allows using cheaper linear drives and enables a higher density of the heliostat arrangement. A special case is the target-aligned heliostat, where the primary axis lies in the vector from the heliostat to the target. This design leads to higher optical quality through reduced astigmatism. Depending on the type of drive and the orientation of the axes wind loads can have significant impact on the pointing accuracy of a heliostat due to backlash in drives and gears (see also next chapter on heliostat errors). For the elevation movement the torque caused by gravity can reduce the backlash if the mirror structure is supported outside its center of mass. For the azimuth movement backlash can be reduced with pretensioning by, for example, springs or by using low backlash gears. 4.17.3.1.2.5 Foundation The foundation is determined mainly by the size and the weight of the heliostat and the operational and survival wind speed it is designed for. Individual (steel reinforced) concrete block or pier foundations are commonly used, especially for larger heliostats

702

Solar Tower Systems

Target

Target → S

→ n → r

Fig. 13 Principle of heliostat imaging error (left) and tracking error (right).

with a single pylon. But also earth-screw and pile-driven foundations have been proposed for cost reduction. Smaller heliostats sometimes use ground anchors or even just ballast and no fixation to the ground. 4.17.3.1.2.6 Control system The main task of the control system is to determine the movement of the drives to give the heliostat the desired orientation and to control the execution of that movement by the drives. As mentioned before, this movement is depending on the heliostat’s position and is therefore individual for each unit. The control system is characterized by its degree of centralization (see Section 4.17.4.6).

4.17.3.1.3

Heliostat errors

Mechanisms that can lead to a loss of radiative energy provided by a heliostat are often referred to as heliostat errors. They can be subdivided into imaging errors and direction or tracking errors. Imaging errors result in a deviation from a point focus and direction errors lead to a deviation from the desired aim point (Fig. 13). 4.17.3.1.3.1 Imaging errors Due to the finite size of the sun disk (B5 mrad half angle) the solar rays are not exactly parallel when reaching the earth. Forward scattering of the solar radiation by the earth’s atmosphere additionally modifies the brightness distribution of the sun in the sky so that a certain percentage (usually 5%–15%) of the radiation comes from an aureole around the actual solar disk [9]. Hence, the maximum possible concentration ratio of focusing collectors is limited. Off-axis reflection (which is mostly the case for heliostats) leads to additional widening of the reflected beam, called astigmatism. The size of the focal spot is broadened further by the nonideal character of the concentrator facets: surface roughness, waviness, and deviation from the ideal shape are summarized as the slope error of a mirror. They are in the order of magnitude of 1 mrad for heliostat mirrors. Deviations caused by misalignment of the facets on the supporting frame are denoted as canting errors when treated separately. 4.17.3.1.3.2 Tracking errors The demands made on the orientation of the heliostats in a tower plant are high, usually o1 mrad (a misalignment of 1 mrad means a heliostat in 1000 m distance misses its desired aim point by 1 m). False orientation of a heliostat usually has a multitude of causes. Error sources of statistical nature can be distinguished from those of systematic origin. The former are caused by backlash in gears and drives and a nonrigid structure that lead to random deviations from the desired orientation during movements and when wind shakes the heliostat. Systematic errors are calculation errors due to non-perfect data sets or algorithm insufficiency. They can be caused by imprecise manufacturing, positioning, and alignment of the heliostat during the installation. The aiming error due to discontinuous tracking steps is also considerable but commonly accepted due to the additional expenses needed for continuous tracking [10]. The deviations of the orientation caused by systematic errors can be detected and compensated by calibration a process where the reflected image of a single heliostat is aimed to an extra target. The center of the focal spot is detected by a camera and the deviation from the desired aim point is determined. By repeating this measurement for several incident angles of the sun a heliostat error model can be parameterized and compensation values can be calculated [11]. 4.17.3.1.3.3 Energy losses A series of energy losses occur during the concentration of sun light by a heliostat. First, due to off-axis reflection, the effective mirror area is reduced by the cosine of the incidence angle. Further, not all of the incoming radiation is reflected toward the target. It is partly absorbed in the glass or by dust or it can be scattered by dust or surface imperfections of the mirror (new mirrors have a clean reflectivity of 94% and above; degradation and dirt can reduce the reflectivity to below 85%). Unlike parabolic troughs, at a solar tower system the reflected radiation has a long way to go through the atmosphere before hitting the target, usually several hundred meters. This leads to a considerable attenuation due to scattering and absorption in the order of magnitude of 1% per 100 m [12]. The radiation finally reaching the top of the tower may not fully enter the aperture of the receiver, which is commonly denoted as spillage. Obviously, the amount of spilled radiation is influenced by the size and the position of the focal spot in the receiver plane and hence by the imaging and tracking errors described above. As the size of the receiver aperture determines its

Solar Tower Systems

703

thermal losses a trade-off between spillage losses of the heliostats and thermal losses of the receiver has to be made during system engineering.

4.17.3.1.4

Heliostat field

Heliostats are placed around the tower in a way that they concentrate the solar radiation with maximum efficiency. For free movement (no collision) the minimum distance of neighboring heliostats is usually set to the diagonal of the moving mirror structure plus some saftey distance. Some concepts try to allow a higher density of heliostat positions by avoiding collision with intelligent control of the mirror’s movements. Obviously, the closer the heliostats are positioned to each other the more they can interfere by reflecting the sunlight. Neighboring heliostats can shadow each other so that just part of the total mirror area is irradiated by the sun. Further, reflected radiation can be partly blocked by heliostats standing in the direction toward the tower. Shadowing occurs at lower sun elevation angles. It cannot be avoided completely, but decreases with increasing distance between heliostats. Blocking can be avoided completely when the radial distance between heliostats is chosen appropriately. The minimum distance between heliostat rows to avoid blocking is (Fig. 14 left): Dr 

)

LV LV LV r ¼ E
sinðaÞ tanðaÞ
cosðaÞ TH cosðaÞ

Dr LV 1 r LV r  ; for large r TH TH cosðaÞ TH TH TH

Fig. 14 shows the minimum distance between heliostat rows as a function of the distance from the tower for heliostats with vertical size LV and tower height TH. Close to the tower (until a distance of about one tower height) the minimum distance to avoid collision is dominant, i.e., the diagonal of the heliostat. After that, the distance of rows follows the equation above. If heliostats are positioned accordingly to avoid blocking the radial distance of heliostats to the tower becomes very large, leading to energy losses due to imaging and tracking errors (see Section 4.17.3.1.3). Therefore, in an overall optimum it usually is favorable to accept some amount of blocking for the benefit of reduced spillage and attenuation losses. Heliostats are usually positioned in rows or circles following a parameterized regular pattern (see Fig. 15). To minimize blocking losses a radial staggered layout is often preferred. Here, the azimuthal spacing between heliostats increases linearly with distance from the tower. Therefore, to maintain a high field density, heliostats in a row are “re-densified” after a certain number of rows, as indicated in Fig. 15 (right). The most efficient position for a heliostat relative to the tower is on the opposite side of the sun where the incidence angle and hence the cosine loss is small (see Fig. 16). This is on the north side of the tower for the northern hemisphere and on the south side for the southern hemisphere. Therefore, for small systems heliostat fields are pure “north fields” (resp. “south fields” for the southern hemisphere). For larger systems, the other energy loss mechanisms (spillage and atmospheric attenuation) become more and more important and it is favorable to accept higher cosine losses by placing heliostats to the south (resp. north) of the tower. The influence of power level and location (i.e., site latitude) is shown in Fig. 17. All statements made for north field in the following descriptions are meant for the northern hemisphere and hold true when used for south fields in the southern hemisphere. Figs. 18 and 19 show basic relationships of heliostat field layout regarding location, size, and field shape as a result of computer-based optimizations (see Section 4.17.4.5.1). Fig. 19 shows the influence of heliostat quality and tower height on field layout for a medium sized tower plant of 450 MWth at 30 degree latitude with surround field. As can be seen, heliostat quality can 0.8

LV/TH = 0.08

0.6

Δr/TH

TH

0.2

LV

α Δr r Fig. 14 Heliostat radial distance to avoid blocking.

0.4

Diagonal 0 0

2

4 r/TH

6

8

Solar Tower Systems

704

Fig. 15 Typical heliostat field layout patterns: rows staggered (left) and radial staggered (right).

y ra nt de ci In m

y ra

fro

nt de ci In

n

m

su

fro n

su

′



North side of tower

South side of tower Small projected mirror area = high cosine loss

Large projected mirror area = low cosine loss

Fig. 16 Incidence angle of heliostats north and south of the tower (left) and annual cosine factor at positions relative to the tower (right) (shown for a solar field on the northern hemisphere).

0.65 20°N; surround field 40°N; surround field Annual field efficiency (−)

0.62

40°N; north field 20°N; north field

0.59

0.56

0.53

0.5 0

100

200

300

400

500

600

700

Receiver power level (MWth) Fig. 17 Annual field efficiency as a function of receiver power level for different latitudes and field shapes. The north field has higher efficiency for small systems but decreases rapidly with power level. The surround field is superior to the north field above a certain power level (approximately 100 MWth for low latitudes and 300 MWth for high latitudes). Important to note: north fields are more efficient at high latitudes; for surround fields it is vice versa, due to the cosine losses.

Solar Tower Systems

705

1.6E+06

14E+06

Total reflective area (m2)

1.2E+06

1.0E+06

8.0E+05

6.0E+05

20°N; surround field 40°N; surround field

4.0E+05 20°N; north field 40°N; north field

2.0E+05

Commercial fields 0.0E+00 0

100

200

300

400

500

600

700

800

Receiver power level (MWth) Fig. 18 Total reflective area as a function of receiver power level for different latitudes and field shapes. Field size for north fields is depending on latitude, but no significant influence is found for surround fields. Round dots indicate the same relation for existing commercial heliostat fields.

0.62

9.2E+05

0.59

8.8E+05

0.56

8.4E+05

Field size

0.53

Field efficiency 0.50

8.0E+05 Bad (2.0/1.5)

Average (1.2/0.6) Heliostat quality

Good (0.8/0.5)

450 MWth, 30°N, surround field

0.65

9.6E+05

0.62

9.2E+05

0.59

8.8E+05

0.56

Ratio (−)

9.6E+05

1.0E+06 Total reflective area (m2)

0.65

(−)

Total reflective area (m2)

450 MWth, 30°N, surround field 1.0E+06

Field size 8.4E+05

0.53 Field efficiency

8.0E+05 100

150

200

250

0.50 300

Tower height (m)

Fig. 19 Influence of heliostat quality (left) and tower height (right) on field size and efficiency for a 450 MWth system at 30 degree latitude (values of heliostat quality indicate slope error and tracking error per axis in mrad).

change the field size by 20% and the efficiency by 6%. Increasing the tower height by 50% can save 10% of the heliostat field and increase its efficiency by 7%. Two important additional factors have to be considered when defining the positions of a heliostat field: (1) access roads for heliostat cleaning trucks and other O&M procedures have to be included into the layout, and (2) cable trenches and cables for power supply and communication are a significant cost factor that can also influence the field layout. Heliostat field layout is usually done by computer-based numerical simulation codes. More details will be presented in Section 4.17.4.5.

4.17.3.1.5

Secondary concentrators

In solar tower systems, secondary concentrators are optical elements in front of the receiver to achieve higher concentration levels. This means that the solar power is concentrated onto a smaller aperture, thus achieving higher flux densities in the receiver aperture. Especially for high receiver temperatures, thermal losses by thermal radiation and convection are significant. As these losses strongly depend on the receiver aperture area a smaller aperture results in lower thermal losses. Therefore, secondary

706

Solar Tower Systems

concentrators can increase the thermal energy yield of solar tower systems by reducing the thermal losses, due to the smaller aperture area. The concentration factor of a secondary concentrator depends strongly on the incidence angle range of the concentrated solar radiation. For a secondary using the typical 3-dimensional compound parabolic concentrator (CPC) geometry, the theoretical maximum concentration factor is given by

Cmax ¼

1 sin2 y

with y being the acceptance angle (i.e., the angle range that the incident radiation covers, relative to the CPC axis). Real secondary concentrators are usually truncated for practical and cost reasons, resulting in somewhat lower concentration factors. For such a secondary concentrator, the acceptance angle is not a clear limit, but a transition region. Fig. 20 shows a typical transmittance function of a real CPC secondary. Additionally, secondary concentrators show some losses due to absorption in the reflector material. In solar tower systems, the limited acceptance angle of a secondary concentrator significantly impacts the heliostat field layout. Typical layouts result in systems with a higher tower and a solar field that is longer north–south direction and narrower in east–west. An example of the limitation from a secondary on the field layout is shown on the right side of Fig. 21, indicating the region on the ground where heliostats can be placed.

4.17.3.1.6

Beam down optics

A special case of solar tower system is the so-called beam down or tower reflector system, where the concentrated solar light from the heliostats is reflected once more by a reflector on top of the tower and directed to the receiver on ground level. The motivation is to avoid placing heavy thermal power equipment on top of the tower and to reduce thermal and mechanical losses through transport of the HTF in pipes up and down the tower. A tower reflector system can be realized as a Cassegrain optical configuration, with the heliostat field as the (fragmented) paraboloidal primary concentrator and the tower reflector as the hyperboloidal secondary reflector placed below the heliostat field focal point (Fig. 21). Therefore, the tower of a beam down system is smaller than that of a comparable tower system. The performance of the total system is less sensitive to the optical quality of the tower reflector than to that of the heliostat field. Therefore, the hyperboloidal secondary reflector can be realized by a segmented mirror structure roughly approaching a rotational hyperboloid. The disadvantages are losses caused by the additional reflection and the necessity to use further concentrators in front of the receiver at ground level (like the “secondary concentrator” described in the previous Section 4.17.3.1.5). This is due to the fact that the tower reflector causes the light beam to spread. Both additional concentrators (on tower top and in front of the receiver) need active cooling, which requires additional equipment and therefore causes costs. Beam down system configurations have been studied for different applications, for example, for solar gas turbine systems or solar chemical applications [13]. The first test system with beam down optics was built at the Weizmann Institute of Science in Rehovot, Israel [14]. Further small test units were built in Japan [15], Abu Dhabi [16], and China [17]. No commercial beam down system has been realized yet.

Transmission-angle curve for a CPC with acceptance angle 30°

Receiver

100 Transmission (%)

Acceptance angle 75

50

25

0 0 (A)

10 20 30 Incident angle (°)

40 (B)

Fig. 20 Influence of acceptance angle on transmission factor (A) and heliostat field (B). Reproduced from Schmitz M, Schwarzbözl P, Buck R, Pitz-Paal R. Assessment of the potential improvement due to multiple apertures in central receiver systems with secondary concentrators. Sol Energy 2006;80:111–20.

Solar Tower Systems

707

1.2

AP

Hyperboloid axis

0.8

0.4

0.0 Fig. 21 Schematic of tower reflector optics. AP¼aim point of heliostat field. Reproduced from Segal A, Epstein M. The optics of the solar tower reflector. Sol Energy 2000;69:229–41.

4.17.3.2

Heat Transfer Medium

In a solar tower plant, the HTM significantly influences the system configuration and the components. The HTM is heated in the receiver and is then transferring the thermal energy to the power block and/or the storage. When the HTF is also the working fluid of the power cycle (i.e., in water/steam systems) no heat exchanger is required. When the HTF is different (i.e., in molten salt or air systems) a heat exchanger is necessary to introduce the heat into the power cycle. The HTM can be gaseous, liquid, or solid. Gaseous HTFs (air, helium, and CO2) offer a large temperature range for operation. As the used gases do not impose limitations for the upper temperature, the receiver material is defining the temperature limit. Air as HTF comes for free. Also, gases are harmless for the environment. A major disadvantage of gases is the low heat transfer coefficient caused by low density and low thermal conductivity. The heat transfer can be improved by higher velocities in the receiver, at the expense of higher pressure drop. Increasing the system pressure also improves the heat transfer capability due to the higher density of the fluid. Liquid HTFs offer a significantly higher heat transfer capability. This allows building smaller and more efficient receivers. Depending on the type of fluid (molten salt, liquid metal) there is a lower and upper limit for the operation temperature. The upper temperature limit is defined by degradation effects, both in the fluid and the enclosing materials. The lower limit is defined by the freezing temperature when the liquid is changing to the solid phase. To avoid freezing of the liquid during transient conditions (start-up and shut-down, cloud passages), a heat tracing system has to be installed for safe operation. The currently used molten salt (“solar salt”, a mixture of 60% NaNO3/40% KNO3) has a melting point of about 2201C and is applicable up to 5651C. At higher temperatures the salt mixture starts to decompose. As solar salt is relatively cheap it is used also as storage medium, i.e., no heat exchanger is required between the receiver loop and storage. Molten salt shows good heat transfer coefficients in the receiver, and allows therefore for small and efficient receivers with limited over temperatures. Although only few such plants are in operation, solar tower systems using molten salt are considered state-of-the-art nowadays. A typical plant is described in Section 4.17.6.2. Liquid metals offer significantly better heat transfer characteristics than molten salt, enabling higher flux densities on the receiver. This results in smaller and more efficient receiver configurations. The lower melting temperature, compared to solar salt, promises reduced parasitic power for heat tracing. However, due to higher cost liquid metals cannot be used as direct storage material. Currently, no storage solutions are commercially available for liquid metals. A special case is water/steam as the fluid is subjected to a phase change within the working temperature range. In the receiver the pressurized water is first heated to saturation temperature, then the water is evaporated. The generated steam is then superheated. The steam can be used directly in the steam cycle. In this case there is no need for a heat exchanger between receiver and power block. The significant changes of the fluid properties in the evaporation section lead to more complex receiver operation mainly in transient situations (start up, clouds). Actually, the world’s largest solar tower complex uses direct steam receivers (see Section 4.17.6.1). Solid HTM are also proposed for solar tower systems. Current developments use, for example, small ceramic particles (e.g., bauxite) with a size in the range from 0.25 to 1 mm. Such ceramic particles are relatively cheap and thus can be used both as heat transfer and storage medium. There is no lower temperature limit, and very high temperatures are possible (e.g., 410001C for bauxite particles). The particles can be heated directly by the concentrated radiation, thus improving the performance and reducing

708

Solar Tower Systems

Table 1

Properties of typical heat transfer media

Medium

Minimum temperature (1C)

Maximum temperature (1C)

Thermal conductivity (W/mK)

Volumetric heat capacity (kJ/m³K)

Water/steam Air Helium Solar salt Sodium Lead-bismuth eutectic Solid particles

0 (m.p.) – – 220 (m.p.) 98 (m.p.) 125 (m.p.) –

– – – B565 883 (b.p) 1553 (b.p) 41000

0.09(180 bar/5401C) 0.059 0.32 0.55 64.9 14.9 6.7

– 0.2 3.0 2675 1042 1415 3560

(m.p. ¼ melting point; b.p. ¼ boiling point at standard pressure)

costs of the solar receiver. A special case are small carbon particles entrained in air, that react during the heating process and result in a hot air stream, i.e., a gaseous HTF. The following table (Table 1) gives an overview over some used and proposed HTM. A more detailed discussion of new HTM can be found in Section 4.17.7.2. In current operational solar tower plants, two HTFs are applied: water/steam or molten salt.

4.17.3.3

Receiver

The receiver is the component that converts the concentrated solar radiation into useful heat that is transferred to the HTM. The receiver efficiency is, together with the component cost, the most important parameter. The receiver efficiency is expressed as Zrec ¼

Pth Pint

with the absorbed thermal power Pth Pth ¼ a
Pint

Pth;rad

Pconv

Pcond

Here, a is the effective absorptivity for the solar radiation, Pint is the radiative power intercepted in the receiver aperture, Pth,rad is the emitted thermal radiation from the hot surface, Pconv is the loss from the hot surface by free and forced convection, and Pcond is the conductive heat loss. The receiver aperture is the area through which the radiation enters to the active part of a receiver. The effective absorptivity of the receiver is a function of the surface absorptivity and radiative interaction between the receiver surfaces, for example, a cavity effect. Typical values for the effective absorptivity of current receivers are in the range of 90%–95%. A common absorber coating is Pyromark 2500 Flat Black [18], a high-temperature resistant paint with a solar absorptivity of about 95% and a thermal emissivity of about 88% at 6001C [19]. Conductive heat losses can be controlled by the design of the insulation and are usually quite small. Thermal losses from thermal radiation and convection are important factors reducing the receiver efficiency. As an approximation, thermal losses from thermal radiation and convection can be described as proportional to the receiver aperture area. Then, using a constant areaspecific thermal loss term Pth,l,A and neglecting conductive losses, the receiver efficiency can be written as Zrec ¼

a
Pint Pth;l;A
Aap Pth ¼ Pint Pint

Using Iint ¼ Pint =Aap as the average incident solar flux into the aperture, this formulation can be converted to Zrec ¼ a

Pt;l;A Iint

From this formulation it is easily derived that the receiver efficiency is improved when the average incident solar flux is increased. Especially for high temperature receivers it is very important to achieve high incident solar fluxes in the aperture. The achievable solar flux depends on the allowable fluxes (as defined by the involved materials) and the quality of the heliostat field, i.e., the concentration factor. Two basic receiver types exist: external and cavity receivers. In external receivers, the absorbing elements are mounted externally on a back structure, and experience the highly concentrated solar radiation directly. In a cavity receiver, the absorbing elements are mounted inside of a cavity with an aperture toward the heliostat field. While the (virtual) aperture sees the highly concentrated solar radiation, the radiation is then distributed over a larger area inside the cavity, and the solar flux levels are reduced accordingly. The established receiver technology is the external tube receiver configuration. Such a receiver consists of multiple panels, interconnected in serial and/or parallel mode. Each panel consists of multiple vertical metal tubes, with the associated headers. The tubes of the panels are irradiated by the concentrated radiation from one side, while the panels are insulated on the back. To increase the absorptivity, the tubes are coated black. The HTM is passing through the tubes and gets heated by the absorbed solar energy. Fig. 22 shows the cylindrical receiver for molten salt of the Crescent Dunes plant, consisting of 14 single-pass, straight-tube panels, each with 66 vertical tubes [20]. The receiver height is 30.5 m.

Solar Tower Systems

709

Fig. 22 Receiver of a molten salt solar tower system (Crescent Dunes, United States). Reproduced from SolarReserve, Available from: http:// www.solarreserve.com/en/global-projects/csp/crescent-dunes; 2016 [accessed 20.09.16].

During normal operation, the molten salt is passing in a defined way through the panels. The thermophysical properties of molten salt require relatively high flow velocities in the tubes to keep temperature gradients between metal tube and molten salt bulk temperature acceptable. As a consequence, the pressure drop of the receiver is also relatively high. The commonly used molten salt mixture gets solid at temperatures below about 2301C. Temperatures below this value occur in the receiver during nonoperation, start-up, shut-down or when clouds pass over the heliostat field. In such cases the receiver is drained by opening valves at the bottom and vents on top of the receiver. The molten salt is then collected in the cold storage tank. Before refilling, the associated components must be preheated to avoid freezing during the filling process. This is done by electrical trace heating on the piping and on receiver components. On the irradiated sections of the receiver, preheating is also done with careful application of low concentrated solar radiation from selected heliostats. Similar tube receiver configurations are used in direct steam receivers where pressurized water is directly heated, evaporated and then superheated in the tubes (see Section 4.17.6.1). To reduce thermal loads, the receiver has separate sections for the different process steps, for example, for superheating the steam after separation in a steam drum. This ensures clearly defined operating conditions on the different receiver sections. Although technically feasible and also used in commercial plants, direct steam receivers are not expected to become commercially viable in the future, mainly because of the lack of a cost-effective thermal storage option for direct steam systems. Another solar tower concept uses an open volumetric air receiver to heat atmospheric air to temperatures of about 7001C [21]. A volumetric receiver uses highly porous absorber structures like ceramic matrices or foams that allow the concentrated solar radiation to penetrate into the structure, so that the radiation is absorbed in the volume. Ambient air is sucked through the porous structure with large inner surface and is heated while passing. The hot air is then directed either to a heat recovery steam generator (for direct electricity generation) or to a storage system for later use (Fig. 23). A test and demonstration power plant using a volumetric air receiver is installed in Jülich (Germany) with a steam cycle of 1.5 MWe and a fixed bed regenerator storage with a storage capacity of about 1 h full load operation. In this plant the air is heated to 6801C by passing through a porous silicon carbide (SiC) honeycomb absorber structure. The receiver is built up in a modular way from small absorber elements held in a steel support structure (Fig. 24). The honeycomb absorber modules have a size of about 0.14 m  0.14 m and a depth of about 0.06 m. The state of the art absorber design has channels of 2-mm width and wall thickness of 0.8 mm. Unlike in the pipe receivers described above in a volumetric receiver the air is heated completely in parallel in a short section of few centimeters while passing through the channels. Therefore, the flux density should be very high (up to 1000 kW/m²) and the air mass flow is rather small (B0.5 kg/s m² receiver average). The air mass flow is adapted to the flux profile across the receiver aperture by means of passive orifices and active flaps [22].

4.17.3.4

Tower

In order to achieve high solar field efficiencies (i.e., minimizing shading and blocking of heliostats), the receiver has to be mounted at a certain height above ground. For this purpose, a tower is installed bearing the receiver on top. In addition, equipment for the heat transfer loop and often for heliostat calibration is installed on the tower. Several concepts for the tower structure are applied:

•

concrete tower, usually erected by slip-cast forming,

Solar Tower Systems

710

Circulation of air Sun

Steam generator

Water/steam cycle Turbine

ling

Receiver

ergy as a densit y res u lt of bun d

Power supply to grid Generator

h en

Cooling water system

Recirculation cooler

Hig

y tion densit radia nergy lar ir Low e

al so Norm

Thermal storage module

Blower

Feedwater tank with degasifier Feedwater pump

Array of mirrors / heliostats

Condenser Ambient air Cooling water pump

Fig. 23 Scheme of a solar tower plant with open volumetric air receiver. Reproduced from Koll G, Schwarzbözl P, Hennecke K, et al., The solar tower Jülich – a research and demonstration plant for central receiver systems. In: Proceedings of solarPACES conference, September 15–18, 2009, Berlin, Germany; 2009.

Fig. 24 Detail of volumetric receiver at the solar tower plant in Jülich.

• •

steel lattice tower, and steel tube tower (as used for wind turbine towers).

The concept selection depends on the system configuration (tower height, component weight, etc.) and local manufacturing capabilities and cost conditions. Most state-of-the-art large solar tower plants are nowadays built with concrete tower. Two examples of towers are shown in Fig. 25.

4.17.3.5

Storage

The inclusion of thermal storage is the most important distinctive feature compared to other renewable energy sources like PV and wind turbines. Thermal storage is relatively inexpensive and is therefore built with large storage capacities, even for 24 h operation.

Solar Tower Systems

711

Fig. 25 Commercial tower configurations: concrete tower (left) (Reproduced from Mehos M, Turchi C, Vidal J, et al., Concentrating solar power Gen3 demonstration roadmap technical report NREL/TP-5500-67464; 2017); steel tower (right) (Reproduced from Bright Source, Available from: http://www.brightsourceenergy.com/image-gallery; 2017 [accessed 19.02.17]).

Fig. 26 Molten salt storage tank. Reproduced from SolarReserve, Available from: http://www.solarreserve.com/en/global-projects/csp/crescentdunes; 2016 [accessed 20.09.16].

The dimensioning of the storage can be tailored according to the specific grid requirements, for example, to provide solar power covering the evening peak typical for some regions like South Africa. By the application of thermal storage, the production of solar power can be decoupled from the collection, as long as the storage is not fully discharged. The type of the storage system is mainly governed by the HTM. Use of large tanks for molten salt storage is state-of-the-art in solar tower technology. Two separate tanks are installed, one for the hot (5651C) and another for the “cold” (2901C) molten salt [23]. When solar radiation is available, molten salt from the cold tank is pumped to the receiver, heated up and passed to the hot storage. For power production, hot salt is pumped to the steam generator and, after being cooled there, fed back to the cold storage. The generated steam drives a conventional steam turbine with a generator. Fig. 26 shows the storage tank of a 110 MWe solar tower plant, with a storage capacity of 10 h full load operation.

712

Solar Tower Systems

Losses in molten salt storage systems are mainly influenced by the insulation of the tanks and are usually very small, typical energy losses are in the range o1% per day. For direct steam generating systems, storage is a critical issue. For short storage periods (up to 2 h) the Ruths storage concept is used in some plants [24]. This concept requires large, pressurized storage vessels, partially filled with water at saturation temperature. During charging, steam from the receiver is condensed in the water, leading to an increase in water temperature and pressure. During discharge the pressure is reduced, resulting in partial evaporation of the water, associated by a decrease in water temperature. However, due to the high pressure and temperature, the vessels are very expensive and only economically viable for short storage periods. For solar tower systems with ambient air as HTM (as described in Section 4.17.3.3 and shown in Fig. 23) a regenerative thermal storage can be used [25]. This storage type consists of a packed bed of solid fillers, honeycombs, or checker bricks with high surface area usually made from temperature resistant ceramic materials like alumina. For charging the storage hot air is led through the packed bed from top to bottom transferring the sensible heat to the solid filler material. For discharging cold air is passing through the storage from bottom to top heating up to the top temperature. In the solid material a so-called thermocline zone develops passing up and down the packed bed when the storage is discharged or charged, respectively. This type of storage is used in the demonstration plant Solar Tower Jülich with a capacity of about 9 MWh.

4.17.3.6

Power Block

Conventional steam cycles are the established technology for the thermal cycle in current solar tower systems. As operation with the standard molten salt is so far limited in temperature to about 5651C, life steam conditions of about 5401C and 115 bar are used today. A typical steam cycle configuration includes reheat and multiple preheating stages. Whenever possible, wet cooling, or hybrid cooling of the power block is applied. However, as solar tower systems are typically located in very sunny and dry regions, dry cooling is the most installed technology. Dry cooling implies an increased condenser temperature and increased blower power consumption, but resulting in a slightly reduced power block net efficiency. Typical power block efficiencies in modern solar tower systems are in the range of 40%.

4.17.3.7

Hybridization

A solar tower system can be understood as a conventional power plant where the thermal energy is provided by solar energy. With the addition of an appropriate burner system as backup, the heat can also be provided by fossil fuels like oil or natural gas. This enables full dispatchability of the power plant at any time, an important asset for grid stability and control. As the backup is only operated when there is insufficient solar energy available over a longer period (i.e., the storage is empty) and there is a lack of available power capacity in the grid, the total annual fuel consumption can be very low. However, ensuring the capacity to the grid is a valuable feature and can avoid keeping other power plants in stand-by, thus avoiding the associated losses.

4.17.4 4.17.4.1

Analysis and Assessment Efficiency Parameters

The overall efficiency of a solar tower system (as instantaneous value) is defined as ratio of the electric power produced to the available solar radiation, which is defined as the direct normal radiation times the total reflective mirror area. It can be expressed as product of the efficiencies of the subsystems heliostat field, receiver and power block: Ztotal ¼

Pel Pel Pint Pth Pel ¼
¼
¼ Zfield
Zrec
Zpb Psolar Pint Pth Psolar nHel
AHel
DNI

The efficiency of the heliostat field is defined as ratio of the concentrated solar radiation entering the receiver aperture, the so-called incident power, to the available solar radiation. It can be expressed as product of the efficiencies for cosine, blocking and shadowing, reflectivity, atmospheric attenuation, and intercept: Zfield ¼

Pint Pint ¼ Zcos
Zb& s
Zref l
Zatm
Zint ¼ Psolar nHel
AHel
DNI

Typical values for a commercial-size heliostat field are

Instantaneous Annual average

Zcos

Zb&s

Zrefl

Zatm

Zint

Zfield

80% 78%

98% 94%

94% 90%

93% 92%

95% 90%

65% 55%

In a similar way the efficiency of a single heliostat can be defined: ZHel;i ¼

Pint;i Pint;i ¼ Zcos;i
Zb& s;i
Zrefl;i
Zatm;i
Zint;i ¼ Psolar;i AHel
DNI

Solar Tower Systems

713

Values can be as high as 82% at the north of the tower and as low as 50% at the south of the tower (instantaneous values). The efficiency of the total field can be expressed as the mean value of all heliostat efficiencies: P P P Pint;i Pint;i Pint 1 X i Pint;i ¼ ¼ ZHel;i ; if AHel;i ¼ AHel f :a:i ¼Pi
¼ P i Zfield ¼ Psolar P n
A
DNI n A
DNI Hel Hel Hel Hel;i i solar;i i i

The receiver efficiency is defined as the receiver thermal power divided by the incident power from the field. It is often calculated from the absorptivity of the absorber and the radiative and convective heat losses. Values are strongly depending on receiver technology and vary from 75% to 490%. Zrec ¼

_ _ loss Q Q Pth ¼ Zabs ¼ abs Pint Pint

_ loss;rad þ Q _ loss;conv Q Pint

The efficiency of the power block is defined as the electric power from the generator set divided by the heat rate from the receiver or storage. Typical values for Rankine cycles lie in the range from 30% to 42%. Zpb ¼

Pel Pth

For all these efficiencies annual average values can be calculated by integrating over time, for example, for the total plant: R R R Z Pint dt Pth dt Pel dt Pel R
R
R ¼ Zfield
Zrec
Zpb Ztotal ¼ dt ¼ Pint dt Pth dt nHel
AHel
DNIdt t Psolar

For the heliostat field: P R P Z P Z Pint 1 X i PRint;i dt i Pint;i i Pint;i R  ¼ P dt ¼ P ) Zfield ¼
dt ¼ ZHel;i ; if AHel;i ¼ AHel f :a:i ¼ P n n
A
DNIdt A
DNIdt solar;i Hel Hel Hel Hel t t Psolar i i i

4.17.4.2

Economic Parameters

Solar tower systems are, like most renewable energy systems, a very capital cost intensive way of power generation. While the solar radiation itself (i.e., the “fuel” of the power plant) is available for free, the equipment to harvest this energy source has to be installed completely before production starts and has to be maintained productive for a technical lifetime of 25 years and more. Therefore, the most important economic parameters are the investment cost for the installations (plus the related cost of financing) and the cost for maintenance of the components.

4.17.4.2.1

Investment cost (CAPEX)

The investment cost, or capital cost expenses (CAPEX), account for approximately 80% of the total cost of a solar thermal power plant. Solar tower technology is at an early stage of commercial deployment, even when compared to other solar technologies, like PV. While the market prices for the conventional components (i.e., steam generator, turbine, electric generator, cooling system, etc.) are mostly well known, the market for solar specific components is still developing and cost data bears a level of uncertainty. Fig. 27 shows the typical cost breakdown of a state of the art molten salt solar tower with storage. The solar components (heliostat field, tower, and receiver) account for approximately half of the total initial investment cost. From the solar components more than 2/3 are related to the heliostat field. The thermal storage accounts for almost 10% of the total investment cost for a storage capacity of 15 full load hours (for 9 h capacity the expenditure for storage would be about 8% of the total investment). In absolute numbers, total investment cost varies between about 7500 US$/kWe for 9 h storage and 10,500 US$/kWe for 15 h storage [26]. Tower

Heliostat field

Owners costs Balance of plant Contingencies Engineering and site preparation

Receiver system

Thermal energy storage Power block

Fig. 27 Typical total installed cost breakdown for 100-MW solar tower plant with 15 h storage. Reproduced from IRENA, Renewable energy technologies: cost analysis series, Volume 1: power sector issue 2/5, concentrating solar power. In: Working paper, International Renewable Energy Agency (IRENA); 2012.

714

Solar Tower Systems

Table 2

Breakdown of heliostat installation cost [7,27]

Subcomponent

Cost fraction

Mirror Structural support Pedestal and foundation Position sensors & control Drives Assembly & installation

25% 15% 15% 5% 30% 10%

4.17.4.2.1.1 Heliostat investment cost The heliostat field is the most important single cost element of a solar tower plant. It is most common to specify the heliostat field cost as specific cost per installed m² reflective area. The installed cost figures include engineering, fabrication, transport, assembly, cabling, lightning protection, and acceptance tests of the heliostat. Values found in literature state 160–250 US$/m² for current installations and set 75–120 US$/m² as goal for 2020 [8]. A cost breakdown of the heliostat investment cost is shown in Table 2. 4.17.4.2.1.1.1 Tower investment cost The tower can be built of different types of structures (see Section 4.17.3.4). Therefore, data found in literature shows a significant variation in tower cost. The estimated cost for a tower of 150 m height, for example, lies between 5 and 20 Mio US$ [28]. 4.17.4.2.1.1.2 Receiver investment cost The investment cost for the receiver is usually given as specific value in US$/kWth or US$/m2. The scope of supply for the receiver system normally contains – additionally to the actual absorber – pumps, valves, piping, vessels, and heat tracing elements (if needed). Published values for the specific investment cost for a molten salt receiver typically range from 280 to 200 US$/kWth for today and and from 170 to 150 US$/kWth for the near future [29]. Recent publications are even more optimistic, stating 125 €/kWth for today and expecting about 100 €/kWth for 2020 and about 80 €/kWth for 2030 [30].

4.17.4.2.2

Annual cost of operation and maintenance (OPEX)

The running expenses during the lifetime of a solar tower plant are lower than for a conventional combustion-based power plant as no fuel costs occur. Operational costs include mainly labor and utilities. An important operational cost item is, for example, for cleaning of the mirrors. The cost for maintenance is dominated by material for component repair and exchange and for external services (e.g., turbine inspection and overhaul). A significant amount of OPEX is also spent for insurances. The annual amount of operation and maintenance costs typically lies in a range of 1%–2% of the total capital investment.

4.17.4.3

Levelized Cost of Electricity

The most common assessment criterium for the economy of a solar tower plant is the so-called LCOE [31]. The LCOE represents the equivalent cost of each unit of electricity ($/kWh) generated during the lifetime of the project taking into account the initial investment (CAPEX), operation and maintenance costs (OPEX), and financing costs associated with interest on loans. We present here the simplified method for LCOE calculation that does not include tax payments and the expected internal rate of return on equity nor any other project specific financial parameter. Therefore, this LCOE does not represent the real generation cost or the selling price of the electricity. This LCOE is very much related with the technology itself and is therefore preferred to compare different technologies on a common basis. The simplified IEA-method is based on the following assumptions:

• • • • • •

100% debt financing, operation time ¼depreciation period, annuity method for depreciation of capital cost, taxes are neglected, neglect inflation and price increases during the construction period, and neglect inflation and price increases regarding O&M, insurance, etc. during operation, Using these assumptions the LOCE can be calculated as: LCOE ¼

CAPEX  FCR þ OPEX i
ð1 þ iÞn and FCR ¼ Eel;annual ð1 þ iÞn 1

with FCR is the fixed charge rate, i is the debt interest rate, n is the project lifetime, and Eel,annual is the annual electricity production.

Solar Tower Systems

715

Estimated values for LCOE of solar tower projects range from 16 to 28 US¢/kWhe in 2011, expected values for 2020 range from 8 to 16 US¢/kWhe [26]. The large bandwidth of values reflects the high sensitivity of LCOE to cost estimates, financing parameters, plant design, and solar resource. A recent study [32] evaluated the actual cost and learning rate of CSP technology. The cost development of all operating CSP plants and those under construction was examined. In addition, the role of capacity growth, industry continuity, and policy support design was analyzed. Several CSP expansion phases were identified, each characterized by different cost pressure in the policy regime and different industry continuity. In 2008–11, with low cost pressure and following industry discontinuity, costs increased. In the current phase, with high cost pressure and continuous industry development, costs decreased rapidly, with learning rates exceeding 20%. Data for projects under construction suggest that this trend is continuing and accelerating. The authors expect that if support policies and industrial structure are sustained, CSP will experience significant further cost reductions.

4.17.4.4

Additional Value of Dispatchability

The LCOE values of solar tower plants suggests that this technology is still not competitive to more mature renewable power generation (onshore wind or PV) in most regions of the world. But solar thermal power technologies with storage have an added value that is not reflected in the LCOE calculation. Future energy systems with a high share of fluctuating renewable energy sources (such as wind and PV) are expected to have temporary large positive or negative differences between production and demand, the so-called residual load, that has to be balanced to maintain grid stability. This residual load cannot be met by further installation of wind and PV, but must be provided by flexible and controllable energy sources, like biomass, geothermal, and solar thermal with storage. These energy sources can deliver electricity when needed, they have a high level of dispatchability. Providing residual load usually is refunded at a much higher price. This holds especially in regions with a high share of fluctuating renewable energy sources, like PV and wind turbines. A case study was made for California, assuming a 40% share of renewables in the grid. Under these conditions the value of dispatchable power from a CSP plant with storage was calculated as 6 US¢/kWh higher than power generated by PV [33]. Studies show also that a certain share of solar thermal power with storage in a regional grid enables integrating even higher shares of fluctuating renewables [34].

4.17.4.5 4.17.4.5.1

Layout and Performance Simulation Heliostat field layout

Unlike most conventional power plants, the operation of a solar tower system is strongly dependent on the regular (daily and seasonal) and irregular (clouds) changing nature of the solar resource. Accordingly, the system layout of a solar tower plant does not follow a simple full-load and part-load calculation but has to consider all possible operation states. Moreover, the layout of a heliostat field, i.e., the definition of the number and positions of the heliostats and the size and position of the receiver on top of the tower is a problem with almost indefinite degree of freedom. Therefore, the layout and performance calculation of solar tower systems is done with computer-based simulation models. The most important simulation task, the calculation of the flux density distribution of the reflected sunlight on a target plane, can be done with two different mathematical methods. 1. The convolution method is based on the mathematical description of the flux density distribution on the target as the convolution of the solar brightness distribution (sunshape) with the error distributions of the mirror (tracking and slope). It can be solved numerically by Fourier transformation and polynomial expansion. A very simple solution is possible when the sun shape is considered to be a circular Gaussian distribution. This leads to a very fast computable model but is also of lower accuracy. 2. The statistical method (also Monte-Carlo or ray tracing method) uses randomly chosen sun rays that are traced from their origin on the sun disk to the reflection on the mirror and further to the intersection with the target plane. The brightness distribution on the sun disk, the uncertainty of the facet orientation and the waviness of the local mirror surface are described by statistical distribution functions. Ray numbers of thousand rays per m² mirror surface area and beyond are normally considered leading to several millions of processed rays. Nevertheless, the ray tracing method is dominant today because of the enormous advancement in computer technology [35,36]. Based on these optical models different methods for heliostat field layout have been proposed that can be categorized roughly into five groups: 1. The “Cellwise Method” is based on the subdivision of the heliostat field into cells of uniform heliostat density; only one representative per cell has to be calculated; after cell densities are optimized a subsequently applied algorithm defines the individual heliostat positions in the cells using parameterized layout patterns [37]. 2. The “Selection Method” calculates every single heliostat of an oversized field defined by a regular pattern and selects the best performing ones to meet a certain design power requirement; although a lot of computational effort is necessary here, this method allows the generic design of very individual fields and many of today’s codes are based on the Selection Method [38,39]. 3. In the “Heliostat Growth Method” the field is built up one by one by setting each heliostat on the best available position and recalculating the annually available energy on the remaining free ground [40].

716

Solar Tower Systems

4. The “Boundary Factor Method” is similar to the Selection Method but requires less computational effort; heliostats of an oversized field are placed on positions where the neighbor-independent performance parameters (including receiver view angle, cosine and atmospheric attenuation) are above a certain limit, the boundary factor [41]. 5. The method of “Unrestricted Refinement” is the most straight forward layout procedure but it requires the largest amount of computational effort due to the enormous degree of freedom; starting with a predefined field of a fixed amount of heliostats discrete alternative positions around each heliostat are assessed by calculation of the annual performance of the local subfield of neighboring heliostats around the heliostat in question [42]. The most important parameters that are influencing the layout of the solar system (i.e., heliostat field, tower, and receiver) are

• • • • • • •

the the the the the the the

site location (latitude, altitude), atmospheric condition (aerosols, haze, and clouds), heliostat size, geometry and optical quality, shape and acceptance angle of the receiver aperture, receiver thermal losses (depending on the aperture size), power level, and cost ratio of the main components (heliostats, receiver, and tower).

The dependence of the field layout on latitude, power level, and heliostat quality were shown in Section 4.17.3.1.4. The acceptance angle of the receiver can have a very strong influence on the field layout. Secondary concentrators, as described in Section 4.17.3.1.5 and used, for example, pressurized receivers, show a considerably limited acceptance angle. As a consequence heliostats must be positioned further away from the tower inside the intersection of the view cone with the ground (Fig. 28). The influence of aerosols in the lowest atmospheric layer is still a matter of research. As pointed out in Section 4.17.3.1.3 the reflected sun light is being scattered and absorbed in the atmosphere while passing from a heliostat to the receiver. For locations with high aerosol content in the lowest atmosphere denser field design and lower towers will be favored accepting higher losses through blocking and shading. Further, it may be necessary to limit the maximum size of a single heliostat field and build more but smaller tower systems.

4.17.4.5.2

Annual performance calculation

To assess the amount of energy that can be produced by a specific plant on a certain location an annual performance calculation is usually performed, i.e., the hourly simulation of the solar tower system operation using a complete power plant model. It is 0

606

4 9 14 18 23 28 32 37 42 46

0

630

51 56 60 65 70 74 79 84 89 93 (%)

−590

Fig. 28 Typical field layout for receiver with secondary concentrator. The color scale indicates the transmission factor of the light coming from a certain position.

Solar Tower Systems

717

essential for this task to have meteo and solar radiation data of high quality that are representative for the site location. A temporal resolution of at least hourly data is required. For commercial projects it is common to use measured hourly DNI data of several years to calculate the average annual yield of a solar tower plant. Depending on the degree of detail that is of interest the models for the annual performance calculation can be more or less sophisticated physical models, mostly of steady-state except for components with large time constants like the thermal storage or the receiver for start-up and shutdown. Often look-up tables are used for components that have been modeled in detail with another more specialized simulation tool (e.g., rankine cycle, steam turbine, and heliostat field). Well-known software tools for annual performance calculation are SAM [43], GREENIUS [44], and EBSILON [45]. To perform an annual performance calculation the operation strategy has to be defined as well, which can be either of the following:

• • • •

base load (24 h constant electric output), intermediate load (12 h to 16 h of constant power generation), peak load (10 h operation or less, focused on time of maximum demand), and load following (generating power according to a load curve, often triggered by corresponding feed-in tariffs).

The dimensioning of the solar part (heliostat field and receiver), the storage and the power block are strongly depending on the choice of the operation strategy. Hence, the annual performance calculation is also necessary for the layout process. A typical example can be found in Fig. 29 where the influence of storage size on specific cost of electricity is shown for a certain electric power level. The SM, defined as the ratio of the receiver design power to the power block heat demand, is varied from 1.5 to 3.5. For each of these cases of oversized solar parts the storage size is varied and the specific cost of generated electricity is calculated after a full annual performance simulation. The larger the SM the larger is the optimum storage size. For this specific plant, location and operation strategy the overall cost optimum is at SM of 2.5 and storage size of 11 h (Fig. 29).

4.17.4.6

Plant Operation and Control

As the energy source to the system, the solar irradiation, cannot be controlled like the fuel of a fossil plant, operation of solar power plants is a challenging task. Due to the variable nature of the solar source solar tower power systems are dynamic processes that are operated outside their design conditions most of the time. The thermal storage “buffers” the fluctuating heat input of the supply side and enables a dispatchable power production.

4.17.4.6.1

Definition of control tasks

A solar tower plant consists of the collector system, the receiver, the storage with the HTF circuit and the power block itself, usually a Rankine cycle with a steam turbine generator set. Accordingly, the main control systems are structured in a similar manner (Fig. 30). The objective of the power block control is to deliver the desired electric output. This defines the heat demand that has to be provided by the HTF and storage system. The receiver control regulates the HTF mass flow through the receiver, usually so that a fixed HTF receiver outlet temperature is maintained. The task of the solar field control is to direct each heliostat to its specific aim point on the receiver surface. Each component control system is subdivided into specific control structures to control local actuators. For example, each heliostat has a local heliostat control unit for the drives and the communication with the central heliostat field control. The coordination of the component subsystems is taken over by the plant operational control. Here, the set points for the subsystems are defined, for example, with model-based optimization methods. Above that acts the plant management or scheduler system that defines in which state the plant should be operated to optimize the revenues on an overall basis.

4.17.4.6.2

Heliostat field control

The motion of the heliostat drives to reflect the solar radiation to the desired aim point on the receiver aperture is usually controlled by an open loop control strategy. The control unit calculates the current position of the sun from the geographical

Relative LCOE (−)

120%

110% SM 3.5 SM 3.0

SM 1.5 100% SM 2.0

SM 2.5

90% 0

2

4

6

8

10

12

Opt. storage capacity (h) Fig. 29 Influence of storage size and solar multiple (SM) on specific cost of electricity [46].

14

16

18

20

718

Solar Tower Systems

Plant management / planning / scheduling

Hours..days

Plant operational control

Heliostat field control system

Receiver control system

Storage and HTF control system

Minutes...hours

Power block control system Seconds...minutes

G Subsecond

Fig. 30 Control system hierarchy and characteristic time windows.

coordinates of the plant and the time. From the known position of the heliostat and the aim point on the receiver aperture the desired direction of the heliostat normal vector is calculated. This determines the heliostat orientation in two axes, usually azimuth and elevation. The respective drives are moved to the desired value, which is controlled by encoders on the axes. No direct check is usually performed to verify that the heliostat’s reflected image is directed to the desired aim point. Several effects can lead to deviations of the real from the desired aim point (i.e., tracking error, see also Section 4.17.3.1.3):

• • • • • •

uncertainties in exact heliostat positions, geometrical dimensions, and axis orientations, heliostat drive tolerances and backlash, defective encoder signals and finite encoder resolution, heliostat structural deformation due to external forces like gravity or wind loads, imperfections of the solar position algorithm, and imprecise knowledge of geographical coordinates and directions.

Typical tracking errors due to these error sources are in the order of magnitude of 1–2 mrad, which would be unacceptably high. Therefore, a regularly repeated off-set correction is performed, where a heliostat is directed to a reflecting target below the receiver and a camera observes the deviation of the image on the target from the desired aim point (see also Section 4.17.3.1.3). A corrective motion of the drives is calculated and performed and included in an error model that describes the systematic error sources. Like this, the tracking errors can be reduced to below 1 mrad. Closed loop tracking control using charge coupled device (CCD) cameras close to the receiver is described in literature but not yet widely used. Different types of control architecture are used today with their specific characteristics. In a strongly centralized control system the solar position and the orientation of each single heliostat is calculated in the central control unit. The rotating angles are also calculated centrally and communicated to the local drive controllers to perform the movement. A large amount of data traffic is necessary in this setup but local control units can be kept very simple. In a very decentralized control design the central unit only communicates the desired aim point on the target and the required calculations of solar position and orientation are performed and executed by the local controller. Here, data traffic is reduced but elevated controller capabilities are needed.

4.17.4.6.3

Aim point distribution

To minimize spillage losses, heliostats should aim at the center of the receiver aperture. But material constraints regarding maximum temperature and heat load on the receiver surface make it necessary to spread the focal spot of the heliostat field, i.e., to distribute the heliostat’s aim points on the receiver aperture. To reduce the degree of freedom of this task, usually a small number of aim points is defined manually on the aperture and heliostats are assigned to these aim points according to their image size (which corresponds more or less linearly with their slant range): heliostats standing in large distance from the target produce large images and are assigned to central aim points (i.e., large distance from aperture edges); heliostats standing closer to the target produce smaller images and are assigned to outer aim points

Solar Tower Systems

719

(i.e., closer to aperture edges). Heliostats are often assigned in groups of neighboring heliostats and assignment is often done manually by the operator. Changing of the assignment during the day can be necessary as the heliostats’ images change in size and shape according to the solar position or due to changing receiver requirements. Model-based algorithms have been proposed in literature to optimize the aim point distribution on the receiver aperture, i.e., to define the aim points and assign the heliostats to these aim points in a way that the concentrated sunlight can be processed by the receiver in the most efficient way while meeting all temperature and load limits [47]. This task should be repeated during normal operation every 15…60 min. In literature a heuristic optimization method is described based on a ray tracing model of the heliostat field and a model of the receiver performance as a function of the flux distribution [48]. A discrete optimization problem is created by defining a grid of possible aim points on the receiver aperture. To solve the combinatorial task of assigning the heliostats to the aim points in an optimal way the so-called ant colony optimization metaheuristic is used. To speed up the process the flux density of each single heliostat aiming at each aim point is pre-calculated by ray tracing before the actual optimization of a certain time point. During the optimization process these flux images are used as partial results and superposed to save computation time. When during normal operation the receiver reaches an upper temperature limit somewhere on its surface an immediate response is necessary. There are basically three options:

• • •

shifting of one or more aim points (including the assigned heliostats) away from the hot spot, reassignment of single heliostats or groups to another aim point, and defocusing of single heliostats or groups.

Which of these options is chosen depends on the receiver technology, the heliostat type and size and the overall operational control strategy. For a cylindrical molten-salt central receiver the aim points are usually spread vertically off from the equator of the cylinder toward the upper and lower rim according to the heliostat’s beam radius. The allowable flux density on the receiver surface is depending on the local salt flow rate and temperature. The allowable flux is high where the molten salt enters into the receiver (B1000 kW/m²) and decreases down to below 400 kW/m² as the salt temperature rises while passing through the receiver. In Ref. [49] a method for the protection of a molten salt receiver against excess flux during operation is described. An automatic system is used based on a model simulating the heliostat field and the reflected light on the receiver surface. The system identifies the heliostat producing the highest flux density at the affected location and subtracts its image from the absorbed flux. This procedure is repeated until the local flux peak is evened out. Then the identified heliostats are removed from track.

4.17.4.6.4

Operation strategy

The operation strategy of the overall plant depends strongly on its task (base, intermediate or peak load, or load following, see Section 4.17.4.5.1) and on the amount of hybridization (co-firing). Here, the operation strategy of a solar-only tower plant designed for intermediate load shall be described as an example (Fig. 31). In the morning before sunrise the power block is started with heat from the thermal storage. As soon as direct solar heat is available the used heat rate from storage is reduced accordingly. When the solar heat from the receiver exceeds the required rate from the power block the surplus is fed to the thermal storage. When the thermal storage is full (here: in the afternoon) the solar heat rate has to be reduced to the required amount, usually by defocusing parts of the heliostat field. In late afternoon, when the receiver power falls below the required amount, the storage begins to be discharged. After sunset, the plant can be operated for additional hours solely from storage. The plant can be shut down to keep enough stored heat for operation in the next morning. During operation, the plant can deliver a constant output of electricity independently from direct sunshine. In more detail, the power output level as well as startup and shutdown times are influenced by the feed-in tariff structure and the weather forecast for successive days.

4.17.4.7

Material Lifetime and Degradation

Due to the high and varying temperatures especially in the receiver components, material selection is an important issue. Corrosion, creeping and low-cycle fatigue must be considered during design. Expensive high temperature alloys (e.g., Ni-based superalloys) are typically used in critical sections.

Thermal heat

Solar heat input Not used From storage To storage

Directly used

From storage Time of day

Fig. 31 Thermal heat usage of solar only tower plant in intermediate load operation.

720

Solar Tower Systems

Degradation of the reflector mirrors is another important durability aspect. So far, glass is the material of choice, especially due to its resistance against abrasion from dust particles. These particles settle on the reflector surface continuously, with a rate depending on the specific site conditions. During night, dew is often appearing on the reflector surface, leaving the particles firmly attached to the surface after evaporation. Therefore, periodical cleaning with brushes and/or water spraying techniques is necessary. Glass has shown high durability under these cleaning conditions. Other reflector materials like aluminum reflectors or coated polymer films have shown less durability so far.

4.17.5

Case Study for a Solar Tower Plant

As an example for a typical solar tower plant, a case study was prepared for a plant in Chile. The presented data is a compilation of data from Ref. [50]. The layout was made for the site Crucero in the region of Antofagasto, which is a region with excellent annual DNI values: the annual DNI (based on measured data) sums up to 3482 kWh/m²a, probably one of the highest values worldwide. The selected site is located at 221160 South, 691350 West, at an altitude of 1182 m above sea level. It should be noted that the site is favorable for several reasons:

• • •

it is located in a very dry region with only a few cloudy days per year, it is at a relatively high altitude where attenuation of the solar radiation is minimal, and the average ambient temperature is relatively low, improving efficiency of the power cycle due to low condenser temperature.

For these reasons the plant performance results in an excellent annual energy yield. In other locations, lower specific annual yield from a comparable solar tower plant will result from lower annual DNI values, more times with part load operation and higher condenser temperatures. The assumptions for the layout are summarized in Table 3. The layout was carried out using the solar tower layout tool HFLCAL [38]. The layout resulted in the following solar tower plant specifications:

• • •

heliostat field: 10032 heliostats, surround field, receiver: external, cylindrical, tube receiver, 18.8 m diameter, 21.44 m height, and tower: 286 m height, 25 m diameter.

The corresponding heliostat field layout is shown in Fig. 32. The colors of the heliostats correspond to their annual efficiency, with the scale shown on the left. It should be emphasized that this layout is an example for a plant using the mentioned assumptions. For each specific plant, an optimized layout has to be made taking into account the specific conditions of the project (e.g., DNI conditions, landscape, microclimate, load conditions, financing, tariff conditions, etc.). Fig. 33 shows a waterfall diagram of the specific efficiencies of the solar tower plant in Chile. The efficiencies were evaluated for DP conditions. As DP, solar noon on March 21 (equinox), with a DNI of 971 W/m² was chosen. The most significant loss is the cosine loss, caused by the fact that the sun rays are usually impinging on the heliostat not perpendicular, but at a certain incidence angle. Then only the projected mirror area is reflecting sunlight, with the area ratio given by the cosine of the incidence angle. Other significant loss contributions are from the limited reflectivity of the mirrors and the receiver efficiency, followed by atmospheric attenuation between the heliostats and the receiver. Intercept losses (so-called “spillage”), blocking and shading have only minor contributions to the losses. The receiver efficiency is dominated by the solar reflection loss (7%), followed by thermal radiation and convection losses. The daily power characteristic of the heliostat field is shown in Fig. 34 for equinox (21.03.) and winter and summer solstice (21.06. and 21.12.). The corresponding thermal receiver power is shown in Fig. 35. In the course of the day there is a pronounced variation in the thermal power output, with a sine-like characteristic peaking at noon. As the site is further away from the equator, Table 3

Base assumptions for a solar tower plant in Chile

Solar tower system configuration

Molten salt system

Heliostat size (width/height) Reflecting heliostat area Average reflectivity (incl. dusting) Beam error (incl. sunshape, slope, and tracking error) Receiver Type: Inlet/outlet temperature Thermal power (design point (DP)) Plant solar multiple (SM) Nominal electric power output Power block efficiency (DP)

9.57 m/12.93 m 121 m² 88.4% 3.664 mrad External, cylindrical tube receiver 2951C/5651C 682 MW 3 (Corresponds to a storage capacity of about 15 h) 100 MW 44%

Solar Tower Systems

55

721

1344

56 57 59 60 61 63 64 65 67 68

1149

–1553

69 71 72 73 75 76 77 79 80 81

–1337 (%)

Fig. 32 Heliostat field configuration for 100 MW plant with 15 h storage (south toward left).

100 90

Absolute

Efficiency (%)

80

Cumulative

70 60 50 40 30 20 10

ei ve r R

ec

ep t rc te In

tte m .a

At

at

nu a

ck i

tio n

ng

ity H

el io

st

R

ef le

bl o

ct

ad sh at st

io el H

iv

in g

in e os C

Av ai la

bl e

0

Fig. 33 Design point (DP) efficiencies of a solar tower system in Chile.

the daily energy yield varies slightly with the season. This is expressed both in the peak receiver power as well as in the daily operation time, as shown in the figures. The thermal energy output of the receiver over the complete year is predicted theoretically as 2197 GWhth/a. Assuming an annual energy loss of 1% in the storage system and an annual average thermal efficiency of 42% in the power block, this would

722

Solar Tower Systems

Power from field to receiver (MW)

800 700 600 500 400 21.03

300

21.06

200

21.12

100 0 6

8

10

12 Time of day

14

16

18

14

16

18

Fig. 34 Heliostat field power to receiver as function of season and time of day.

Thermal receiver power (MW)

800 700 600 500 400 21.03

300

21.06

200

21.12

100 0 6

8

10

12 Time of day

Fig. 35 Receiver power as function of season and time of day. Reproduced from Bright Source, Available from: http://www.brightsourceenergy. com/image-gallery; 2017 [accessed 19.02.17]).

translate into an annual electricity production of 914 GWh/a. However, operating a 100 MWe power plant for a full year (8760 h) would result in a maximum electricity production of 876 GWh/a, somewhat lower than the predicted energy yield of the solar tower plant. The discrepancy can be mainly explained by so-called “dumping” losses. Dumping losses occur when the available thermal power output of the receiver exceeds the power that the power cycle and the storage can absorb (see also Fig. 10). This is mainly the case when in the afternoon of some days the storage is fully charged. If so, an appropriate number of heliostats are defocused and thus the power output of the receiver is reduced accordingly. The remaining focused heliostats provide just the power to feed the power cycle with the required thermal input. Dumping losses are the accepted result of the technoeconomic system optimization, leading to a certain oversizing of the heliostat field. Even though some energy is wasted (“dumped”) on certain days, more energy can be accumulated on other days in the course of the year, when the storage cannot be completely filled during the day. On an annual basis, this can result in a lower LCoE or a better match between power supply and demand. It is important to note here that for systems with storage the produced thermal power does not correspond to the power fed into the power cycle. In such systems the power cycle is designed for a nominal electric power that can be generated with a fraction of the receiver design power. The excess thermal power is used for charging the storage. The oversizing of the heliostat field is usually expressed by the so-called “solar multiple” (SM) that is simply the ratio of the design thermal receiver power to the thermal power required to operate the power block at nominal load.

4.17.6

Examples of Solar Tower Plants

The following two examples are operational solar tower plants and can be considered as examples for the state-of-the-art in this technology. Comprehensive information about other CSP and solar tower plants can be found for example in Refs. [51,52]. The third example is a demonstration plant using air as HTF.

Solar Tower Systems 4.17.6.1

723

Ivanpah Solar Energy Generating System

The Ivanpah Solar Energy Generating System (ISEGS) is currently with 377 MW the largest solar tower unit worldwide (Fig. 36). It consists of three similar independent solar tower plants and is located at Ivanpah Dry Lake in California, United States. Total investment cost was about 2200 Mio USD. Further details are listed in the following table. It uses water/steam as the HTF, driving directly the steam turbine, and does not include storage. Further details are listed in Table 4 [7].

4.17.6.2

Crescent Dunes

The Crescent Dunes plant (Fig. 37) is a representative of solar tower systems with high storage capacity, using molten salt as heat transfer and storage medium. The plant has a net power of 110 MW and a storage system for 10 h of full load operation. It is located near Tonopah in Nevada, United States. Further details are listed in Table 5 [7,52]. In current molten salt solar tower designs the receiver is drained during nonoperation periods (night or longer cloud periods), to avoid freezing in the receiver. The drained molten salt is collected in the cold storage tank. For start-up, the receiver and associated components have to be preheated before refilling the system.

Fig. 36 Solar tower plant Ivanpah Solar Energy Generating System (ISEGS) (Ivanpah, CA, United States) [53].

Table 4

Ivanpah solar tower system details

Electric power rating Annual direct normal insolation (DNI) at site Net annual power production Capacity factor Land area Heliostat field Number of heliostats Heliostat area Tower Receiver Heat transfer fluid (HTF) Receiver inlet/outlet temperature Storage Power cycle Cycle efficiency (DP) Fossil backup fuel Begin of construction period Start of operation

377 MW (net total, in 3 independent units) 2717 kWh/m²a 1,079,232 MWh/a (planned) 32.7% 14.2 km² 2,600,000 m² (reflective area) 173,500 15 m² 3 towers, steel framework, 140 m high External tube receiver Water/steam 2501C/5501C None Superheated steam cycle, dry cooling 28.7% Natural gas 2010 2014

Reproduced from NREL, Available from: http://www.nrel.gov/csp/solarpaces; 2017 [accessed 25.02.17].

724

Solar Tower Systems

Fig. 37 Solar tower plant Crescent Dunes (Tonopah/United States). Table 5

Crescent Dunes solar tower system details

Electric power rating Annual direct normal insolation (DNI) at site Net annual power production Capacity factor Land area Heliostat field Number of heliostats Heliostat area Tower Heat transfer fluid (HTF) Receiver Thermal power (design point (DP)) Receiver inlet/outlet temperature Storage Storage capacity Power cycle Begin of construction period Start of operation

110 MW net 2685 kWh/m²a 500 GWh/a 52% 6.5 km² 1,197,148 m² 10,347 116 m² Concrete, slip formed, 195 m high Molten salt (60% NaNO3/40% KNO3) External tube receiver, cylindrical 565 MWth 2881C/5651C Two-tank direct, efficiency: 99% 10 h Steam cycle with reheat, hybrid wet/dry cooling 2011 November 2015

Reproduced from NREL, Available from: http://www.nrel.gov/csp/solarpaces; 2017 [accessed 25.02.17].

Fig. 38 Solar test and demonstration power plant for air receiver technology (Jülich/Germany).

4.17.6.3

Solar Tower Jülich

The solar tower Jülich (Fig. 38) is located west of Cologne, Germany. It was designed as a demonstration plant and is special in that it uses atmospheric air as the HTF which is heated in a volumetric air receiver consisting of multiple SiC absorber modules.

Solar Tower Systems

Table 6

725

Solar tower demonstration plant Jülich

Electric power rating Annual direct normal insolation (DNI) at site Net annual power production Land area Heliostat field Number of heliostats Heliostat area Tower Heat transfer fluid (HTF) Receiver Thermal power (DP) Receiver inlet/outlet temperature Storage Storage capacity Power cycle Begin of construction period Start of operation

1.5 MW net 902 kWh/m²a (Demonstration plant, not continuously operated) 0.8 km² 17 650 m² 2153 8.2 m² Concrete, 60 m high Air External, open volumetric 8.5 MWth 1201C/6801C Single-tank regenerator type, packed bed 1.5 h Superheated steam cycle, dry cooling 2007 2008

Reproduced from NREL, Available from: http://www.nrel.gov/csp/solarpaces; 2017 [accessed 25.02.17].

Each absorber module is built from extruded honeycomb structures, allowing the solar radiation to penetrate into the channels (Table 6) [21].

4.17.7

Future Directions

Based on the LCoE, solar tower systems, like CSP systems in general, are still at a higher cost level than other renewables like PV or wind turbines. However, the latter systems lack the possibility to deliver power on demand, which gives CSP systems with storage and/or hybrid operation capability additional value for the power generation system. In any case, significant further cost reduction is required for CSP systems to get a reasonable share in the power sector. This is especially true for solar tower systems which are at the beginning of their learning curve. A recent report [54] gives an overview over the actual status of CSP and possible ways to improve the technology and thus reduce cost of solar thermal electricity in the future. Some of the future directions for solar tower systems are discussed here in more detail. The increase of the operating temperature of future solar tower systems is considered one of the major challenges. Higher operating temperatures enable the use of more efficient power cycles, but are associated with somewhat increased losses in the solar subsystem. However, numerous studies predict that increased operating temperatures results in lower LCoE. Higher conversion efficiency results in smaller heliostat field size for the same power output. As the heliostat field is the largest cost contribution in a solar tower plant, the investment cost is reduced accordingly.

4.17.7.1

Future Power Cycles

For the power cycles, several options exist for the increase of efficiency using higher temperature processes. The most important ones are:

• • •

advanced steam cycles, gas turbine cycles, and supercritical CO2 cycles. A comprehensive discussion of various options for CSP systems can be found in Ref. [55].

4.17.7.1.1

Advanced steam power cycles

In current solar tower plants, steam cycles operate at temperatures up to 5401C (limited by the degradation of the used molten salt), with thermal efficiency of about 42%. In contrary, modern conventional steam power blocks operate at up to 6201C, achieving net thermal efficiencies of about 45%. It is therefore of interest to integrate modern steam cycle technology with higher operating temperatures, either subcritical or supercritical, into solar power plants. Such temperatures can be easily achieved by solar tower systems, but not with the nitrate molten salt mostly used as HTF. New heat transfer and storage media are required, as discussed in Section 4.17.7.2. Another important issue is that advanced power cycles have also higher specific investment cost, partially offsetting the advantage from the increased efficiency. Thus, careful optimization will be required to minimize LCoE.

4.17.7.1.2

Gas turbine cycles

State-of-the-art gas turbine systems with bottoming steam cycle, so-called combined cycle (CC) plants, achieve efficiencies in the 60% range. The use of gas turbine-based power cycles is therefore also an attractive option for solar tower plants. Several solarized

726

Solar Tower Systems

800°C Fuel

Solar air receiver

1200°C 350°C

G G

Heliostat field 650°C

Fig. 39 Solarized gas turbine cycle in combined cycle (CC) configuration. .

Receiver Storage Combustor

Receiver Storage Combustor

V R R

V R R

Recuperator

Recuperator

G

Solar field

Solar tower

Gas turbine

G

Solar field

Solar tower

Gas turbine

Fig. 40 Solar gas turbine cycle configurations: recuperated (left), with additional intercooling (right).

gas turbine concepts were developed, using the solar energy to preheat the compressed air before entering the turbine section. A detailed discussion of solarized gas turbine systems is given in Ref. [56]. Fig. 39 shows a solar-hybrid gas turbine system in CC configuration. In addition to the high conversion efficiency of gas turbine-based cycles, the cooling requirements are significantly reduced. CC configurations have only about 40% of the cooling demand of comparable steam cycles, and recuperated gas turbines do not need any external cooling. Several system configurations were investigated in detail, verifying the potential performance advantage. Besides the CC configuration, recuperated gas turbine systems (Fig. 40 left), optionally combined with intercooling (Fig. 40 right), were investigated. From the technoeconomic point of view, the intercooled configuration looks promising. However, this configuration is not common and would require further development toward commercial units. Several test and demonstration systems were built and operated. The largest demonstration was based on a Mercury-50 gas turbine from Solar Turbines, with about 4.5 MWe [55]. This system was built and operated near Seville, Spain, with a receiver reaching about 8001C. Solar testing demonstrated the simple operation and control of the solar-hybrid gas turbine system. Before market introduction of solar gas turbine systems, further development is required, both on the gas turbine and the high temperature receiver side. With solarized gas turbine units with bottoming steam cycle, the exhaust energy of the gas turbine can also be stored in a regenerator storage [54]. Thus power production from the steam turbine can be decoupled from the power production in the gas turbine, providing partial dispatchability while avoiding the high cost of a high temperature storage system in the gas turbine cycle.

4.17.7.1.3

Supercritical CO2 cycles

Recently, supercritical CO2 (sCO2) cycles attracted increasing interest. Due to the favorable thermophysical properties of supercritical CO2 thermal efficiencies exceeding 50% are predicted assuming 7001C turbine inlet temperature [56]. The corresponding upper pressure level is typically in the range of 250 bar. In addition, supercritical CO2 cycles have significantly smaller dimensions than comparable steam cycles. This is advantageous not only with respect to system cost, but also for transient characteristics. It is expected that such systems allow much faster ramp rates than steam cycles, which is important for future grids with high shares of

Solar Tower Systems

727

Tmc,in Pmc,in

Shaft speed Main comp

Turbine

Generator

Buffer volume

Tt,in

Recomp comp

Precooler

Low temperature recuperator

Primary heat exchanger

rc

Motor

Low temperature recuperator

Fig. 41 Recompression cycle with supercritical CO2. Reproduced from Ho CK, Carlson M, Garg P, Kumar P. 2016. Technoeconomic analysis of alternative solarized s-CO2 Brayton cycle configurations. ASME J Sol Energy Eng 2016;138(5). doi:10.1115/1.4033573.

intermittent renewables. Another potential attraction of sCO2 is that it could provide high efficiencies at smaller capacities where steam turbines would not be suitable. Several sCO2 cycle configurations have been proposed for CSP applications. The recompression cycle, shown in Fig. 41, is one of the promising configurations. For high efficiency configurations, a disadvantage is the relatively small temperature span at the heat introduction side, which implies also a small temperature span for the storage system. For sensible heat storage systems like molten salt, this results in increased specific storage cost. Higher upper temperatures offer higher efficiencies, but require more expensive materials in some sections of the cycle. Future development needs to evaluate the trade-off between performance and cost to identify optimal configurations. In the case of CSP systems with dry cooling, the lower temperature level of a sCO2 cycle will usually be above the critical temperature of CO2 (311C). This will negatively affect cycle performance. Therefore it is important to evaluate such cycles considering the real cooling conditions in the course of the complete year. A first commercial supercritical CO2 system of 8 MWe is available, operating at moderate temperature and achieving about 24% thermal efficiency [57]. Significant further effort is required to develop high efficiency cycles at higher power levels.

4.17.7.2

Future Heat Transfer Media and Receivers

The main goal for future receiver technologies is to increase the HTM temperature while maintaining high reliability and acceptable cost. In any case, the selection of the HTM is closely related to the receiver technology. Several technology options exist:

• • • •

molten salt mixtures for higher temperatures, solid particles, air or other gases, and liquid metals.

New molten salt mixtures, suitable for higher operating temperatures, are known. Among the most promising candidates are chloride and carbonate salt mixtures [55]. Important factors for the salt selection are the thermophysical properties (melting point, heat capacity, density, etc.), corrosion issues and material cost. The associated receiver design will be quite similar to the existing external tube receiver design, adapted to higher temperatures and different salt properties. Especially corrosion issues might be a critical aspect, requiring additional effort for purity control and/or use of expensive metal alloys in the high temperature sections. The use of liquid metals is another promising option to increase the operation temperature. Liquid sodium is the most promising candidate, due to its excellent thermophysical properties. The main advantage is that the allowable solar flux density on the receiver is significantly higher than for molten salt receivers. Therefore the receiver can be designed smaller, reducing thermal

728

Solar Tower Systems

Sodium HT molten salt

Receiver panel Heat exchanger

Sump tank

Hot Cold

EM-pump Heliostat field

Solar tower

Thermal storage

G

Power block

Fig. 42 Solar tower with sodium receiver loop and molten salt storage.

losses and cost. However, liquid sodium is considered a hazardous material as it is highly flammable and must be completely sealed from the environment. Appropriate safety measures need to be taken to deal with this danger. Also, the cost of sodium is too high to allow direct use in large quantities as thermal storage medium [58]. A mixed concept using a small sodium inventory in a closed receiver loop which transfers the solar heat via a heat exchanger to a suitable storage system (e.g., high temperature molten salt) offers a promising LCoE reduction potential. Fig. 42 shows a scheme of this concept. The small sodium inventory significantly reduces the risk, while maintaining all the benefits of the improved heat transfer characteristics in the receiver (e.g., smaller receiver). For storage, low-cost molten salt is used. When solar salt is used, this defines the temperature limit. As the heating of the salt can be done in a very controlled manner in the heat exchanger, excess salt temperatures can be significantly reduced (compared to heating the salt in the receiver). This might even allow raising the temperature level in the hot salt tank, enabling higher efficiency in an improved power cycle. After early work on solar tower systems using solid particles as heat transfer and storage medium, there is recently again increasing interest in this technology. Solid particles can overcome the temperature limitations of other HTM. As an example, many research groups use commercially available bauxite as particles. Such particles are inert and can be used up to temperatures of at least 10001C, also avoiding the problem of freezing at low temperatures. The particles are already produced in huge quantities for various processes, for example as “proppants” for fracking in the oil and gas exploration. They are relatively cheap and can therefore also be used directly as thermal storage material, promising a reduction of specific storage cost. Although corrosion is not considered an issue, attrition between particles and abrasion on structural materials are the challenges that need to be solved before commercial application. Several receiver concepts are currently under development [59]. Some concepts use small particles entrained or fluidized in air, in tubes or cavity-like arrangements. Other receiver concepts rely on the so-called “direct absorption” principle: the dark solid particles are directly exposed to the concentrated solar radiation and get heated while absorbing the solar radiation. Concepts with freely falling particles and others with particles moving in rotating cavities use this principle, thus reducing the need for expensive high temperature materials. Direct absorption particle receivers are expected to achieve high efficiencies even at high temperatures, at low cost for the receiver itself. However, particle transportation and heat exchanger technology are further issues to be developed and demonstrated (Fig. 43). A significant advantage of particle systems is their wide range of operation temperature. This allows system optimization with many degrees of freedom (process temperature, storage temperature span, storage and heat exchanger sizing, etc.). As an example, increasing the receiver exit temperature (while maintaining the low temperature level) will reduce storage size and heat exchanger area accordingly. While the reduction in receiver efficiency can be limited, this might result in a significant investment cost reduction. More details on all aspects of particle systems are discussed in Ref. [55]. Gas receivers are also considered an option for future solar tower systems with increased temperatures [55]. Air or inert gases (e.g., He, CO2, etc.) can be used. Typical for gas receivers is the poor heat transfer compared to other HTFs. By operating the receivers at higher pressures, heat transfer characteristics can be improved and pumping losses are reduced, at the expense of increased cost for the receiver materials (e.g., tubes). Advanced concepts for open volumetric receivers include cavity-like systems, enabling higher air return ratios. Also, advanced absorber structures with better thermal performance are under development.

4.17.7.3

Storage Technology

For molten salt storage, developments are under way to replace the current two-tank configuration with a single tank system, using a thermocline approach with cheap filler materials [60]. A significant cost reduction is predicted for this approach. Suitable

Solar Tower Systems

729

Particle inlet Feeding cone g

Particle outlet Cavity

Concentrated sunlight Fig. 43 Falling particle receiver (left), centrifugal receiver (right) [59].

low-cost filler materials must be identified and validated for durability. Other concepts intend to use a single tank with a floating barrier between the hot and the cold salt tank [60]. Thermochemical storage uses the reaction enthalpy of chemical reactions, in addition to the sensible heat. This storage concept offers higher volumetric energy density and potentially reduced thermal losses. Possible reaction systems include redox reactions, sulfur-based cycles, and metal oxide reduction–oxidation cycles [61]. However, all thermochemical storage concepts are in early stages of development. A new approach is the use of temporarily free storage capacity for the storage of excess power in the grid, for example, from wind turbines during stormy periods. Under certain conditions, the storage of a CSP cannot be fully charged, for example, in longer cloudy periods, during winter season or when the solar system is designed for a limited storage capacity. Then, the available storage infrastructure can be used basically for free to store excess electricity from other sources. The obvious way is to use electricity directly in a heater to heat the molten salt in the CSP storage, resulting in a round trip efficiency (electricity to electricity) of about 40%. Higher storage efficiencies can be achieved when the excess electricity powers a high temperature heat pump, for example, based on a supercritical CO2 cycle [62]. Then round trip efficiencies well above 50% can be achieved. This approach allows cost-effective storage of excess electricity.

4.17.7.4

Other Improvement Options

Further cost reductions of solar tower systems are expected from ongoing development and improvement of the technology. R&D work is going on to increase the solar absorptivity of the receiver while reducing the thermal emissivity, through innovative selective absorber coatings. New algorithms and strategies are proposed to improve the field layout, i.e., the positioning of the heliostats in the field. So-called multitower systems are investigated, with the solar subsystem divided into several identical smaller solar tower units, feeding a common central power block. Such multitower systems benefit from the higher optical efficiency of smaller heliostat fields, but require additional expenses for the interconnection of the subsystems. Nevertheless, studies predict cost reductions for multitower configurations. Advanced control and operation strategies are expected to increase the energy yield of solar tower plants, for example, by sophisticated heliostat aim point strategies that increase steady-state efficiency, minimize start-up and cloud passage losses and prolong receiver lifetime by reducing thermal gradients. In parallel, further down the learning curve, investment cost reductions are expected from improved and standardized manufacturing. Introduction of new technologies for some components will also lower cost. With increasing operational experience and enhanced component durability, reductions in operation and maintenance cost will also contribute to lower LCoE.

4.17.7.5 4.17.7.5.1

Further Application Options Hybrid plants

Combining solar tower systems with PV power plants is another way to reduce cost of solar electricity. During sunshine hours, solar power production is from PV and the solar tower system, while in parallel the thermal storage is charged. When solar radiation cannot longer cover the full demand, the plant is operated partially or fully from storage.

4.17.7.5.2

Process heat applications

As solar tower systems can effectively achieve high operating temperatures, they can provide economically solar process heat for a variety of industrial processes. For process heat applications, the power block is omitted and the thermal power can be provided without conversion loss in the power cycle. Therefore the predicted cost of thermal energy looks very attractive.

730

Solar Tower Systems

For applications with temperatures above 6001C, two receiver technologies are in the focus: air receivers and particle receivers. Air receivers might be a good solution for processes where combustion can be replaced or supported directly. Particle receiver systems provide a larger temperature range (up to at least 10001C) and inherent cheap storage capability. Transportation of insulated containers filled with hot particles is an additional option that will enable retrofitting of existing industrial plants when there is no free space for a solar system directly adjacent to the plant. First estimates indicate that transportation over a few kilometer distance does not significantly increase the cost of heat. Several special receiver technologies, for example, rotary kiln receivers for aluminum smelting or for lime calcination, are under development for high temperature processes. However, all these approaches are in an early stage of development and need to demonstrate their technical and economic viability. Due to the huge variety of industrial processes, increased engineering cost is expected for the adaptation to the specific process, including suitable equipment for solar heat integration into the industrial process. Development of standardized modular solar thermal units might reduce this additional cost, the adaptation to the given heat demand is then done by installing the appropriate number of identical modules. Production of solar fuels via solar thermochemical processes is another promising application of solar tower technology. Several processes exist that can use solar energy at high temperatures for exothermal reaction steps, delivering, for example, H2 [63].

4.17.8

Closing Remarks

Solar tower systems are a renewable power source offering the important feature of cost-effective storage for daily load cycles. Such systems enable load shifting, i.e., collection of solar energy and production of electricity can be fully decoupled. With all the characteristics of a conventional thermal power plant, additional services for grid stability are provided, for example, spinning reserve. Including an additional burner system makes the solar tower plant fully dispatchable, thus avoiding backup capacity in the grid. However, solar tower systems are a relatively new technology at commercial scale, and are at the beginning of the learning curve. Therefore cost of such systems is currently relatively high. With further technological development and deployment of additional plants, costs are expected to come down and performance to be improved. Provided that this future cost reduction can be achieved, solar tower systems can be an important part of renewable energy system in sunny countries. Currently, the flexible and controlled power production through the integration of thermal storage is the unique selling point of solar thermal power systems. Because of the large temperature span of solar tower systems, the storage can be provided at relatively low cost. Battery storage might provide the same flexibility in power supply to the grid. With actual cost figures solar thermal plants can offer this service at lower cost. However, with strongly decreasing prices for battery systems, large scale application of such systems might become competitive in the future. With the available cost reduction scenarios for battery systems, this is expected after the year 2030 [30]. Another important aspect is the local content in the erection of such a plant. A solar tower plant can have a large contribution from local manufacturing, like steel work, glass production, concrete components, etc. For this reason, solar tower plants can bring significant economic benefit to the country where the plant is installed. This has become a major driver for the technology selection, in comparison with other renewable energy systems like PV or wind.

Acknowledgment The authors would like to thank Stefano Giuliano for his valuable contributions to this chapter.

References [1] [2] [3] [4] [5] [6] [7] [8] [9]

Wikipedia, Available from: https://en.wikipedia.org/wiki/Paris_Agreement. IRENA, The power to change: solar and wind cost reduction potential to 2025; 2016. HELIOSCSP, Available from: http://helioscsp.com/china-1st-phase-20-concentrated-solar-power-pilot-projects/; 2017 [accessed 04.06.17]. HELIOSCSP, Available from: http://helioscsp.com/solarreserve-bids-24-hour-concentrated-solar-power-at-6-3-cents-in-chile/; 2017 [accessed 20.07.17]. Amsbeck L, Buck R, Pfahl A, Uhlig R. Optical performance and weight estimation of a heliostat with ganged facets. ASME J Sol Energy Eng 2008;130(1):011010. Schell S. Design and evaluation of esolar’s heliostat fields. In: Proceedings of SolarPACES 2010 Conference, Perpignan, France, September 21–24, 2010; 2010. Pfahl A. Survey of heliostat concepts for cost reduction. J Sol Energy Eng 2014;136:010301. Kolb GJ, Jones SA, Donnelly MW, et al., Heliostat cost reduction study report No. SAND2007-3293G, Sandia National Laboratories, Albuquerque, NM; 2007. Neumann A, Witzke A, Jones SA, Schmitt G. Representative terrestrial solar brightness profiles. In: ASME Solar 2002: international solar energy conference. American Society of Mechanical Engineers; 2002. p. 325–33. [10] Kribus A, Vishnevetsky I, Meri M, Yogev A, Sytnik A. Continuous tracking of heliostats. In: ASME 2003 international solar energy conference. American Society of Mechanical Engineers; 2003. p. 553–62. [11] Berenguel M, Rubio FR, Valverde A, et al. An artificial vision-based control system for automatic heliostat positioning offset correction in a central receiver solar power plant. Sol Energy 2004;76:563–75. [12] Pitman CL, Vant-Hull LL. Atmospheric transmission model for a solar beam propagating between a heliostat and a receiver. In: Proceedings of annual meeting – American section international solar energy society. CONF-820629-Vol. 5-Pt. 2, United States; 1982.

Solar Tower Systems

[13] [14] [15] [16] [17] [18] [19] [20] [21] [22] [23] [24] [25] [26] [27] [28] [29] [30] [31] [32] [33] [34] [35] [36] [37] [38] [39] [40] [41] [42] [43] [44] [45] [46] [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63]

731

Segal A, Epstein M. Solar ground reformer. Sol Energy 2003;75(6):479–90. Yogev A, Fisher U, Erez A, Blackmon J. High temperature solar energy conversion systems. ISES. In: Solar world congress 1999; 1999. Vant-Hull L. Issues with Beam-down concepts. Energy Procedia 2014;49:257–64. Mokhtar M, Meyers SA, Armstrong PR, Chiesa M. Performance of a 100 kWth concentrated solar beam-down optical experiment. ASME J Sol Energy Eng 2014;136(4): CSP, Available from: http://www.xinchen-csp.com/en/; 2017 [accessed 12.8.17]. Tempil, Available from: http://www.tempil.com/specialty-coatings/pyromark-high-temperature-paint/; 2017 [accessed 12.06.17]. Ho CK, Mahoney AR, Ambrosini A, et al., Characterization of Pyromark 2500 paint for high-temperature solar receivers. J Sol Energy Eng 2013;136(1): 014502. SolarReserve, Available from: http://www.solarreserve.com/en/global-projects/csp/crescent-dunes; 2016 [accessed 20.09.16]. Koll G, Schwarzbözl P, Hennecke K, et al., The solar tower Jülich – a research and demonstration plant for central receiver systems. In: Proceedings of solarPACES conference, September 15–18, 2009, Berlin, Germany; 2009. Ahlbrink N, Andersson J, Diehl M, Pitz-Paal R. Optimization of the mass flow rate distribution of an open volumetric air receiver. J Sol Energy Eng 2013;135(4): 041003. Relloso S, Lata J. Molten salt thermal storage: a proven solution to increase plant dispatchability. Experience in Gemasolar tower plant. In: Proceedings of solarPACES conference; 2011. Steinmann W-D, Eck M. Buffer storage for direct steam generation. Sol Energy 2006;80:1277–82. Fricker H. Regenerative thermal storage in atmospheric air system solar power plants. Energy 2004;29(2004):871–81. IRENA, Renewable energy technologies: cost analysis series, Volume 1: power sector issue 2/5, concentrating solar power. In: Working paper, International Renewable Energy Agency (IRENA); 2012. IEA, Technology roadmap solar thermal electricity – 2014 edition; 2014. Weinrebe G, von Reeken F, Wöhrbach M, et al., Towards holistic power tower system optimization. In: Proceedings of solarPACES 2013 conference, Las Vegas; 2013. Kolb GJ, Ho CK, Mancini TR, Gary JA. Power tower technology roadmap and cost reduction plan – SAND2011-2419, Sandia National Laboratories; 2011. Breyer C, Afanasyeva S, Brakemeier D, et al., Assessment of mid-term growth assumptions and learning rates for comparative studies of CSP and hybrid PV-battery power plants. In: Proceedings of 22nd solarPACES conference, October 11–14, 2016, Abu Dhabi, United Arab Emirates; 2016. IEA-NEA, Projected costs of generating electricity – 2010 Edition; 2010. Lilliestam J, Labordena M, Patt A, Pfenninger S. Empirically observed learning rates for concentrating solar power and their responses to regime change. Nat Energy 2017;2(2017):17094. Jorgenson J, Denholm P, Mehos M. Estimating the value of utility-scale solar technologies in California under a 40% renewable portfolio standard technical report NREL/ TP-6A20-61685; 2014. Denholm P, Mehos M. Enabling greater penetration of solar power via the use of CSP with thermal energy storage NREL technical report, NREL/TP-6A20-52978; 2011. Belhomme B, Pitz-Paal R, Schwarzbözl P, Ulmer S. A new fast ray tracing tool for high-precision simulation of heliostat fields. J Sol Energy Eng 2009; Izygon M, Armstrong P, Nilsson C, Vu N. TieSOL–a GPU-based suite of software for central receiver solar power plants. In: Proceedings of solarPACES 2011 conference, Granada, Spain; 2011. Lipps FW, Vant-Hull LL. A cellwise method for the optimization of large central receiver systems. Sol Energy 1978;20. Schwarzbözl P, Pitz-Paal R, Schmitz M. Visual HFLCAL – a software tool for layout and optimisation of heliostat fields. In: SolarPACES 2009 Conference, Berlin; 2009. Collado FJ, Guallar J. Campo: generation of regular heliostat fields. Renew Energy 2012;46:49–59. Sanchez M, Romero M. Methodology for generation of heliostat field layout in central receiver systems based on yearly normalized energy surfaces. Sol Energy 2006;80 (7):861–74. Wei X, Lu Z, Wang Z, et al. A new method for the design of the heliostat field layout for solar tower power plant. Renew Energy 2010;35(9):1970–5. Reinholz A, Husenbeth C, Schwarzbözl P, Buck R. Optimizing heliostat positions with local search metaheuristics using a ray tracing optical model. In: SolarPACES 2016 conference, Abu Dhabi; 2016. Blair N, Dobos A, Freeman J, et al., System advisor model, SAM 2014.1. 14: general description NREL report No. TP-6A20-61019. Golden, CO: National Renewable Energy Laboratory; 2014. Dersch J, Schwarzbözl P, Richert T. Annual yield analysis of solar tower power plants with greenius. J Sol Energy Eng 2011;133. Pawellek R, Löw T, Hirsch T, Giuliano S, Schwarzbözl P. Solar tower simulation with EbsilonProfessional. In: Proceedings of the solarPACES 2011 conference; 2011. Singer C, Giuliano S, Buck R. Assessment of improved molten salt solar tower plants. Energy Procedia 2014;49:1553–62 (Pitchumani R, editor, Proceedings of the solarPACES 2013 international conference). Camacho EF, Berenguel M. Control of solar energy systems. IFAC Proc 2012;45(15):848–55. Belhomme B, Pitz-Paal R, Schwarzbözl P. Optimization of heliostat aim point selection for central receiver systems based on the ant colony optimization metaheuristic. J Sol Energy Eng 2014;136. Vant-Hull LL. The role of “Allowable Flux Density” in the design and operation of molten-salt solar central receivers. J Sol Energy Eng, Trans ASME 2002;124(2):165–9. Available from: https://www.4echile.cl/4echile/wp-content/uploads/2017/03/Sistemas-de-Torre-Solar.pdf; 2017 [accessed 16.06.17]. CSP Today global tracker. Available from: http://social.csptoday.com/tracker/projects; 2017 [accessed 12.02.17]. CSP Project Fact Sheet 09/2013 by SolarReserve. Bright Source, Available from: http://www.brightsourceenergy.com/image-gallery; 2017 [accessed 19.02.17]. Heller L, Hoffmann J. A cost and performance evaluation of SUNDISC: a dual-pressure air receiver cycle. Energy Procedia 2015;69:1287–95. Mehos M, Turchi C, Vidal J, et al., Concentrating solar power Gen3 demonstration roadmap. Technical report NREL/TP-5500-67464; 2017. Blanco M, Santigosa LR, editors, Advances in concentrating solar thermal research and technology. Woodhead Publishing Series in Energy, ISBN: 978-0-08-100516-3; 2017. Echogen, Available from: http://www.echogen.com/our-solution/product-series/eps100/; 2017 [accessed 16.02.17]. Boerema N, Morrison G, Taylor R, Rosengarten G. Liquid sodium versus Hitec as a heat transfer fluid in solar thermal central receiver systems. Sol Energy 2012;86:2293–305. Ho CK. A review of high-temperature particle receivers for concentrating solar power. Appl Therm Eng 2016 Available from: http://dx.doi.org/10.1016/j. applthermaleng.2016.04.103. Breidenbach N, Martin C, Jockenhöfer H, Bauer T. Thermal energy storage in molten salts: overview of novel concepts and the DLR test facility TESIS. Energy Procedia 2016;99:120–9. Prieto C, Cooper P, Fernández AI, Cabeza LF. Review of technology: thermochemical energy storage for concentrated solar power plants. Renew Sustain Energy Rev 2016;60:909–29. Aga V, Conte E, Carroni R, Burcker B, Ramond M. Supercritical CO2-based heat pump cycle for electrical energy storage for utility scale dispatchable renewable energy power plants. In: 5th international symposium – supercritical CO2 power cycles, March 28–31, 2016, San Antonio, Texas; 2016. Smestad GP, Steinfeld A. Review: photochemical and thermochemical production of solar fuels from H2O and CO2 using metal oxide catalysts. Ind Eng Chem Res 2012;2012(51):11828–40.

732

Solar Tower Systems

Further Reading Blanco M, Santigosa LR, editors, Advances in concentrating solar thermal research and technology. Woodhead Publishing Series in Energy, ISBN: 978-0-08-100516-3; 2017. IEA, Technology roadmap solar thermal electricity – 2014 edition. Aavailable from: https://www.iea.org/publications/freepublications/publication/ TechnologyRoadmapSolarThermalElectricity_2014edition.pdf; 2014. Korzynietz R, Brioso JA, del Río A, et al. Solugas – comprehensive analysis of the solar hybrid Brayton plant. Solar Energy 2016;135:578–89 ISSN 0038-092X, Available from: http://dx.doi.org/10.1016/j.solener.2016.06.020. Pacheco JE. Final test and evaluation results from the solar two project. SAND2002-0120; 2002. Stein WH, Buck R. Advanced power cycles for concentrated solar power. Sol Energy 2017;152:91–105 ISSN 0038-092X, Available from: http://dx.doi.org/10.1016/j. solener.2017.04.054. Zunft S, Hänel M, Krüger M, et al. Jülich solar power tower – experimental evaluation of the storage subsystem and performance calculation. J Sol Energy Eng 2011;133(3):031019.

Relevant Websites http://tracker.newenergyupdate.com/tracker/projects CSP project tracker. http://helioscsp.com/ HeliSCSP. https://www.nrel.gov/csp/ NREL. http://www.solarpaces.org/ SolarPACES.

4.18 Solar Fuels Christos Agrafiotis, Martin Roeb, and Christian Sattler, German Aerospace Center – DLR (Deutsches Zentrum für Luft- und Raumfahrt), Köln, Germany r 2018 Elsevier Inc. All rights reserved.

4.18.1 Introduction 4.18.2 Background/Fundamentals 4.18.3 Systems and Applications 4.18.3.1 Redox Water/Carbon Dioxide Splitting Thermochemical Cycles Chemistry 4.18.3.2 Coupling Redox Chemistry to Solar Energy: Solar Receiver–Reactors 4.18.4 Analysis and Assessment 4.18.5 Case Studies 4.18.5.1 Volatile Thermochemical Cycles: The ZnO/Zn and the SnO2/SnO Cycle 4.18.5.1.1 Current status of technology 4.18.5.2 Nonvolatile Cycles: The Ferrites, Ceria and Perovskites Cycles 4.18.5.2.1 Nonstructured (particle) receiver–reactors 4.18.5.2.1.1 The spouted bed reactor 4.18.5.2.1.1.1 Current status of technology 4.18.5.2.1.2 The moving packed bed reactor 4.18.5.2.1.2.1 Current status of technology 4.18.5.2.2 Structured reactors with moving parts: Rotary-type reactors 4.18.5.2.2.1 Current status of technology 4.18.5.2.3 Structured reactors with nonmoving parts 4.18.5.2.3.1 Current status of technology 4.18.6 Results and Discussion 4.18.7 Future Directions 4.18.8 Closing Remarks Acknowledgments References Further Reading Relevant Websites

4.18.1

733 735 736 736 738 739 740 741 743 743 744 744 744 744 747 748 748 748 751 755 755 757 757 757 761 761

Introduction

A general definition of a fuel is any chemical compound that stores energy, which can be released by being oxidized to provide heat [1]. In addition to fuels employed in classical uses of such heat, like engines, electricity generation, and thermally driven processes, the term nowadays is broadened to include fuels reacting with oxygen in a fuel cell to directly produce electricity. Petroleum-based liquid hydrocarbons have established themselves as our primary fuel source due to their high power density, ease of transportation and storage, development of internal combustion engine technologies and use of existing infrastructure (fuel distribution and vehicles); despite the advancement of electrified transport that will likely reduce liquid fuel demand they will continue to be needed [2]. However, a different viewpoint must be adopted to mitigate the environmental, political, and other consequences of today’s fossil hydrocarbon-based economy. Their widespread use calls for means to produce them sustainably. Nonfossil, synthetic liquid fuels (SLFs) are alternatively pursued. The term “synthetic fuel (synfuel)” refers to a liquid fuel produced at commercial scale from low energy content carbonaceous sources, such as coal, natural gas, or biomass, that are upgraded at the expense of additional energy, also obtained from the combustion of fossil fuels [3]. Hydrogen and syngas (a gas mixture of varying amounts of CO and H2) are the basic raw materials to produce SLFs at commercial scale from such carbonaceous sources via industrial processes, for example, via the Fischer–Tropsch (FT) technology [4]. Water electrolysis to hydrogen and oxygen has been used industrially to produce hydrogen for more than a century. Once the favoured method for hydrogen production, it was subsequently largely displaced by lower-cost methods, such as steam reforming of natural gas, and today only 4% of hydrogen (65 million tons) is produced this way [5]. The largest electrolysis plants (over 30,000 Nm3/h) have historically been deployed for the fertilizer industry [6]. Commercial hydrogen is produced today from fossil sources. The majority (48%) comes from reforming natural gas and refinery gas, as a by-product from chemicals production (30%) and from coal gasification (18%). In the “reforming processes,” steam and/or CO2 are reacted with natural gas (methane) to produce syngas (CO and H2) according to the reaction

Comprehensive Energy Systems, Volume 4

doi:10.1016/B978-0-12-809597-3.00429-6

733

Solar Fuels

Carbonaceous feedstocks

Gaseous feedstocks

Natural gas (CH4)

Solid feedstocks

Concentrated solar energy

Biogas (CH4, CO2)

(H2O, CO2)

Reforming (steam, CO2)

Biomass CxHyOz

Pet coke (C)

Splitting

Gasification

H2 + CO Solar syngas from carbonaceous feedstocks Solar (liquid) fuels from carbonaceous feedstocks

Concentrated solar power

O O

MOox O O

MOred

Thermochemical cycle

Tox

MOox+H2/CO←MOred+H2O/CO2

H

Fuel (syngas) C O

Tred

MOox→MOred+O2

Temperature

(A)

Storing solar energy

734

O

H

O C O

HH

(B)

Central receiver/reactor tower with heliostats

Modular dish-mounted receiver/reactor

Solar receiver STCH reactor

Dish mirrors

Tower

(C)

Heliostat field

Heliostat field

Solar Fuels

735

schemes (1) and (2) below, steam methane reforming (SMR) and CO2 (or dry) methane reforming (DMR), respectively: CH4 þ H2 O ⇆ 3H2 þ CO

DH0298K ¼ þ 206 kJ=mol

ð1Þ

CH4 þ CO2 ⇆ 2H2 þ 2CO

DH0298K ¼ þ 247 kJ=mol

ð2Þ

Both reactions are highly endothermic, therefore favoured by high temperatures and carried out between 800 and 10001C. The required energy is supplied by combustion of additional natural gas as fuel and process waste gas from the downstream hydrogen purification step (3–20% of total natural gas consumption of the plant) [7]. “Gasification” involves the reaction of steam with solid carbonaceous feedstocks such as coal, coke, biomass, or carboncontaining wastes to produce syngas. The overall net reaction for stoichiometric water delivery can be written as C1 Hx Oy Su Nv þ ð1

yÞH2 O-ðx=2 þ 12y2uÞH2 þ CO þ u H2 S þ v=2 N2

ð3Þ

where x, y, u, and v are the elemental molar ratios of H/C, O/C, S/C, and N/C, respectively, in the feedstock. Just like reformers, conventional gasifiers use a portion of their product or input stream to drive their reaction, which harms overall efficiency. Renewable energy sources (RES) can reduce the dependency on fossil fuels that cause pollutant gas emission and climate change. Among them solar energy is unmatched in magnitude and availability as well as scalable to any future energy demand [8]. All routes above, electrolysis and reforming/gasification, can be rendered environmentally friendlier when combined with a RES, such as solar energy [5]. Interest in water electrolysis has increased again recently, influenced by its potential to provide hydrogen with a very low associated carbon footprint using renewable electricity as well as for electrolyzers to provide services, such as load response management, to changing electricity grids. Concentrated solar power (CSP) systems – special mirror assemblies (parabolic troughs, heliostats, or parabolic dishes) that track the sun and concentrate its radiation – convert solar energy to medium- to high-temperature heat and through that to electricity or chemical bonds (chemical substances). The operation principle and types of CSP systems can be found in many comprehensive reviews [9,10]. CSP systems can be employed in both approaches above: with their main function as electricity providers can supply (alternatively to photovoltaics/PV) the renewable electricity for electrolysis of steam. Alternatively, they can supply high-temperature process heat as the necessary energy source for the performance of endothermic chemical reactions (similar, but not limited to the reforming/gasification ones) in the so-called “solar thermochemical” processes. In this way the solar thermal energy obtained is not converted into electrical power but to chemical bonds to create chemical substances that can be used downstream in the chemical industry or stored/transported and used for off-sun electricity production [11,12]. A “solar fuel” is thus any chemical compound that can react with oxygen to release energy, and that was initially formed, at least partly, using energy from solar radiation. In the broad sense this term can contain, in addition to “solar hydrogen,” syngas, hydrocarbons and alcohols produced from reactions between H2 and CO as well as solid powders that have originated from solar-aided dissociation processes.

4.18.2

Background/Fundamentals

The “thermochemical route” uses solar heat at high temperatures supplied by CSP systems for performing various high-temperature reactions that produce hydrogen or syngas from transformation of various fossil and nonfossil fuels (Fig. 1(A)). The term “concentrated solar fuels” (CSFs) has been coined recently [13] to denote such fuels produced with CSP, distinguishing them from fuels produced with the aid of low-temperature solar photon energy via, for example, photochemical and photobiological processes [14]. Producing the end-use fuels is usually a two-stage process. The initial solar-driven endothermic reaction produces gases, either syngas or pure hydrogen, with oxygen as a side-product. This is followed by the synthesis of the desired end product fuel – for example, methanol [15], dimethyl ether (DME) and Fischer–Tropsch diesel [16] – with processes largely built on industrial existing technology, which could be located separately from the solar facility. Such chemical reactions include the abovementioned natural gas steam reforming [17] and the gasification of solid carbonaceous materials like coal or biomass according to the above reaction schemes [18], as well as water splitting (WS) to hydrogen and oxygen. The WS reaction can then be followed either by reaction of H2 with CO2 via the reverse water–gas shift (RWGS) reaction or by reaction of H2 with CO coming from carbon dioxide splitting (CDS) to CO and O2, to produce syngas [19,20]. The so-called WS thermochemical cycles (TCs) were proposed initially for the production of hydrogen from the dissociation of water to hydrogen and oxygen. These are a series of consecutive chemical reactions (Z2), their “net” sum being the splitting of H2O to H2 and O2, with the maximum-temperature (endothermic) step taking place at a temperature level lower than that required for the single-step thermal dissociation of water (thermolysis) at E28001C. Nevertheless, this endothermic step needs the input of external energy Fig. 1 (A) Different routes for transformation of various fossil and nonfossil fuels to syngas via high-temperature reactions using solar radiation as the energy source (reprinted from Agrafiotis C, von Storch H, Roeb M, Sattler C. Solar thermal reforming of methane feedstocks for hydrogen and syngas production – a review. Renew Sust Energy Rev 2014;29:656–82 with permission from Elsevier); (B) general schematic of the solaraided, two-step, redox-oxide-pair-based, water and/or carbon dioxide splitting (CDS) thermochemical cycle for syngas production (reprinted from Agrafiotis C, Roeb M, Sattler C. A review on solar thermal syngas production via redox-pair-based water/carbon dioxide splitting thermochemical cycles. Renew Sustain Energy Rev 2015;42:254–85 with permission from Elsevier); (C) solar-tower and solar dish mount receiver–reactor configurations (from U.S.D. Partnership. Hydrogen production technical team roadmap. Available from: https://energy.gov/eere/vehicles/downloads/ us-drive-hydrogen-production-technical-team-roadmap; 2013, DOE, United States). STCH: Solar ThermoChemical Hydrogen.

736

Solar Fuels

which can be provided by a source of high-temperature process heat like CSP. Of particular interest are two-step TCs based on oxide redox pair systems, which operate on the principle of transition between the oxidized (higher-valence, MeOoxidized) and reduced (lower-valence, MeOreduced) form of an oxide of a metal exhibiting multiple oxidation states [21,22]. One of their advantages versus other TC systems is that they are directly adaptable to CDS and/or combined CO2/H2O splitting for the production of CO or syngas, respectively, according to the reaction schemes (4)–(5) [23]; therefore can culminate in principle essentially to the synthesis of liquid hydrocarbon fuels from solar energy, water, and (waste) carbon dioxide. These routes are known as solar redox processes. During the first, higher-temperature, endothermic thermal reduction (TR) step, the higher-valence oxide under the supply of external heat releases a quantity of oxygen and transforms to a lower-valence state (reaction (4)). The second, lower-temperature step involves (exothermic) oxidation of the reduced form back to its oxidized state via an oxygen source (oxidant), establishing thus a cyclic process. 1 MeOoxidized þ ðDH1 Þ-MeOreduced þ O2 ðgÞ 2

ð4Þ

MeOreduced þ H2 O=CO2 ðgÞ-MeOoxidized þ H2 =COðgÞ þ ðDHÞ

ð5Þ

The fact that the H2 and the CO produced via reaction (5) can then be combined leading to syngas, has led various researchers to propose the above described “solar syngas” production scheme in solar reactors [23]. The approach is conceptually simple since the TR step (reaction (4)) is common for both WS and CDS. Therefore a particular redox material and a respective thermochemical reactor can be used for both WS and CDS separately from each other, or simultaneously to produce syngas in one step. This generic scheme is depicted in Fig. 1(B) [24,25]. WS TCs produce hydrogen and oxygen in different steps and therefore bypass the H2/O2 separation problem to avoid explosive mixtures, allowing at the same time operation at moderately high temperatures. The same principle can be applied to electrolysis: rather than electrolyzing steam for H2 production, steam/CO2 mixtures can be electrolyzed for syngas production [2,26]. Among the thermochemical routes to solar syngas shown in Fig. 1(A), solar reforming requires lower temperatures compared to WS/CDS but the latter employs CO2 as a reactant and in this perspective has the potential of reusing and “valorizing” atmospheric CO2 as a carbon-containing raw material for the production of fuels and chemicals [26]. CSP-aided coal/biomass steam gasification (dotted line) has been covered in a series of publications [27,28]. Two review articles on CSP-aided reforming and on CSPaided syngas production via WS/CDS thermochemical processes have been recently (2014, 2015) published by the present authors [29,30]. Since then further review articles were published, focused either only on WS [31], or on WS/CDS systems and reactors set forth by specific research groups [32] or available worldwide [33], comparing theoretical efficiencies of the various routes [34] or targeted to market peculiarities of specific countries like Australia [13]. Thus, the emphasis herein is on updating the work performed during the last 3 years, with important older references suggested at the end as Further Reading.

4.18.3 4.18.3.1

Systems and Applications Redox Water/Carbon Dioxide Splitting Thermochemical Cycles Chemistry

Obviously, the oxygen yield during the first step (4) depends on the extent of reduction: the oxidized form of the redox material with the metal cation at a high valence can be reduced either to a lower-metal-valence oxide or all the way to the respective metal. Highest possible dissociations are in principle sought, since subsequent full replenishment of the oxygen released during dissociation by oxygen taken from H2O/CO2 during oxidation, results in higher H2/CO product yields per mass of redox material. Hence, both metal oxide/metal systems (e.g., ZnO/Zn) and metal oxide/metal oxide pairs (e.g., Fe3O4/FeO, Mn3O4/MnO, CeO2/ Ce2O3) have been considered for hydrogen/syngas generation via such cycles. “Stoichiometric chemistries” assume that all the cations of the multivalent metal are transformed from the higher to the lower oxidation state during reduction and vice versa during oxidation. Since these two states are of different crystal structure, these reactions are also known as “phase change” reactions. Typical such reactions for representative single metal pairs are listed below. The temperature required for the high-temperature reduction step to occur spontaneously, defines the state of the product containing the metallic cation – solid, liquid, or gas: 1 2CeO2 ðsÞ-Ce2 O3 ðsÞ þ O2 ðgÞ 2

ð6Þ

Ce2 O3 ðsÞ þ H2 O=CO2 ðgÞ-2CeO2 ðsÞ þ H2 =COðgÞ

ð7Þ

1 Fe3 O4 ðsÞ-3FeOðlÞ þ O2 ðgÞ 2

ð8Þ

3FeOðsÞ þ H2 O=CO2 ðgÞ-Fe3 O4 ðsÞ þ H2 =COðgÞ

ð9Þ

1 2ZnOðsÞ-ZnðgÞ þ O2 ðgÞ 2

ð10Þ

ZnðsÞ þ H2 O=CO2 ðgÞ-ZnOðsÞ þ H2 =COðgÞ

ð11Þ

Solar Fuels

737

The concept of using oxide pairs of multivalent metals for solar-aided thermochemical production of hydrogen via WS was coined in 1977 [35] where cycling between Fe3O4/FeO (magnetite/wüstite) under the pair of reactions (8) and (9) was proposed [36]. However, as pointed out eloquently in Ref. [37], “…While the WS chemistry outlined above is deceptively simple, implementation remains a challenging endeavor…”

The first problem lies in identifying redox pairs suitable for both steps of the cycle: thermodynamic calculations have shown that oxide systems that could be easily thermally reduced stoichiometrically under air atmosphere at moderate temperatures (e.g., Co3O4/CoO) could not split water or carbon dioxide and for systems exhibiting high hydrogen yields during hydrolysis (e.g., Fe3O4/FeO, Nb2O5/NbO2) the temperatures required for TR were above their melting points [38]. Excluding thus the first group of oxides, research efforts were focused on lowering the TR temperatures of the oxides of the second group by either modifying their composition and/or by reducing the oxygen’s partial pressure [39]. Thermodynamic calculations have shown that performing this step under air atmosphere requires prohibitively high temperatures and have quantified the magnitude of oxygen partial pressure effects on the TR step equilibrium. In practice, most experimental set-ups and reactors use an inert gas to sweep the oxygen out of the reaction chamber and keep the atmosphere under a low oxygen partial pressure. In this case though, recycling inert gas imposes additional energy penalties to the overall process. An alternative option is to reduce the metal oxide under vacuum total pressures. With respect to composition modifications, the first obvious choice was the partial substitution of iron cations in the magnetite’s lattice by a transition (e.g., Mn, Co, Ni, or Zn) metal, to obtain mixed metal iron oxides (Fe1 xMx)3O4, the well known in the electronic industry, ferrites. Experimental campaigns have proved that, indeed several ferrites could be reduced at lower temperatures than pure magnetite with their reduced mixed wüstite phase (Fe1 xMx)O, still capable of splitting water [40]. Ferrites belong to the family of spinel materials which, together with perovskites, are two of the most known families of oxides containing multiple metal cations that can exhibit various valence states. Spinels and perovskites are of the general formulae A þ 2B2þ 3O4 and A þ 2B þ 4O3, respectively; however, more than one cation of the same valence can occupy the A or B sites, for example, (Ax,B1 x) þ 2(Cy,D2 y) þ 3O4 and (Ax,B1 x) þ 2(Cy,D2 y)2 þ 4O3 are respective typical formulae with two metal cations at each site. In addition, both single- and multi-metal multivalent oxides such as CeO2, spinels and perovskites form a wide range of stable, non-stoichiometric compounds, denoted as CeO2 δ, AB2O4 δ, and ABO3 δ, respectively. All such “non-stoichiometric” families can operate in a reaction pair scheme similar to (1)–(2) or (3)–(4) above. In reality, they represent much more complex situations like non-stoichiometric phases, solution phases, and multicomponent oxide materials [41]. Furthermore, experimental results have demonstrated the already known fact [42] that the extension of reduction of the non-stoichiometric “oxidized” state of the redox oxide in the first cycle step is not something “constant” but depends on the temperature and pressure of the experiment. The same holds true for the oxidation process: it is not necessary that all the oxygen released during TR of the oxidized state is replenished by the reduced oxide during oxidation with H2O/CO2. Thus, the following nomenclature is adopted by all groups active in the field [43,44], where the subscripts 4/3/2-δred and 4/3/2-δοx for the exemplary cases of mixed ferrites, perovskites and ceria, respectively, represent the state of reduction/oxidation reached at a particular experiment under a given temperature and pressure: ðA x B1 x ÞFe2 O4 ðA x B1 x ÞFe2 O4

δred

δred

δred

δox -ðA x B1 x ÞO3 δred

δox -CeO2 δred

δox

þ ðδred 2δox ÞH2 =COðgÞ

þ ðδred 2δox Þ=2O2 ðgÞ

þ ðδred 2δox ÞH2 O=CO2 ðgÞ-ðA x B1 x ÞO3 CeO2

CeO2

þ ðδred 2δox Þ=2O2 ðgÞ

þ ðδred 2δox ÞH2 O=CO2 ðgÞ-ðA x B1 x ÞFe2 O4

ðA x B1 x ÞO3 ðA x B1 x ÞO3

δοx -ðA x B1 x ÞFe2 O4 δred

δox

þ ðδred 2δox ÞH2 =COðgÞ

þ ðδred 2δox Þ=2O2 ðgÞ

þ ðδred 2δox ÞH2 O=CO2 ðgÞ-CeO2

δox

þ ðδred 2δox ÞH2 =COðgÞ

ð12Þ ð13Þ ð14Þ ð15Þ ð16Þ ð17Þ

In other words, the reduction product does not contain all the reducible metal cations at their lower valence state but only a smaller percentage of them since δ is usually much smaller than 1 – that is why these systems are also known as “partial reduction” systems. This has as a direct result the evolution of much less oxygen during the TR step and the consequent generation of less H2/ CO at the subsequent WS/CDS step. An advantage of this, on the other hand, is that one can make use of only the metal(s) that change their valence present in the single/mixed oxide phase and “oscillate” during the redox cycle between the reduced and oxidized structure without causing phase transformations (such as to the lower-valence metal oxide or to the respective metal) that can induce structure disruption. Such cycles employ redox pair oxides which remain condensed during the whole process, bypass the recombination issue found for volatile cycles and include today a wide variety of single- as well as multi-metal, multivalent, metal oxide families. With respect to redox materials chemistry, four major such cycles have been proposed and investigated: the ferrites, the ceria, the perovskites, and the hercynite cycles. The first three operate according to the reactions schemes (12)–(17). The materials aspects have been comparatively presented in recent publications by researchers of the German Aerospace Center/DLR [24] and of

738

Solar Fuels

SANDIA National Labs (SNL) Albuquerque, NM, USA group [45] and most recently by the present authors [30]; thus only the findings are reported here. A whole series of ferrites including either only one or two bivalent metal cations in the A site and synthesized by various techniques has been tested experimentally and studied thermodynamically initially for WS and subsequently for separate/combined CDS. With respect to materials composition, experimental, and modeling results [46,47] converge currently to the conclusion that practically only NiFe2O4 and CoFe2O4 (and their combined stoichiometries) have potential to operate reliably under the real conditions of a solar-aided process. Their TR temperatures are still high (E1300–14001C) – an important drawback since it can cause significant sintering of the oxide. Attempts to tackle this problem have been realized by supporting the redox reagent on high-temperature stable ZrO2 fine particles or supports [48–50]. Oxidation of ferrites by WS/CDS is much more rapid than their TR, requiring thus less time for completion. Solar-aided stoichiometric redox operation of the CeO2/Ce2O3 pair in WS and CDS according to scheme (6)–(7) was reported in 2006 by the PROMES (Laboratoire PROcédés, Matériaux et Energie Solaire) group in Odeillo, France. TR of CeO2 to Ce2O3 was achieved via a solar reactor at pressures of 100–200 mbar and at temperatures higher than 19501C where CeO2 was already in the molten state and a large fraction was lost due to sublimation. In 2009, a research group at California Institute of Technology (Caltech), United States, proposed a ceria-based cycle according to the non-stoichiometric reduction reaction scheme (16)–(17), not involving melting [20]; thereafter research on ceria has shifted toward this direction. Oxygen-deficient ceria shows very good reactivity with water and satisfactory H2 production yield. However, its most significant drawback is the high TR temperatures required – higher than those of ferrites, from 15001C and above – to attain significant reduction efficiency. At such temperatures – in addition to reactor material compatibility problems to be discussed below – partial sublimation of ceria can occur decreasing the reduction yield [45,51]. In an approach similar to that for ferrites, numerous stoichiometry modifications were attempted experimentally and modeled thermodynamically seeking compositions with enhanced redox/thermal stability characteristics at lower temperatures. Apart from a consensus on the well known from automotive emission control, beneficial effect of blending CeO2 with ZrO2 to induce thermal stability [52], in terms of doping with other cations, as mentioned in Ref. [45] “…in most cases the improvement in thermal reduction relative to undoped ceria is modest, and in some cases H2 production by WS actually decreases….”

Research with perovskites emerged after 2013 to mitigate the problems of the other two material families mentioned above [53]. Compositions investigated are targeted to Fe, Co, La, Sr, and Mn combinations. Experimental results converge to that perovskites exhibit higher oxygen yields that ceria during TR at moderately high temperatures; however, most of them are characterized by incomplete reoxidation from either CO2 [54,55] or H2O. In fact, recent analysis has shown that the poor reoxidation performance observed in such systems is due to thermodynamic constraints imposed by both the reduction enthalpy and entropy [37,45]. The fourth nonvolatile, the doped-hercynite cycle with a mixed cobalt ferrite–hercynite system (CoFe2O4/FeAl2O4) was proposed by the University of Colorado (UoC), Boulder, United States, as an effective WS/CDS system capable of producing appreciable amounts of CO after TR at temperatures approximately 100–150K lower than values reported for ferrites or CeO2. The details of the cycle can be found in several relevant publications [56–58]. Despite the encouraging results reported therein, in a more recent review by the same main authors it is stated that “…However, there are no published reports confirming the hypothesized reaction scheme and further work is necessary to validate and more completely understand this reaction mechanism…” [31].

The relevant issues on the exploration of various redox pairs for WS–CDS/TR TCs can be found in several review articles [11,22,59,60]. The technical baseline is that despite extensive research on multi-cation combinations in all three material families above, currently there is no system exhibiting a TR temperature below 13001C even at the lowest partial pressures of oxygen achieved under either inert gas atmosphere or vacuum.

4.18.3.2

Coupling Redox Chemistry to Solar Energy: Solar Receiver–Reactors

The above temperature level leaves only solar towers and dishes as the high-temperature-heat CSP source of choice (Fig. 1(C)) [61], whereas the size limitation of solar dishes practically excludes them based on scalability criteria. Thus, most research and development work in the field is targeted on implementing TCs on solar towers, with predevelopment tests performed in either solar simulator or solar furnace facilities. In a solar tower, the solar energy is concentrated on a focal point by the mirrors (heliostats), providing thus high temperature heat. A heat exchanger called “receiver” is used, located in the concentration field of the radiation: its task is to “trap” (absorb) the concentrated solar radiation and transfer it to a heat transfer fluid/HTF (air, water, or molten salt) at the highest possible temperatures. Solar receivers are categorized either according to the mechanism of transferring the solar heat to the HTF to directly and indirectly heated ones, or according to their geometrical configuration in external and cavity-type receivers [12]. The characteristics of all receiver kinds have been described in detail in many recent reviews [62,63]. In all cases, the solar receiver is designed so that to approach a blackbody in its capability to trap incident solar radiation by making use of cavities and black-painted tube panels or porous absorbers. Solar thermochemical applications employ the same concentrating technologies but instead of a “plain” receiver, a receiver– reactor is employed, where endothermic chemical reactions are performed (Fig. 1(C)). The temperature levels required for the TR

Solar Fuels

739

step (1300–16001C depending on the redox material used) that needs to be solar-aided, impose challenging reactor operation conditions. Requirements in relation to reactor construction are superimposed to those for the redox material. The high TR temperatures may cause evaporation of volatile compounds, reactant loss or composition changes, activity reduction or side reactions with the reactor materials; solar absorbance and resistance against thermal shock and fatigue must also be considered. For the efficient design and operation of solar receiver–reactors, concepts from “traditional” chemical reactor engineering should be combined with efficient ways of heating the reactor via concentrated solar irradiation. Involving gas–solid reactions, the situation with redox pairs resembles that of catalytic reactions between gases where the reactant gas species react at the surface of a solid catalyst to be converted to useful gaseous products. In the “traditional” nonsolar chemical engineering, such catalytic reactor types can be distinguished in two broad categories depending on whether the catalyst particles are distributed randomly or are “arranged” in space at the reactor level. The first category includes packed and fluidized beds; the second comprises the so-called “structured” systems like honeycomb, foam, and membrane catalytic reactors, all three being free of randomness at the reactor level [64–67]. In a direct analogy to “conventional” catalytic applications, both configurations can be employed for redox solid oxides. “Loose” particles as well as porous structures can be contained either within solar-heated tubular receivers or directly exposed to solar irradiation. Differences between “traditional” and “solar” chemical engineering though, have to be accounted for. In “traditional chemical engineering” the hot effluent gases from an automobile internal combustion engine or a gas-powered plant heat an initially “colder” catalytic honeycomb reactor. In contrast, in “solar chemical engineering” the solid is first heated by absorbing concentrated solar irradiation and then employed to heat up the initially colder reactant gases to the reaction temperature. Furthermore, in solar redox chemistry, the solid reactant (metal oxide) is not a “catalyst” present in much smaller quantities than the gaseous reactants but a reactant itself, with non-negligible mass, which not only has to be heated to the reaction temperature but also gets progressively depleted during the course of the reaction, having to be replenished. Therefore it either has to be fed constantly into the reactor if the reactions are to be performed in a continuous mode, or, alternatively, practical ways have to be “invented” for its’ in situ regeneration. Last but not least, the reactor being either a packed or fluidized bed or a porous structure like a honeycomb or a foam, has to incorporate as much of the redox oxide solid reactant as possible; on the one hand, to maximize volumetric product yield and, on the other hand, to avoid the “waste” of external energy in heating chemically inert materials to high temperatures. To further complicate the issue, the TR and the (H2O/CO2) splitting reactions are thermodynamically favored by different conditions [68]: reduction by high temperatures and low oxygen partial pressures and splitting by low temperatures and high partial pressures of H2O/CO2. However, to ensure satisfactory splitting reaction kinetics and thus rates require sufficiently high temperatures – but not so high to induce the TR simultaneously to splitting. Therefore the splitting reactions should, in principle, take place at high, yet lower temperature levels (700–10001C) than the TR ones. In other words the complete cyclic operation has to be carried out under a “temperature-swing” mode whereas in parallel the gaseous feed to the metal oxide has to swing between H2O/CO2 and inert purge gas. This is a common problem for all single- and mixed-oxide redox systems mentioned above, causing complications with respect to reactor design and oxide material handling between the two stages. This temperature swing induces additional issues relevant to efficient heat utilization between the two reaction steps. The sensible heat available after the higher-temperature TR step has somehow to be recovered and reused effectively. Heat rejection at the TR temperature levels of 1300–16001C needs to be avoided as far as possible because the associated heat losses can render the efficiency of the system detrimentally low for the economics of the whole process. The importance of such heat recuperation has been extensively stressed [68,69]. Whereas the “material-related” problem in this respect is the low extent of TR, in solar-aided operation the heat recuperation which is a property of the reactor design comes also into play. At this stage the problem is shifted from chemistry issues discussed above to heat transfer ones and the issue of a solar reactor type becomes important. In this respect the various reactor designs proposed for the particular application have stemmed to a large degree from the quest for effective heat recuperation concepts. Reactor concepts and designs have implemented different technical solutions in order to perform both steps of the cycle on-sun within a single-system configuration and meet the technical requirements of two process steps performed at different temperature levels with different heat demands. One fundamental distinction has to do with whether such reactors employ moving or only stationary parts. Two concepts exist to alternate the operating status of the reactants periodically, attaining either a continuous or a batch-wise H2/CO/syngas production. For the former concept, such continuous production is achieved by moving the reactive particles or structures from a TR reactor or zone to a splitting reactor/zone. The two reactors/zones are operated at different temperatures and at least the TR reactor is heated by solar irradiation. Gas streams and solar irradiation can be provided continuously to the reaction chambers. The second concept foresees splitting and reduction taking place in one single reaction chamber avoiding thus any solids transportation. By that means, batch-wise production of H2/CO/syngas is achieved by switching the gas streams in the reaction chamber from reducing to oxidizing atmosphere. Simultaneously, solar flux densities need to be adjusted in order to realize the two different temperature levels and heat demands of reduction and splitting. This is typically realized by diverting the solar flux periodically. All these concepts have been extensively described in the previous review by the authors published in 2015 [30]; more recent developments are discussed below.

4.18.4

Analysis and Assessment

Process efficiency is a requirement for commercial viability. Various definitions of efficiency have been proposed, but a full accounting of the thermal energy and work input to cycle should be considered. These “cycle efficiencies” correlate the higher

740

Solar Fuels

heating value of the fuel produced to the thermochemical cycle energy input (i.e., the amount of energy that must be supplied to carry out the entire cycle). It has been argued that “…thermochemical routes to solar fuels must achieve a system level AASFE (annual average solar to fuel efficiency) in excess of 20% to be considered a viable alternative…against more conventional and low risk approaches based on electrolysis…Our analysis shows that meeting the viability metric requires a reactor thermochemical efficiency of at least 36% (heat to chemical energy in the reactor)…” [69].

Furthermore, United States Department of Energy (DOE) has set the technical target for hydrogen production from thermochemical WS as a “Solar to hydrogen (STH) energy conversion ratio” of 20 for year 2020 [70]. This resulted in as quoted from Ref. [71] that “…The thermal efficiency of the solar-to-fuel conversion process is used by the research community as a surrogate to economics to project the commercial viability of thermochemical metal redox cycles because reactors to implement these cycles are still early in the research and development phase...”

With this target, an intensive effort has been undertaken in identifying, by thermodynamic means, conditions and operating modes that maximize this STH conversion efficiency. Due to the abundance of thermodynamic data for the ceria system in contrast to the multi-cation combinations of ferrites and perovskites, the efficiency of the former cycle has been assessed extensively correlating the extent of reduction δ with the reduction temperature, the operation temperature swing, and the oxygen partial pressure. In this perspective, on the one hand, for the elimination of energy losses associated with cyclic heating and cooling of the metal oxide together with practical overcoming of problems associated with heat recuperation issues such as thermal stresses in reactor components and slower oxidation kinetics, “isothermal thermochemical cycles” have been proposed for the ceria [44] as well as the hercynite reaction scheme [58]. It is also obvious that while higher reduction temperatures lead to higher theoretical efficiencies, reduction cannot be conducted at arbitrarily high temperatures due to practical and economic concerns: reradiation losses through the receiver/reactor, potential melting, or sublimation of the redox oxides, side reactions with the reactor containment materials. Furthermore, subsequent thermodynamic studies by the University of Minnesota (UoM) and the SNL groups [72,73] concluded that the isothermal cycle is less favorable than a temperature-swing cycle, due to limitations entirely of water thermodynamics independent of alternative materials or reactor designs. As mentioned in a recent SNL review article [37] “…it is impossible to split H2O using CeO2 isothermally at 1773K unless the final state H2O:H2 ratio exceeds 25:1…”

In the same reference it is mentioned then for ceria as well as for any other redox material operating in a similar mode, the “…CeO2 STH efficiency achieves a maximum at some intermediate differential temperature as opposed to increasing continuously as would be expected for a Carnot heat engine…”

A peak efficiency exists for any of the combinations between temperature/pressure swing width, extent of non-stoichiometry swing δ and percentage of heat recovery achieved. The SNL group advocated for an optimal temperature difference between cycle steps and a combination of well-targeted pressure and temperature swing rather than either individually, as the most efficient mode of operation of a two-step thermochemical cycle for solar fuel production. Obviously, low oxygen partial pressures increase the thermodynamic driving force of the reduction reaction. Research in this direction concerned the proper selection of oxygen partial pressure operation and the means to achieve it practically. Indeed, thermodynamic calculations have demonstrated the beneficial effect of reduced pressure on the extent of reduction for a variety of oxides [74,75]. Quoting from [31]: “…Low O2 partial pressures are achieved by either large vacuum pumping or large excess of inert gas sweep. This increases the mechanical work required for reduction because operating under high vacuum is difficult at the high temperatures required for reduction and large inert flow rates require significant pumping work to move excess gas and significant separations work to remove the O2 from the inert. The high levels of excess steam required to drive the oxidation reaction lead to higher pump work requirements and higher heat duties for steam heating; the effects of which can have substantial detrimental effects on the overall efficiency of the system…”

Several studies thus concerned efficiencies comparison of specific cycles with respect to vacuum pumping versus inert gas sweeping. All these operation concepts proposed to maximize efficiency are discussed below in conjunction with the specific reactors associated with them.

4.18.5

Case Studies

The reactor technologies set forth are thus in close conjunction with the characteristics of the particular chemical system chosen for the implementation of the TC. A classification of such cycles in the literature is to the so-called “nonvolatile” and “volatile” cycles

Solar Fuels

741

according to whether the metal-containing species remain in the condensed state during the entire process or not. The current state of the art in these two categories follows.

4.18.5.1

Volatile Thermochemical Cycles: The ZnO/Zn and the SnO2/SnO Cycle

Since the temperatures required for the thermal decomposition reactions are high, they often exceed the boiling temperatures of the reduced species. Thus, “volatile” redox pairs employed in two-step WS/CDS cycles commonly exhibit a solid-to-gas phase transition of the other-than-oxygen product (either the metal or the lower-valence oxide) in the reduction step. This phase transition is, on the one hand, a thermodynamic advantage beneficial for the process, because a high entropy gain is obtained but also a major technical drawback: a gaseous mixture of the reduced phase (this being either an oxide or a metal) and oxygen occurs which needs special treatment to avoid its recombination back to the original oxidized form. This fact precludes the direct combination with the other cycle step, i.e., the “oxidation” (via steam or CO2) reactor and therefore, all such systems consist of two separate reactors. Solar reactors targeted to such systems have been designed to perform only the first, higher-temperature TR step from which a condensed reduced phase is obtained together with gaseous oxygen. The second step of these cycles involves the oxidation of the elementary metal/reduced oxide in H2O/CO2 where H2/CO is generated and the metal oxide is recovered and recycled. This step need not be solar-aided and since the two steps are decoupled, the production of H2 and/or CO can be carried out on demand and round-the-clock at convenient sites and independent of solar energy availability [76]. Among the various such cycles proposed (ZnO/Zn, SnO2/SnO, CdO/Cd, and GeO2/GeO) [30] the ZnO/Zn and SnO2/SnO ones have been studied most extensively and only the former has reached a pilot-level demonstration scale as described below. The decomposition temperature of ZnO is approximately 20001C, whereas Zn melts at 4201C and has a boiling point of 9071C. The ZnO/Zn cycle was first proposed by Bilgen et al. [77]. Based on thermodynamic calculations it was considered among the most promising cycles with respect to theoretical process efficiency [78,79]. It was most extensively studied by the research group at Swiss Federal Institute of Technology/Paul Scherrer Institute (ETH/PSI) in Switzerland as well as by the groups of PROMES in France and of UoC in the United States. The work of ETH/PSI originally focused on the application of this cycle for WS and hydrogen generation [80] and subsequently on CDS [81]. The most challenging part of this process is the reduction of ZnO via solar decomposition into Zn and ½ O2. The product mixture needs to be quenched to avoid recombination, with the quenching efficiency being sensitive to the dilution ratio of Zn(g) in an inert gas flow and to the temperature of the surface on which the products are quenched. As a result, the final product leaving the solar reactor/quencher, that is, the feed for the oxidation step, generally contains a substantial amount of ZnO, observed to range between 6 and 85 mol% depending on reaction conditions and inert gas/Zn(g) dilution ratio. The PROMES group has also proposed and systematically investigated the SnO2/SnO cycle for WS and CDS. In this cycle the solar-aided TR step consists of the reduction at approximately 16001C of SnO2 into gaseous SnO under atmospheric pressure – since its boiling temperature is 15701C – and O2 [82]. Then a nonsolar exothermic reoxidation of SnO(s) by H2O/CO2 follows to form H2/CO2 and SnO2(s). Hydrolysis takes place at about 6001C while the splitting of CO2 requires significantly higher temperatures (8001C) to reach complete particle conversion. Advantages claimed over the Zn/ZnO cycle are the lower TR temperatures, the slower undesirable reoxidation of SnO to SnO2 compared to that of Zn to ZnO which enables higher product recovery yields and the higher H2 yield of SnO over Zn during hydrolysis [83]. Obviously, the cycle faces the same recombination problems, with the product consisting of a mixture of SnO and SnO2. The progress and current development level achieved on the ZnO/Zn cycle are summarized in a recent review by PSI [32]. A windowed rotating cavity solar receiver–reactor (initially called therefore ROCA [84]) was first employed by the ETH/PSI group to perform the ZnO dissociation step under solar irradiation in their solar furnace facility (Fig. 2(A); [85]). The reactor was lined with ZnO particles continuously fed via a screw feeder, held by centrifugal force and directly exposed to high-flux solar irradiation serving simultaneously the functions of radiant absorber, thermal insulator, and chemical reactant. Solar tests carried out with the next generation,10 kW prototype solar reactor ZIRRUS employing sintered alumina as insulation (Fig. 2(B)) at temperatures above 17001C proved the low thermal inertia of the reactor system, its resistance to thermal shocks and the functionality of the overall engineering design [86]. An overview of the work until then on the two-step solar WS/CDS TCs with Zn/ZnO redox reactions was published outlining the underlying science and the technological advances in solar reactor engineering along with life cycle and economic analyses [85]. The same reactor configuration was employed by the PROMES group for ZnO TR under controlled atmosphere at reduced pressure applied by a vacuum pump [87]. The ZnO powder was injected continuously inside the cavity; dilution/quenching of the product gases with a neutral gas yielded Zn nanoparticles by condensation, recovered in a downstream ceramic filter with maximum yield of particles recovery 21% and dissociation yield up to 87%. To circumvent problems inherently related to cavity rotation such as sealing of rotating components both the ETH/PSI and PROMES groups attempted at some point to substitute the redox oxide powder with shaped objects made of it. The ETH/PSI reactor described above was modified to include ZnO blocks pre-sintered at 10001C as solid samples positioned in the reactor and essentially subjected to thermal ablation [88] in a moving-reaction front concept where a pressed ZnO cylinder could be continuously advanced to the focal point from the back of the reactor. The same principle was adopted by PROMES where a “moving front” reactor suitable for both the SnO2/SnO and ZnO/Zn cycles [89] was tested at about 16001C. Each test produced about 1 g of powder with significant fractions of reduced species in less than 30 min for a pressure of 20 kPa. In addition, the mass fractions of reduced species in the synthesized SnO powders (maximum 72%) were always higher compared to Zn under similar conditions corroborating that the recombination reaction is less favoured in the case of SnO.

742

Solar Fuels

In parallel, realizing the engineering complexities introduced via the use and maintenance of a rotating reactor assembly, the ETH/PSI group in cooperation with University of Delaware, United States, introduced later another type of cavity reactor, the so-called gravity-fed, entrained bed reactor [90]. In this implementation, the cavity arrangement is maintained to achieve the high temperatures required for ZnO dissociation, whereas the feedstock ZnO powder is fed continuously to the (nonmoving) reactor by a series of 15 vibrating hoppers distributed along the reactor’s upper perimeter (Fig. 2(C)). The powder thus falls as a thin sheet under gravity into the reaction chamber where slides along the surface of an inverse, inclined code consisting of alumina tiles essentially forming a moving-bed reactive layer. Being gravity-driven the reactor configuration has to be vertical and therefore

5

ZnO feeder

9

Rotary joint

Water/gas inlets/outlets

Ceramic insulation

ZnO

Cavity-receiver

6

Zn + ½ O 2 Quartz window

10

7 2 1

Concentrated solar radiation

4 8 3 (A)

(B)

1 2 3 4 5 6

B

7

(C)

2

3 4 7 5

1 (D)

8

6

Solar Fuels

743

heated by a beam-down solar concentration system. Experiments at the solar simulator facilities of PSI were performed (but only up to 9001C) to test the mechanical and structural stability and the reaction-surface adhesion process. With respect to the second step, nonsolar exothermic oxidation studies of Zn by H2O and/or CO2 to form H2 and/or CO have shown a positive effect of solid diluent ZnO on the oxidation extent [91] indicating thus that solar reactor products consisting of Zn/ZnO mixtures could be used as such in the oxidation step.

4.18.5.1.1

Current status of technology

Of all these reactor concepts only the rotating cavity reactor of ETH/PSI was scaled up to a 100 kW solar pilot reactor for ZnO dissociation (Fig. 2(D)) demonstrated at the Megawatt Solar Furnace at the PROMES facility in Odeillo, France [32]. During testing campaigns carried out in 2012-14 the pilot plant was operated for over 97 h and achieved sustained reaction temperatures above 17001C. The products Zn and O2 were quenched with argon delivered from a liquid tank and Zn was recovered in a pair of filter batteries as partly oxidized particles in the range of 5–30 mm. Over 28 kgs of ZnO were dissociated over 13 days of experimentation, with average dissociation rates as high as 28 g/min yielding a Zn molar fraction of the condensed products as high as 44 mol% but on average significantly lower (o10%), largely dependent on the flow rate of Ar injected to quench the evolving gaseous products [92,93]. In these experiments the reactor was operated with solar power delivered to the reaction cavity ranging between 90 and 128 kW and with peak flux density as high as 4671 kW/m2. A maximum solar-to-chemical efficiency based on the collected products from the dissociation reaction was reported at 3%. The solar-to-fuel efficiency of the pilot-scale solar reactor was primarily limited by an excessive use of quench gas (E2000 L/min). Even though significant progress has been made over the last years on scaling up a solar reactor for ZnO decomposition, still a complete cycle including the splitting step has not been validated yet; at the best the solar production of Zinc has been demonstrated. The common problem of all reactors to perform only the TR step is that their integration with their “oxidizing” (“splitting”) counterparts and relevant heat recuperation still needs to be demonstrated. Furthermore, even for the ZnO decomposition step alone, the quench gas cost has a significant impact on the H2/syngas price to be produced on commercial scale. The opinions of two of the research groups among the most actively involved in such volatile WS/CDS TCs, as expressed in their most recent review articles, seem to converge. The UoC group mentions “…While the SnO2/SnO solar thermal water splitting (STWS) cycle appears to be more promising than the ZnO/Zn cycle, the SnO2/SnO cycle is still plagued by low recovery of the reduced material and the difficulties inherent in quenching the reduction product and handling the resulting reduced solids. Without significant improvements to address these issues, volatile stoichiometric STWS cycles will likely be impractical for commercial water splitting…” [31].

The PSI group states in their respective most recent review that “…we conclude that one should not proceed with solar fuel production using the Zn/ZnO thermochemical cycle unless significant advances are made in product separation and/or efficient inert gas recycling...” [32].

4.18.5.2

Nonvolatile Cycles: The Ferrites, Ceria and Perovskites Cycles

The material families operating in this mode share many commonalities. First they are limited by the small width of the nonstoichiometry swing δ, discussed above. Being throughout the cycle in the solid state, they offer more possibilities concerning a common reactor concept, process design, and operation mode due to the possible use of either particle receiver–reactors or structured ones consisting of monolithic structures, such as honeycombs, foams, or fins. Such reactors are designed to perform both cycle steps during on-sun operation but different concepts are implemented for this goal. Even though, in analogy with reactors for volatile cycles, solar (basically aerosol) reactors performing on-sun only the TR step of nonvolatile cycles have been proposed, they have not reached the development status of reactors performing both cycle steps. Thus, herein only the former Fig. 2 (A) ROCA solar reactor design for ZnO dissociation (reprinted from Loutzenhiser PG, Meier A, Steinfeld A. Review of the two-step H2O/ CO2-splitting solar thermochemical cycle based on Zn/ZnO redox reactions. Materials 2010;3:4922–38 with permission from Elsevier): (1) rotating cavity receiver, (2) cavity aperture, (3) quartz window, (4) compound parabolic concentrator (CPC), (5) outside conical shell, (6) reactant feeder, (7) ZnO layer, (8) purge gas inlet, (9) product outlet, and (10) quench device; (B) ZIRRUS 10 kW rotating ZnO solar reactor (reprinted from Loutzenhiser PG, Meier A, Steinfeld A. Review of the two-step H2O/CO2-splitting solar thermochemical cycle based on Zn/ZnO redox reactions. Materials 2010;3:4922–38, with permission of main author): (1) quartz window, (2) cavity aperture, (3) conical frustum, (4) reaction cavity, (5) insulation, (6) rotary joint, and (7) quench unit; (C) the gravity-fed moving-bed reactor: schematics of operation principle and actual photographs: (1) water-cooled window mount and vortex-flow generation, (2) water-cooled cavity aperture, (3) BOP and data-acquisition cavity access ports, (4) alumina-tile reaction surface, (5) annular solid ZnO exit, (6) bulk insulation and cavity-shape support, and (7) central product-vapor and gas exit (reprinted from Koepf E, Advani SG, Steinfeld A, Prasad AK. A novel beam-down, gravity-fed, solar thermochemical receiver/reactor for direct solid particle decomposition: design, modeling, and experimentation. Int J Hydrogen Energy 2012;37:16871–87 with permission from Elsevier); (D) the 100 kW ZnO solar pilot plant developed at PSI (reprinted from Koepf E, Alxneit I, Wieckert C, Meier A. A review of high temperature solar driven reactor technology: 25 years of experience in research and development at the Paul Scherrer Institute. Appl Energy 2017;188:620–51 with permission from Elsevier): (1) quartz window mount, (2) cavity aperture, (3) aluminum shell, (4) hopper containing ZnO, (5) retractable screw feeder, (6) product hoses, (7) product filters, and (8) movable carriage.

744

Solar Fuels

category will be addressed. The majority of such reactors are directly irradiated receiver–reactors (DIRRs): they employ solid particles or structures directly exposed to the concentrated solar radiation. Since the working fluid at the TR stage is not air, the receiver–reactors must be equipped with a transparent window, which allows concentrated light to enter the receiver while isolating the working gas from ambient air [62] and providing for operation under non-atmospheric pressures if needed.

4.18.5.2.1

Nonstructured (particle) receiver–reactors

4.18.5.2.1.1 The spouted bed reactor The research group of Niigata University, Japan, has set forth the concept of an internally circulating “fluidized” bed reactor (or, in a more precise terminology, a “spouted” bed reactor) in a series of publications [94–98]. A schematic of the operating concept and a photograph of such a reactor operating while irradiated by a 3 kW solar simulator are shown in Fig. 3(A) and (B). The redox oxide particles are circulated through an internal annulus from the bottom to the top of the reactor and are exposed to concentrated solar radiation entering from a window at the top, at the uppermost points of their trajectories. The idea is that internal circulation will, among others, inhibit sintering and agglomeration of the redox oxide particles avoiding hence a pulverization process after the TR step. In addition, sequential performance of the two steps of the cycle would be possible in a single reactor by switching the feed gas between an inert gas (N2) for the TR step to steam/CO2 for the WS/CDS step. Such chemical reactors were tested for TR with unsupported NiFe2O4 as well as supported NiFe2O4/ZrO2 particles. First tests involved only the TR reaction, removing the reduced powder and performing in another nonsolar rig the WS reaction, whereas subsequently both steps were tested in the same spouted bed reactor [97]. During these tests the temperature at the surface of the fluidized particle bed during TR step reached 1500–16001C in the draft tube region and 1100–14501C in the annulus region. Approximately, 35% of the supported NiFe2O4 was reported to have been converted to the reduced phase, and subsequently completely reoxidized with steam at 11001C to generate H2, remaining in powder form without sintering and agglomerating during Xe-beam irradiation over 30 min. In a scaled-up version this receiver/reactor concept needs to be combined with a beam-down type solar concentrator as per the schematic in Fig. 3 (D). In parallel to such scale-up activities described below, a new, bigger (30–40 kWth) “beam-down” sun-simulator with xenon-arc lamps was installed at Niigata University to carry out tests in lager scales (Fig. 3(C)). The first such tests were performed with quartz sand particles that could reach 1050–12001C by direct irradiation through the quartz window [99]. 4.18.5.2.1.1.1 Current status of technology Niigata University, University of Miyazaki, and Miyazaki prefecture have started an R&D joint project since 2011 to demonstrate the technology on-sun. A new type of 100 kWth beam-down solar concentrating system with a secondary elliptical reflector was built in August 2012 at the campus of University of Miyazaki (Fig. 3(E)). Performance tests of this beam-down system with/ without a compound parabolic concentrator (CPC) (Fig. 3(G)) were implemented in 2012–4 [100]. Even though the solar demonstration of the reactor at the Miyazaki beam-down system was foreseen for October 2013 no such tests have been reported in the open literature so far. 4.18.5.2.1.2 The moving packed bed reactor Streams of particles can be used as both heat transfer fluids and heat storage media just like molten salts, being though capable of achieving much higher temperatures. In addition to revitalizing research on falling particle receivers proposed by SNL in the 1980s, as a natural follow-up such reactor concepts of continuously moving beds of redox oxide particles that can transport and exchange heat with countercurrent/concurrent fluids or other particle streams were invoked to address the critical issue of heat recuperation in WS/CDS TCs. A schematic of the operating principle of such a reactor as initially proposed by a consortium of US researchers from SNL, Bucknell University, and Arizona State University [101] is shown in Fig. 4(A). The oxide particles in their oxidized state are transported by a vertical screw elevator/feeder to the top of a solar tower, where concentrated solar radiation enters through a window-covered aperture, directly heating and thermally reducing them, producing oxygen, which is pumped away from the chamber. The packed bed of the reduced particles produced, moves then downwards via a connecting tube in a counter-flow arrangement with respect to the oxidized particles moving upwards, essentially preheating them. Heat transfer via conduction, from the hot (reduced) particles to the colder (oxidized) ones is augmented by the extended surface area of the conveyor auger. In this respect the whole reactor consists of three sections: a TR chamber at the top, a recuperator (solid–solid heat exchanger) in the middle, and a fuel production chamber (at the bottom). In the fuel production chamber, the particles are exposed to reactant gases (H2O or CO2) reducing them to fuel products (H2 or CO). The mix of reactants and products (H2O/H2 or CO2/CO) is removed from the chamber and the reoxidized particles are fed into a return elevator that brings them to the inlet of the recuperator/elevator to continue the cyclic process. Advantages claimed are solid–solid sensible heat recovery between reaction steps, spatial separation of pressures, temperature and reaction products in the reactor and continuous on-sun operation. It is also claimed that vacuum pumping of the TR half of the cycle – i.e., operating the entire reactor at sub-ambient pressure – made possible by pressure separation in the particular reactor design, has a decisive efficiency advantage over inert gas sweeping currently explored. In addition, the so-called “cascading pressure” operation concept, consisting of performing the TR step in multiple chambers, each operating at a successively lower pressure and within which only a fraction of the oxygen evolved is pumped out of the chamber, has been proposed and simulated to increase the extend of the TR reaction and achieve higher efficiencies than a single-stage reactor. The optimal difference between reduction and oxidation temperatures for such a concept has been calculated. Conversion efficiencies of solar energy into H2 and CO exceeding 30% have been reported by simulations, using CeO2 as a reactive material.

Solar Fuels

745

Reflective tower

Concentrated solar radiation Quartz window

H2/O2 Reacting particles Draft tube Stainless reactor

Heliostats

Distributor Gas flow

(A)

(B)

(C)

Elliptical secondary reflector 1st Focal point

2nd Focal point

Heliostats Reactor

(D)

(F)

Concentrator (CPC)

(E)

(G)

Fig. 3 The spouting bed reactor of Niigata University, Japan: (A) schematic of operation concept and (B) actual photograph of such a reactor operating while irradiated by a 3 kWth solar simulator (both reprinted from Gokon N, Mataga T, Kondo N, Kodama T. Thermochemical two-step water splitting by internally circulating fluidized bed of NiFe2O4 particles: successive reaction of thermal-reduction and water-decomposition steps. Int J Hydrogen Energy 2011;36:4757–67 with permission from Elsevier); (C) bigger, 19  7-kW xenon-arc lamps beam-down sun-simulator and bottom view of 19 xenon lamps in the simulator house (reprinted from Kodama T, Gokon N, Cho HS, et al., Particles fluidized bed receiver/reactor with a beam-down solar concentrating optics: 30-kWth performance test using a big sun-simulator. In: AIP conference proceedings. AIP Publishing; 2016. p. 120004 with permission from AIP Publishing); (D) principle of the beam-down solar concentration system (reprinted from Kodama T, Gokon N, Cho HS, et al., Particles fluidized bed receiver/reactor with a beam-down solar concentrating optics: 30-kWth performance test using a big sun-simulator. In: AIP conference proceedings. AIP Publishing; 2016. p. 120004 with permission from AIP Publishing); (E) 100 kWth beam-down solar concentrating system (reprinted from Kodama T, Gokon N, Cho HS, et al., Particles fluidized bed receiver/reactor with a beamdown solar concentrating optics: 30-kWth performance test using a big sun-simulator. In: AIP conference proceedings. AIP Publishing; 2016. p. 120004 with permission from AIP Publishing); (F) compound parabolic concentrator (CPC), installed in Miyazaki and (G) CPC reflectors viewed from bottom (both reprinted from Kodama T, Gokon N, Matsubara K, et al., Flux measurement of a new beam-down solar concentrating system in Miyazaki for demonstration of thermochemical water splitting reactors. Energy Proc 2014;49:1990–8 with permission from Elsevier).

Conceptual designs of such a multistage cascading pressure reactor were elaborated (Fig. 4(B)) and first construction steps of a prototype were reported together with proof-of-concept experiments demonstrating that dynamic pressure separation via packed beds can be achieved in small scale. However, only one of the key components, the particle conveying system in vacuum, has so far been tested but only with chemically inert bauxite particles and at temperatures only as high as 6001C [102]. Exploring further the ideas above, different concepts for solid–solid particles heat exchange followed. Instead of directly irradiating a redox particle stream in a solar receiver, the idea to heat therein a nonreactive particle stream to a sufficiently high

746

Solar Fuels

temperature and use then the enthalpy of this stream to heat another stream of redox particles to the temperature level required for their TR away from the solar receiver, has been set forth by researchers of DLR [103]. The overall concept is depicted schematically in Fig. 4(C)–(E). After being solar-heated and then stored in a high-temperature storage unit (ST) (Fig. 4(C)), the heat transfer spheres are fed continuously to the reduction reactor (RR) where the oxidized redox particles are fed as well [104]. The RR is essentially a mixing chamber where the two particle streams come into direct contact and exchange heat as they move downwards in a moving bed, driven by gravity (Fig. 4(D)). At the end of the mixing stage the redox particles should have been heated above their reduction temperature, having evolved oxygen and having been transformed to their reduced state. Provided that the particles and the spheres are of different dimensions, a ceramic sieve can separate them in two streams having nearly the same temperature. On their way out of the RR toward the oxidation-reactor (OR) the reduced redox particles transfer their heat to the oxidized redox

Solar Fuels

747

particles after leaving the OR by means of a third inert particle stream. In the OR the reduced, lower-temperature redox material stream is used to split H2O, CO2 or a combination of both. The oxidized particles are fed gain, preheated by the heat transfer spheres to the RR, to close the cycle. In parallel, the “colder” heat transfer spheres are transported back to the solar receiver to be heated again. To increase the limited heat recovery rate resulting from the co-current flow, several steps can be used in a row to realize a quasi-counter-current principle as shown in Fig. 4(E) [103]. The RR can be operated at a fixed oxygen partial pressure PO2 which is achieved using a vacuum system. One option to reduce the auxiliary power consumption of the vacuum system is dividing the reduction by using a sequence of RRs operated at optimized PO2 levels. Potential benefits claimed are mainly operational decoupling of the process steps that can thus be independently developed and optimized. For instance, the receiver layout can adapt designs and practices of open particle receivers without introducing therein the complications of chemical reactions especially under low oxygen partial pressure. The particle–particle heat transfer concept was tested experimentally in labscale to calculate the heat transfer coefficient between CeO2–ZrO2 (redox) and alumina (inert) particles of different sizes, but the experiments were limited to 2501C [105]. Another reactor concept based on redox particle streams flowing between the reduction and oxidation reaction chambers has been proposed recently by the group of UoC, the so-called solar thermal particle flow reactor (SPFR) [31]. The reactor concept is shown in Fig. 4(F). The design is based on a beam-up approach and consists of several sets of reduction/oxidation chambers arranged in an inner and outer circle where the reduction chambers form the inner ring of the reactor. Concentrated sunlight is directed up through the gap in the bottom of the receiver and the entire apparatus is envisioned to sit atop a solar power tower, as shown in Fig. 4(G). Starting from fully oxidized material, the particles fall through the falling particle RR, which is heated indirectly through the reactor wall, where a low oxygen partial pressure is maintained using vacuum pumping. The reduced particles are stored as a pseudo-packed bed at the bottom of the reduction chamber before they enter the oxidation reactor. The packed bed moving storage section provides a pressure buffer, enabling for both a low pressure in the RR and a high steam partial pressure in the oxidation reactor. After storage, the reduced particles are entrained in steam and conveyed upwards to a fluidized bed oxidation chamber. Oxidized particles fall to the bottom of the oxidation chamber and are stored in a second packed bed before reentering the RR. The reduction and oxidation reactions could be run at near-isothermal temperatures, reducing the need for solid–solid heat recuperation and lowering thermal stresses on the reactor due to cooling and reheating. Process heat recuperation is accomplished by utilizing the heat from both the liberated O2 and product H2 and unreacted H2O to generate electricity or preheat reactant steam. Advantages claimed are that gas–solid mixing in a fluidized bed promotes rapid transport of gaseous reactants and products to and from the reactive solids, while providing heat transfer between the gases and solids, including both the reactive solid particles and the reactor walls. 4.18.5.2.1.2.1 Current status of technology A commonality in rationale among such concepts is that they have initiated from theoretical investigations showing that high efficiencies that can meet the economic targets set, can be achieved. Many thermodynamic efficiency studies of varying complexity have been published. Earlier studies have indicated that conversion of solar energy to stored chemical energy could be higher than 40% [106] under ideal conditions. The ceria system in particular has been studied extensively. The effects of sweeping with inert gas under co-current or counter-current gas–solid flow have been studied analytically to identify further potential of efficiency increase [107–109]. The conclusion was that a counter-flow arrangement of the purge gas, which is introduced at the point with the highest oxygen deficiency, decreases the total amount of purge gas required. Vacuum pumping options were comparatively screened. A wide range of projected efficiencies has been reported depending on how idealized or modest are the assumptions concerning percentage of heat recovery, thermal losses, chemical equilibrium, vacuum levels achieved, etc. Interestingly enough, some models predict higher thermodynamic efficiencies of ferrite/zirconia composites than of ceria [110]. However, all such studies are based on heat exchange and recovery between two solid oxide “flows” or regions and is beyond any doubt that a high degree of such a heat recuperation has to be implemented to achieve reasonable efficiencies [111]. Fig. 4 Moving bed particle reactor concepts proposed: (A), (B) The moving packed bed redox solar reactor proposed by Sandia Labs, Bucknell University and Arizona State University: (A) operating principle schematic (reprinted from Ermanoski I, Siegel NP, Stechel EB. A new reactor concept for efficient solar-thermochemical fuel production. J Solar Energy Eng 2013;135:031002 with permission from ASME); (B) conceptual drawing of the cascading pressure reactor and prototype diagram, with loose resemblance to reactor geometry (reprinted from Ermanoski I, Grobbel J, Singh A, et al., Design and construction of a cascading pressure reactor prototype for solar-thermochemical hydrogen production. In: SolarPACES 2015 AIP conference proceedings. vol. 1734; 2016. p. 1200011–1200018 with permission from AIP Publishing); (C)–(E) solid heat transfer medium operation proposed by DLR: (C) process scheme where the particulate redox material (stream 2) is cycled between the reductionreactor (RR) and the oxidation-reactor (OR) (reprinted from Felinks J, Brendelberger S, Roeb M, Sattler C, Pitz-Paal R. Heat recovery concept for thermochemical processes using a solid heat transfer medium. Appl Therm Eng 2014;73:1004–11 with permission from Elsevier); (D) operating schematic of heat exchanger concept (reprinted from Felinks J, Brendelberger S, Roeb M, Sattler C, Pitz-Paal R. Heat recovery concept for thermochemical processes using a solid heat transfer medium. Appl Therm Eng 2014;73:1004–11 with permission from Elsevier); (E) scheme of the complete system (reprinted from Brendelberger S, Sattler C. Concept analysis of an indirect particle-based redox process for solar-driven H2O/ CO2 splitting. Solar Energy 2015;113:158–70 with permission from Elsevier); (F) solar thermal particle flow reactor proposed by UoC: an individual reduction/oxidation reactor unit, receiver configuration containing multiple individual reduction/oxidation reactor units (not in scale) and relevant “beam-up” receiver configuration. Reprinted from Muhich CL, Ehrhart BD, Al‐Shankiti I, et al., A review and perspective of efficient hydrogen generation via solar thermal water splitting, Wiley Interdiscip Rev: Energy and Environ 2015;5(3):261–87.

748

Solar Fuels

A comparison though with recently experimentally reported solar-to-fuel efficiencies [34] indicates that theoretical efficiencies are much higher than those practically achieved. This is due to the fact that the former are often made on hypothetical reactors under assumptions that are extremely difficult to be materialized in practice. For example, while obviously higher reduction temperatures lead to higher theoretical efficiencies, such temperatures are limited by the reactor construction materials and the drop of thermal and economic efficiency of solar collection as temperature increases. On the one hand, it is true that technical challenges in circulating packed or fluidized powder beds like high-temperature and thermally shock resistant reactor containment materials and flowable, attrition-resistant particles have been addressed in many industrial processes from where technology can be transferred, however, at lower temperature levels. On the other hand, the issue of different operating atmospheres between the reduction and the oxidation reactor has also to be resolved. The same holds true for particle–particle streams that have to exchange heat without exchanging gaseous oxygen-containing species between them (from the oxidation to the reduction chamber). This can imply intermediate storage and shift in operation atmosphere environment. Specifically with respect to multi-scale cascading pressure operation described above, overcoming the practical challenge of moving particle packed beds between a series of distinct chambers that maintain very different and very low pressures at very high temperatures has to be demonstrated experimentally. Currently such reactor concepts proposing the circulation and transport of hot solid particles between higher- and lowertemperature reactor regions with the aid of mechanical parts, sometimes in combination with vacuum conditions, have not been implemented even at a lab-scale single-stage reactor yet, let alone multistage cascades.

4.18.5.2.2

Structured reactors with moving parts: Rotary-type reactors

To address the same issue of heat recuperation toward the achievement of higher efficiencies, concepts based on rotating redox structures rather than flowing particles were also proposed. The research group from the University of Tokyo, Japan, introduced in 2006 a rotary-type reactor (Fig. 5(A)) in which a cylindrical rotor coated with redox pair materials is rotating between two chambers: in one chamber the WS reaction (H2-generation) is performed and in the other the TR reaction (O2-releasing) under solar irradiation [112]. Even though such reactors coated with CeO2 and Ni0.5Mn0.5Fe2O4 were tested first under IR irradiation [113] and a scaled-up version with 0.8CeO2–0.2ZrO2 under a solar simulator between 1200 and 15001C demonstrating cyclic H2 production without sintering of the redox material [114], there are no published results on further scale-up and testing. The group of UoM has proposed in 2012 another version of such a continuously operating, rotating-cylinder reactor, for production of syngas from WS/CDS. The basic idea involves heat recuperation from a rotating hollow cylinder of a porous reactive material to a counter-rotating inert solid cylinder via radiative transfer (Fig. 5(B)) [115]. The outer cylinder consists of a reactive porous medium and cycles between the reduction zone at high temperature and oxidation zone at low temperature. The inner cylinder is a chemically inert, heat recuperating solid. Heat transfer modeling studies predicted heat recovery effectiveness of over 50% with thin cylinder walls and long rotation periods; however, no actual implementation of such a reactor has been reported as yet. Also in 2006, the research group at SNL proposed their own concept of a rotating reactor, the so-called counter-rotating-ring receiver–reactor-recuperator (abbr. CR5) for producing hydrogen and oxygen from water [116,117], conceived to enhance heat recuperation. The key feature of the CR5 is a stack of counter-rotating rings or disks that are outfitted with fins around the circumference that are constructed of a redox metal oxide. SNL proposed combining WS and CDS with the CR5 reactor (Fig. 5(C)) into a project named “Sunshine to Petrol” (S2P), targeted to the production of “solar” hydrogen or of liquid synthetic combustible fuels (e.g., methanol, diesel, etc.) [118]. The bulk of the on-sun testing effort with the CR5 reactor was performed with thin ceria fins fabricated by a casting/lamination/laser cutting methodology. CDS operation with 4 and 8 ceria finned rotating rings was demonstrated successfully within a reduction temperature range from 1450 to 16201C. However, when the scaled-up version of 22 fins was tested, operation ceased shortly, mainly since several of the rings ceased to rotate due to cracking/separation of zirconia wedge segments at or near the metal/zirconia connection points [119,120]. 4.18.5.2.2.1 Current status of technology The implementation of efficient heat recuperation is still a major issue of concern. Many alternative solar reactor design and relevant simulations have predicted enhanced heat recuperation and reactor efficiency but when it comes to implementation, technically complicated concepts have not proved yet to have enough potential for eventual scale-up to commercially exploitable levels. To the best of the authors’ knowledge, none of the proposed and tested structured reactors that include moving parts from a hotter region to a colder one to enhance such recuperation has been successfully scaled-up so far. Problems with mechanical vibrations, thermal expansion, thermal shock resistance, inhomogeneous heating of rotating parts, and sealing at high temperatures are difficult to overcome and become fatal during prolonged operation: such issues have caused eventual damage of reactor parts in all cases. Such reactor concepts have not been advanced further experimentally in the open literature since 2008.

4.18.5.2.3

Structured reactors with nonmoving parts

Such reactors stem primarily from the traditional gas–solid catalytic chemical reactors, where ceramic porous supports, chemically inert with respect to the targeted reactions, are coated with a catalyst material capable to catalyze them. Thus, it is not surprising that the first uses of such reactors for solar-aided chemistry applications involved also catalytic CO2 DMR by Rh coated on honeycombs by WIS in 1989 [121,122] and on ceramic foams by SNL and DLR between 1987 and 1990 [123] in a 100-kW directly irradiated reactor on a solar dish. In 2006 the HYDROSOL research group (including among others the research group of Aerosol and Particle Technology/APTL, Greece and the present authors) has introduced the concept of monolithic, honeycomb solar reactors for performing redox pair cycles

Solar Fuels

749

Fig. 5 Operation principle schematic outlines of various rotating-type solar reactors for two-step splitting processes: (A) solar reactor of the University of Tokyo, Japan: schematic outlines of laboratory-scale version (left) and scaled-up version with 500 mm cylindrical rotor diameter (right) (reprinted with permission from Kaneko H, Miura T, Fuse A, et al., Rotary-type solar reactor for solar hydrogen production with two-step water splitting process. Energy & Fuels 2007;21:2287–93, Copyright (2007) American Chemical Society); (B) University of Minnesota: reactor design realizing a nonstoichiometric partial redox cycle with solid–solid heat recuperation. A counter-rotating cylinder of inert alumina positioned coaxially within the outer ceria cylinder (which cycles between the reduction zone at high temperature and oxidation zone at low temperature) provides heat recuperation (reprinted from Lapp J, Davidson JH, Lipiński W. Heat transfer analysis of a solid–solid heat recuperation system for solar-driven nonstoichiometric redox cycles. J Solar Energy Eng 2013;135:031004 with permission from ASME; (C) SANDIA’s Counter‐Rotating‐Ring Receiver Reactor Recuperator (CR5) for water/carbon dioxide splitting (WS/CDS)). © 2012 Sandia Corporation, reprinted from Diver RB, Miller JE, Allendorf MD, Siegel NP, Hogan RE. Solar thermochemical water-splitting ferrite-cycle heat engines. In: Proceedings of ISEC 2006 ASME international solar energy conference, Denver, Colorado; 2006, Miller JE, Allendorf MA, Ambrosini A, et al., Final Report, Reimagining liquid transportation fuels: sunshine to petrol. In: SANDIA Report Sandia National Laboratories, Albuquerque, New Mexico; 2012 with permission from ASME.

for the production of hydrogen from WS using solar energy [124]. The reactor consisted from radiation-absorbing silicon carbide (SiC) honeycombs coated with WS redox material, ferrites in the particular case. The issue of continuous production was resolved with a modular dual-chamber fixed honeycomb absorber implementation [125]. One part of modules splits water while the other is being regenerated; after completion of the reactions, the regenerated modules are switched to the splitting process and vice versa by switching the feed gas [126]. Such a modular, dual-chamber, ferrite-coated-honeycomb scaled up to the 100 kW level (Fig. 6(A)) was coupled on a solar tower facility (Plataforma Solar de Almeria, Spain – Fig. 6(B)) and achieved continuous solar-operated WS-TR cycles [127]. In such a facility, the different heat demands for the two process stages were realized not by moving the reactors, but by adjusting the

750

(A)

Solar Fuels

(B)

1

2

3

5 (C)

4

(D) Overhead trolleys Nitrogen outlet EMPOLI-Hydrosol reactor

SOLREF reactor with support structure

EMPOLI-Hydrosol reactor Reactor support structure and tumtable

Compensator

Water going to the condenser

Steam heat exhanger (W10)

Water coming from the evaporator Nitrogen heat exhanger (W10) Nitrogen coming from the tank

(E)

(F)

Fig. 6 The HYDROSOL solar reactors: (A) the 100 kWth-scale dual-chamber HYDROSOL reactor with nickel ferrite coated SiC honeycombs on the top of the PSA solar tower facility; (B) operation of the reactor coupled with the solar field (reprinted from de la Calle A, Roca L, Yebra LJ, Dormido S. Modeling of a two-step solar hydrogen production plant. Int J Hydrogen Energy 2012;37:10549–56 with permission from Elsevier); (C) view of the new domed HYDROSOL reactor design; (D) detailed design concept: 1. Secondary concentrator extension, 2. Quartz window, 3. Front flange, 4. Volumetric absorber, 5. Vessel; (E), (F) 3-reactors, 750-kW plant layout from the front and rear side, respectively. All reprinted from Säck J-P, Breuer S, Cotelli P, et al. High temperature hydrogen production: design of a 750 KW demonstration plant for a two step thermochemical cycle, Solar Energy, 2016;135:232–41, with permission from Elsevier.

flux density on each module when the status of the cycle is switched from regeneration to splitting and vice versa. This was achieved via partitioning the heliostat field and providing two “switchable” focal spots with independent power modulation [128]. The evolution of such solar receiver–reactors proceeded along this developmental path for some time, i.e., by depositing layers of redox oxide materials upon ceramic supports capable of absorbing the concentrated solar irradiation and developing the temperatures required for the TR step; examples include the work of the Niigata University group in Japan, later in cooperation with Inha University, Korea, using a larger NiFe2O4/m-ZrO2-coated foam with a 5-kWth dish concentrator [129]. As more and more experience was accumulated with such systems, it was at some point realized that, on the one hand, possible side reactions of

Solar Fuels

751

the redox coating with the support material could have an adverse effect on the desired reactions and that, on the other hand, the much larger thermal mass of the redox-inert support material had an adverse effect on the reactor’s thermal efficiency. In this perspective a self-supported, shaped, porous structure – for example, honeycomb, foam or fin- incorporating the maximum possible amount of a redox oxide in its structure instead of a thin coating layer and even better entirely made out of it, would introduce minimal thermal mass that is not directly involved with the reaction process into the reactor and consequently higher volumetric product yields and enhanced efficiency. In parallel to pursuing other approaches, the ETH/PSI group, collaborating initially with the group of Caltech, worked extensively on developing a solar reactor based on reticulated porous ceramic (RPC) foams manufactured entirely from the redox material – cerium oxide (CeO2) in the particular case – for thermochemical CDS. Actually this has occurred as a culmination of their work employing initially pellets, then porous cylinders, fibers and eventually foams made entirely of the particular redox material [23,130,131]. The evolution of their technology of ceria-based solar cavity reactors for solar-driven thermochemical production of fuels is depicted in Fig. 7 and described in several recent reviews [30,32]. The group has reported a peak solar-to-fuel efficiency of 3.53% at 16001C and an average efficiency of 1.73% for the ceria-foam-based reactor, stating that these were the highest solar-to-fuel energy conversion efficiency values reported to date for a solar-driven device converting CO2 to CO, and more than four times greater than previously reported values [130]. With the aim to increase the surface of the material, RPCs with dualscale porosity structures were produced by adding spherical carbon particles as templates for small pores to the CeO2 slurry from which the RPCs are produced [132]. Using these dual-scale RPCs, in a 4 kW receiver, oxygen evolution reached peak rates at a maximum temperature of 15751C. Interestingly, no difference in the rate of O2 evolution was observed between the “normal” mono-scale RPCs and the RPCs with dual-scale porosity. The solar-to-fuel energy conversion efficiency was 1.72%, without sensible heat recovery. A total of 291 stable redox cycles were performed with the dual-porosity foams, yielding 700 standard liters of syngas of composition 33.7% H2, 19.2% CO, 30.5% CO2, 0.06% O2, 0.09% CH4, and 16.5% Ar, which was compressed to 150 bar and further processed via Fischer–Tropsch synthesis to a mixture of naphtha, gasoil, and kerosene [133]. In parallel the UoM group shifted also from the rotating reactor of Fig. 5(B) to a nonmoving one containing the redox oxide (ceria, in the specific case) in the form of a packed bed. The details of this reactor are shown in the series of Fig. 8. The particular reactor is tailored for the isothermal, non-stoichiometric ceria cycle and is integrated with a heat exchanger made of reticulated ceramic foams. Functionally, the reactor comprises two fully integrated sections: a solar receiver/reactor cavity and the heat recovery section. The geometry of the receiver/reactor, including the cavity, fixed-bed reactive elements, and heat exchanger, was developed with the aid of computational models of the radiative exchange, chemical kinetics, and transport processes in the reactor [134,135] and evaluation of a prototype heat exchanger [136]. Concentrated sunlight enters the receiver/reactor cavity through a converging conical frustum and 48 mm diameter circular aperture. Within the cavity, solar radiation is distributed to six assemblies of coaxial dense alumina tubes (Fig. 8(B)). The annulus of each tube assembly is filled with 5 mm (length and diameter) cylindrical porous ceria particles formed of fibers, of a total mass of 3.2 kg (Fig. 8(C)). The overall bed void fraction is 45%. The tube assemblies extend beyond the solar cavity to the heat recovery section. Therein the inner tube and the annulus are filled with alumina RPC of fluid accessible porosity of 85–90% (Fig. 8(D)) to enhance radiative and conductive heat transfer [136,137]. The nominal 4 kWth prototype reactor is insulated with layers of porous ceramic and glass fiber insulation [138]. The whole assembly was tested for CDS via the isothermal ceria thermochemical redox cycle in a high-flux solar simulator (Fig. 8(E) and (F)). Images of the reactor in the solar simulator viewed from the aperture and from the rear where the gases enter and exit the reactor are shown in Fig. 8(E) and (F), respectively [71]. The redox cycle is implemented by alternating the flow of sweep gas and CO2 through each reactive element/heat exchanger assembly. During reduction, nitrogen is introduced to the center tube of each reactive element, flows through the inner tube, then reverses direction and flows over the ceria particles in the annulus. Heat is recovered from the product gases as they leave the reactive ceria bed. After 100 s, the gas flow was switched automatically to CO2 at the same flow rate. Fuel was produced continuously by operating half of the reactive elements in reduction and the other half in oxidation. The high-flux simulator was controlled to provide 4.4 kW. With this solar input, during steady-periodic operation the spatially and temporally averaged temperature of the surfaces of the reactive elements was E14701C. CO was produced continuously over 45 redox cycles, and up to 95% of the sensible heat of the process gases was recovered. Gases enter the heat exchangers at B251C and exit at B1401C (Fig. 8(G)), indicating that a large amount of thermal energy was maintained within the reactor and cycled between incoming and outgoing gases during operation [71]. The recovered heat represents 12 kW that otherwise would have to be provided by solar input. Further increase on fuel productivity by 75% was reported in a subsequent publication, by increasing the flow rate during oxidation and decreasing the flow of sweep gas during reduction to reduce the parasitic energy to produce nitrogen [138].

4.18.5.2.3.1 Current status of technology Since such reactors cannot provide for solid phase heat recuperation but only for gas phase between entering and exiting the reactors, their low efficiency remains their main problem. An overview of experimentally reported efficiencies for the ceria cycle, mainly from the ETH group is provided in Ref. [34]. They reported a peak solar-to-fuel efficiency of 3.53% at 16001C and an average efficiency of 1.73% for the ceria-foam-based reactor; however, there is concern that perhaps such values are still overoptimistic [139]. To these values, the ones reported recently by the UoM on their reactor above have to be added: for CDS the average solar-to-fuel efficiency without consideration of the energy cost of producing nitrogen was 1.64% whereas when accounting for all work input the efficiency was 0.72% [71].

752

Solar Fuels

(A)

O2/Ar

Syngas

Reduction Syngas

Solar reactor

Compressor

Fischer−Tropsch unit

Oxidation Liquid hydrocarbons

Ar

H 2O

CO2

High-flux solar simulator

Steam generator

(B)

a

b

Endothermic reduction step (O2 generation) Exothermic oxidation step (O2 generation)

Ceria RPC mm-sized pores

Quartz window

2000 μm Infiltrated strut

Concentrated solar radiation CO O2

200 μm μm-sized pores

(C)

CO2

Thermal insulation Gas-collection gap

20 μm

Solar Fuels

753

It is obvious that achieving the 20%-level target is not possible with the current material families and reactors employed. However, the importance of building and testing preindustrial solar plants to demonstrate the technologies set forth in acquiring and establishing industrial partnerships for further scale-up cannot be underestimated and in this respect cascades employing nonmoving porous structures are in principle scalable to any commercial-relevant level [140] due to their inherent modularity characteristics. In this perspective, the technology based on nonmoving porous structures manufactured to the highest possible extent out of the redox oxides themselves, having been so far demonstrated in pilot-scale level has proceeded to the next step in demonstration level coupled to real solar tower fields. Two such research projects are currently under way on a trans-European level, exploiting essentially this same concept, yet with different redox oxide systems: the HYDROSOL-PLANT and the SUN-to-LIQUID project. The HYDROSOL-PLANT Project (2013–2017), awarded through the Fuel Cells and Hydrogen Joint Initiative (FCH-JI) of the European Union is a culmination of the series of HYDROSOL Projects, described above. A new scaled-up version of the HYDROSOL reactor to the 750 kW level has been implemented based on lessons learned from successful operation of previous reactor concepts and designs. The rationale was to couple the solar reactor technology employed by DLR in the past in solar-aided reforming of methane at 9001C and 10 bar (REFOS and SOLREF Projects [141,142]), with the operating conditions of solar redox splitting, i.e., higher operating temperatures (up to 14001C), ambient pressure and cyclic operation mode. An optimization of the reactor shape has been carried out to reduce the quite high reradiation losses due to the high temperatures and the large exposed absorber surface area of the former 100-kW revealed by experiments and simulations [143]. A new reactor design has been implemented [144] where the overall shape of the absorber is close to a hemisphere and a suitable secondary reflector is included as well (Fig. 6(C) and (D)). These concepts ensure a more homogeneously distributed solar flux and therefore a more homogeneous temperature distribution. The cavity design ensures also that the thermal radiation is rather absorbed inside the reactor than emitted through the window since different parts of the absorber face each other instead of facing the environment. Following the approach in solar-aided reforming where the dome was made of solar-radiation-absorbing SiC foams coated with Rh-based catalysts, in the present case the dome consists of foams manufactured entirely of the redox material, nickel ferrite. The absorber structure has an elliptical shape to reduce the losses of the radiation emitted from the absorber to the environment: it has a tilted inlet ring and a concave outlet region formed by five parallel rings and one central element [145]. Each ring is formed by 18 parallel channels porous monoliths cut to form a roman arc structure, so that the monoliths cannot fall down into the cavity once assembled: the total volume of active material in a cavity is 95 L (Fig. 6). On the front and on the back of the reactor two flanges are mounted in which it is possible to place temperature and pressure sensors to control properly the temperature of the absorber and of the inlet and outlet streams. Furthermore, the whole reactor set-up and all components were designed in a way allowing easy maintenance and replacement of parts, in particular of the individual absorber monoliths.The reactor has a maximal diameter of 1100 mm and a length of about 1500 mm without the secondary concentrator and of 2450 mm with it. The secondary concentrator protects the frontal flange from the direct radiation coming from the heliostats, to use this spillage in the reactor instead of losing it, and to homogenize the solar radiation hitting the receiver window as much as possible. It has a dodecagon shape made by 12 trapezoidal metal sheets to form a kind of CPC: the diameter of the inscribed circumference of the dodecagon shape outlet is 560 mm. The window has a dome shape with a diameter of 652 mm, a length of 450 mm, and a thickness of 8 mm; it is assembled on a sealing ring and cooled by a nitrogen stream coming through it. The sealing effect is ensured by the pressure inside the reactor that pushes the window against the sealing ring placed on the front flange: this system has been developed by DLR for system with overpressure of at least 1 bar inside the reaction chamber. To meet a demonstration target of on-site hydrogen production 43 kg/week, employing nickel ferrite as the redox material which works optimally at 11001C for the WS step and at 14001C for the TR step, a design consisting of three reactors was selected as shown in Fig. 6(E) and (F). The plant is placed on two floors on the solar tower at the Plataforma Solar de Almeria: the floor for the reactors is at 26 m high; the second where the periphery components are placed, just underneath. To demonstrate quasicontinuous hydrogen production, since TR takes more time that splitting due to the slower kinetics, two reactors will be performing the TR step while one will be producing hydrogen. For the same reason each reactor is scheduled to spend twice as much time in the TR than in the WS step. Relevant mass flow rates are 10 kg/h for the steam and 200 kg/h for the nitrogen. The target is to achieve a temperature higher than 14001C on the absorber and lower than 10001C for the quartz window. Thermodynamic modeling and calculations have identified that the thermal input power of 750 kW should be enough to reach the target temperature on all the reactors: indeed, two reactors should operate simultaneously in the TR step, so a power around 400 kW should be required. The third reactor should be on the splitting step, which works at 3001C less than the TR one with a flow rate 20 times smaller: for these reasons, the required power is estimated to be lower than that of the TR step. Thus, the required solar

Fig. 7 Technology of ETH’s ceria-based solar cavity reactors for two-step, solar-driven thermochemical production of fuels: (A) typical fabricated CeO2 reticulated parts 20 mm thickness, 100 mm o.d. (reprinted with permission from Furler P, Scheffe J, Gorbar M, et al., Solar thermochemical CO2 splitting utilizing a reticulated porous ceria redox system. Energy & Fuels 2012;26:7051–9, Copyright (2012), American Chemical Society); (B) schematic of the experimental setup, featuring the main system components of the production chain to solar kerosene from H2O and CO2 (reprinted with permission from Marxer DA, Furler P, Scheffe JR, et al., Demonstration of the entire production chain to renewable kerosene via solar-thermochemical splitting of H2O and CO2. Energy & Fuels 2015;29(5):3241–50, Copyright (2015), American Chemical Society); (C) schematic and actual photographs of the solar reactor configuration with the cavity-receiver containing a ceria-made reticulated porous ceramic (RPC) structure with dual-scale porosity in the millimeter- and micrometer-scale. Reprinted from Marxer D, Furler P, Takacs M, Steinfeld A. Solar thermochemical splitting of CO2 into separate streams of CO and O2 with high selectivity, stability, conversion, and efficiency. Energy Environ Sci 2017;10:1142–9, with permission of main author.

Solar Fuels

754

Heat exchanger

From reactor

Packed bed of porous ceria

Insulation

To reactor

Cavity Aperture

Sunlight Reactive element (1 of 6)

Reactive element

(A)

Tube-in-tube counterflow HEX

(B)

Ceria packed bed

LHX

Alumina RPC

OD – 0.069 m

0.0031 m

Outlet

ta = 0.0096 m

Inlet

di = 0.038 m

Dense alumina tubes

Annulus Alumina felt Tube Alumina slurry

OD – 0.044 m

(C)

Qfual, HHV (W)

(D)

100

526

80

421

60

316

40

210

Measured

20

Prodected for optmized cycling

Temperature (K)

(E)

Temperature (K)

0

(F)

(G)

0

1780

Cavity wall average

1760 1740

105

Yield rate (ml min–1)

LHX

RE well average ±σ

1720 420 400 380 360 340 320 300 380 00:00

HX5

HX1

HX2

HX3 HX4

Inlets

00:30

HX6

01:00

01:30

02:00

02:30

Elapsed cycling time (hh:mm)

Fig. 8 Solar nonmoving thermochemical reactor integrated with a heat exchanger proposed by the University of Minnesota: (A) sketch of the integrated solar reactor/gas phase heat recovery heat exchanger not to scale (reprinted from Bala Chandran R, Davidson JH. Model of transport and chemical kinetics in a solar thermochemical reactor to split carbon dioxide. Chem Eng Sci 2016;146:302–15 with permission from Elsevier); (B) sketch of cross-sectional view of the prototype isothermal ceria redox reactor indicating key component locations (reprinted from Banerjee A, Bala Chandran R, Davidson JH. Experimental investigation of a reticulated porous alumina heat exchanger for high temperature gas heat recovery. Appl Therm Eng 2015;75:889–95 with permission from Elsevier); (C) detail sketch view of the portion of a reactive element within the reactor cavity (reprinted from Bala Chandran R, De Smith RM, Davidson JH. Model of an integrated solar thermochemical reactor/reticulated ceramic foam heat exchanger for gas-phase heat recovery. Int J Heat Mass Transf 2015;81:404–14 with permission from Elsevier); (D) front and angled view photographic images of the inlet of the heat exchanger (reprinted from Banerjee A, Bala Chandran R, Davidson JH. Experimental investigation of a reticulated porous alumina heat exchanger for high temperature gas heat recovery. Appl Therm Eng 2015;75:889–95 with permission from Elsevier); (E), (F) front- and rear-view photographs of the isothermal reactor, showing the cavity aperture and the gas connections to the heat exchangers and the high-flux solar simulator lamp array in the background, respectively (reprinted with permission from Hathaway BJ, Bala Chandran R, Gladen AC, Chase TR, Davidson JH. Demonstration of a solar reactor for carbon dioxide splitting via the isothermal ceria redox cycle and practical implications. Energy & Fuels 2016;30:6654–61, Copyright (2016), American Chemical Society); (G) steady-state performance of the 4.4 KW reactor for carbon dioxide splitting (CDS) via the isothermal ceria-based redox cycle: top: total fuel production, middle: spatial-averaged surface temperatures in the solar receiver/cavity, and bottom: gas temperatures at the inlet and outlets of the gas-phase heat exchangers (HX). Reprinted with permission from Hathaway BJ, Bala Chandran R, Gladen AC, Chase TR, Davidson JH. Demonstration of a solar reactor for carbon dioxide splitting via the isothermal ceria redox cycle and practical implications. Energy & Fuels 2016;30:6654–61, Copyright (2016), American Chemical Society.

Solar Fuels

755

power will be below 600 kW and the rest of the available power will be needed as a reserve for additional losses in all the system which is not taken into account in the model. For improving the overall plant efficiency a simplified heat recovery system has been developed, based on two heat exchangers built for temperatures up to 11001C and placed on the same floor to reduce the heat losses in the plant and the length of the pipes at high temperatures. These will operate as preheaters: one for each of the hydrogen and nitrogen path. Tests are scheduled in the first semester of 2017. In a similar approach the Sun-to-Liquid project, granted under the European Union Horizon 2020 initiative (2015–2019) is based on the extensive work of the ETH/PSI group with ceria-made reticulated porous structures, described above. Based on the success of the 4 kW solar reactor featuring dual scale RPC materials and experimentally tested inside the framework of the Solar-Jet project a new consortium was awarded the Sun-to-Liquid project aiming to demonstrate again the entire production chain of solarproduced liquid fuels but at the pre-commercial 50-kW scale and with record-high efficiency. The work involves the construction of an entirely new 50 kW solar pilot plant outside Madrid, Spain. Improvements to be incorporated therein include an optimized design that features the replacement of the CPC by secondary concentrator and a conical cavity resulting thus a more even flux distribution on the ceria RPC to avoid hot spots, an improved flow pattern of the purge gas that prevents backflow through the aperture and a better loading ratio of the cavity [146]. In the meantime, the 4 kW reactor containing an octagonal 25-mm-thick RPC structure made of pure ceria shown in Fig. 7(C) was further tested at the solar simulator facilities of ETH, Switzerland. Testing the reactor for five CDS cycles with reduction performed at 15001C under vacuum (total pressure 10 mbar) and oxidation in a transient mode between 1000 and 7501C under atmospheric pressure during cooldown from the reduction temperature without irradiating the reactor, the authors reported a new record of 5.25% solar-to-fuel energy efficiency [147]. Based on the same operating principles, i.e., under vacuum during reduction, and scheduled for deployment in 2017, the solar pilot plant will produce liquid fuels via Fischer–Tropsch synthesis of solar produced syngas. The success of such projects would mark a major step forward in the technology for the exploitation of solar radiation to produce fuels, being the first of that scale operating at such high temperatures with solar chemical reactors.

4.18.6

Results and Discussion

The first lessons learned so far from the various worldwide research approaches on WS/CDS via redox-oxide-pair-based TCs converge to performing the cycles below the melting point of the redox pair keeping it practically in the solid state throughout the process. The three state-of-the-art material families, ferrites, ceria, and perovskites operate in a similar manner and suffer from the same limitations imposed basically by the small width of the non-stoichiometry swing δ. Of course there are different “boundary conditions”: between the two most studied systems, ferrites and ceria, the former have demonstrated higher levels of reduction at lower temperatures and thus the higher TR temperatures of ceria necessitate the use of more special reactor materials. On the other hand, ceria is characterized by much faster gas splitting kinetics. Perovskites are characterized by high oxygen yield at moderately high temperatures but difficulties in reoxidation. However any such differences identified so far are not blatantly in favor or against a particular material family. Furthermore, given the extensive fundamental research on cations combination and doping performed so far, materials compositions with spectacularly improved performance within much different temperature ranges should not be expected, at least in the near future. With respect to the reactor type to be used, successful, cyclic, long-term redox operation under solar-irradiation conditions has so far been demonstrated only from reactors employing nonmoving porous structures manufactured to the highest possible extent out of the redox oxides. Such reactors are inherently of limited efficiency since they cannot implement effectively solid phase heat recuperation. However, awaiting the on-sun operation demonstration of spouted bed reactors or the lab-scale demonstration of reactors employing moving redox particle streams which will be naturally very welcome from the research and industrial community active in the field, it should be borne in mind that “technically simpler” concepts are in principle more attractive for largescale implementation and demonstration of any technology and in most cases a “trade-off” has to be made between theoretical targets and operation feasibility [32,71]. In such reactor concepts neither the redox oxide composition, for example, ferrites/ceria/perovskites, nor the structure itself, for example, honeycomb/foam, are so crucial for on-sun operation. Provided that design details relevant to the absorbance of solar irradiation like micro-, macro-porosity, and unit dimensions are optimized, the kind of the porous structure (honeycomb or foam) is not so crucial for solar operation but it has to be selected rather with ease-of-manufacture criteria since this modularly constructed “structured morphology” can be implemented with a variety of materials (e.g., ceria, ferrites, and perovskites). For example, a “domed” reactor like the one in Fig. 6(D) can be very well assembled from either foam or honeycomb modules [144]. It is equally obvious that the ceria foams of the reactor in Fig. 7(A) can be replaced with ferrite or perovskite honeycombs. It is rather expected that combinations of the three material families and the two porous geometries in reactors operating under the practically achievable conditions in a real solar plant would exhibit only marginal differences among them.

4.18.7

Future Directions

To reduce the currently unpractical high TR temperatures, perhaps processes alternative to thermal-only reduction have to be invoked [61]. Two such concepts can be chemically aided reduction with the addition of carbon containing species and

756

Solar Fuels

electrically aided (oxidation) reduction, i.e., electrolysis. Both these routes share many materials commonalities with the redox oxide pair-based TCs; these three technologies can together capitalize on the experience acquired so far in each one. Solar-aided incorporation of carbon species in the reaction mechanisms according to the well-known carbothermal reduction schemes, i.e., the reaction of an oxide with carbon or natural gas to produce the elementary metal has been proposed a long time ago [148]. It was extensively pursued in volatile redox cycles in the case of the carbothermal reduction of ZnO by the ETH/PSI group in cooperation with the Weizmann Institute of Science (WIS), Israel [149]. In the case of nonvolatile cycles such schemes can be performed in membrane reactor systems based on the so-called “mixed oxygen-ion and electron-conducting (MIEC)” materials, a notable example of which are perovskites. Such perovskite membrane reactors can be used in WS/ CDS as a means of simultaneous reaction and separation [150]. They can continuously remove oxygen product from the TR zone, shifting the reaction equilibrium to the right side, favoring product formation and achieving higher conversion. Such a function can be enhanced by introducing a carbon-containing species in the other side of the membrane. If natural gas (methane) is used as a reducing agent, then the partial oxidation of methane (POM) to syngas is combined, in a single process, with a chemically aided reduction of metal oxides at relatively low temperatures (750–10001C). For the “splitting” reactor side, among the various possible oxidants either the WS reaction (product H2) or the CO2 splitting reaction (product CO) or simultaneously both of them (co-splitting, product syngas) can be exploited. In this respect the two reactions, WS/CDS and either steam or DMR, represented by reactions (1) and (2), respectively, can be combined in a single reactor, producing simultaneously hydrogen and syngas [151]. The particular concept has the inherent advantage of being isothermal; however also requires elevated temperatures (of the order of 750–10001C depending on the perovskite’s composition), thus external heating, that can be provided by CSP. These temperatures are, however, significantly lower than the TR temperatures of state-ofthe art redox oxide materials currently employed at CSP-aided WS like mixed ferrites (TRE1350–14501C) or Ceria (TRE1450–16001C). Recently schemes involving POM with redox oxides have been proposed by UoM [152]. However, there is no apparent reason why such processes should be preferred over the well-established, CSP-driven methane reforming process [29]. These approaches fall within the broad category of so-called “hybrid redox cycles” where the TR step is complemented by a “chemical-reduction” one via carbon-containing species [152–154]. Such cycles exploit similar materials as well as solar concentration technologies; however, they can be performed under much milder conditions. These cycles belong to the socalled “open-loop TCs” since they employ feedstocks additional to water/carbon dioxide (carbon-containing compounds like methane) that are consumed and not recycled. Alternatively the reduction of the metal oxides, as the first step for WS/CDS, can be aided by supplying electrical energy, through the application of an external potential at the opposite sides of a dense oxygen-ion conducting membrane. The general scheme of the reactor is similar to that of the membrane reactor described above; however, in this case no fuel addition is required and the dense membrane is a pure ionic conductor (e.g., YSZ or doped-CeO 2), not conducting electrons, thus an external electrical circuit is required. The reactor is known as a “high-temperature solid oxide electrolysis cell (SOEC)” and can be used to split steam, CO2 or steam/CO2 mixtures to produce H2, CO, or syngas, respectively. Porous composites made of lanthanum-doped strontium manganite and yttria stabilized zirconia (LSM-YSZ) are commonly used as O 2 electrodes. However, recent research efforts have shown that this ceramic–ceramic composite can be favorably replaced by single-phase materials exhibiting MIEC like perovskite materials with an oxygen under-stoichiometry, such as LSCF (La1-xSrxCoyFe1-yO3-d) or LSC (La1-xSrxCoO3-d) [155]. Although no products based on solid oxide electrolysis (SOE) technology are available, the concept has been proven by development and operation of short stacks. Researchers active in the field claim potential to significantly reduce costs and increase efficiencies and anticipate commercially availability potential by 2020. In this perspective SOECs can be a viable integration in the emerging sector of so-called “power to gas” (P2G) technologies where excess electricity is converted into hydrogen by water electrolysis. Electrolyzers are being tested in pilot stations for integration between renewable electricity generation and the production of alternative energy carriers such as hydrogen or synthetic methane, which ultimately enable greater utilization of renewable power. Globally about 50 such demo plants have been realized or are in the planning stage, and more recent projects are often larger than 1 MW of electrolyzer electrical load [156]. In most such power-to-gas pilot plants, wind or solar energy is used to generate electricity and in this respect CSP systems can be employed to produce the necessary (solar thermal) electricity in addition to hydroelectric. Current P2G projects commonly integrate alkaline or proton exchange membrane (PEM) electrolyzers for hydrogen generation due to the maturity of this technology. Solid oxide electrolyzers operate at significantly higher temperatures than alkaline electrolyzers, typically 500–8501C, which though are still much lower than those needed for thermal-only reduction. Technical advantages of SOE commonly claimed by researchers and developers are the potential of steam/CO2 co-electrolysis producing syngas as well as a potentially higher electrical system efficiency compared to low temperature technologies, as a significant share of the energy input can be provided in the form of heat. Electrolysis and membrane technologies share common features with solar redox processes: they all involve the composition optimization and the development of bulk, porous oxide structures that perform cyclic redox operations for extended periods of time. Naturally they also share technical problems associated with such operation, for instance the “chemical expansion” issue that all such materials exhibit, i.e., permanent volume changes induced by repetitive redox cycles [157,158]. In this respect they can mutually benefit from research on improving durability at higher current densities/operation temperatures and mitigation of performance degradation via combined optimization of composition microstructure and porosity. Solar reactors based on such compositions and structures can be employed as preindustrial test bench facilities to identify such problems and produce relevant solutions.

Solar Fuels

4.18.8

757

Closing Remarks

The acknowledgment of the fact that the experience and technology accumulated with solar-aided, two-step, redox-pair-based WS TCs for hydrogen production could be “transferred” to CDS and essentially culminate to the synthesis of liquid hydrocarbons from solar energy, water, and (waste) carbon dioxide, has created many aspirations and research efforts worldwide. However despite significant progress during the last years, solar fuels production from such solar-aided, WS/CDS TCs, even though having been already successfully demonstrated at bench- and pilot-scale, is still facing significant technical challenges and still has a notable way to go for potential commercial exploitation. Technical barriers have to do both with the redox materials’ chemistry as well as the solar energy exploitation issues. The two main research tasks dealt with are, on the one hand, integrated heat recovery schemes and, on the other hand, solving the main material-related issues and providing the right functional materials at reasonable costs. Research efforts during the last 30 years seem to converge to some conclusions. Despite the high energy conversion efficiencies predicted as achievable from a wealth of thermodynamic modeling studies, efficiencies actually achieved experimentally are lower. This is not only due to the operating temperature range requirements of the available state-of-the-art materials but also due to the fact that reactor and heat exchange concepts proposed in most such modeling studies involving solid-phase heat recuperation between redox-based moving parts or particle streams achieved at high temperatures and vacuum conditions have been proved challenging to be realized in practice. Currently it seems that the technical solutions based on reactors without high-temperature moving parts, incorporating the maximum possible redox material quantity per volume and integrating at the time being the most efficient schemes of (only) gasphase heat recovery, seem to offer the easiest way to scale-up beyond the lab-scale level. Although possibilities to improve on the efficiency of such reactors are limited, a significant progress in such solar reactor design has been made. Such preindustrial scale solar reactor pilot plants have been demonstrated at as high as the 300 kW power level and already scheduled to reach 750 kW. Valuable lessons can be learned from such an on-sun operation especially concerning the potential hybridization of such cycles with fossil-fuels like methane in similar solar-aided processes and reactor designs. These routes are thought of as a process option for a transition period leading from fossil fuel-based solar-fuels to such produced only by renewable resources. Considering that electrolysis using solar photovoltaic or CSP produced electricity is most likely the best benchmark technology so far for the production of such solar fuels, research should proceed in parallel, given the materials and structural commonalities and long-term redox operation requirements. Solutions to such issues will decisively help solar thermal processes to achieve the role of significantly contributors through carbon-lean to eventually carbon-free and sustainable hydrogen and syngas production on large scale.

Acknowledgments The authors gratefully acknowledge partial support of this work through DLR’s Programmdirektion Energie (PD-E) Project “Thermochemical storage for CSP-applications based on Redox-Reactions – from materials to processes (REDOXSTORE),” the Initiative and Networking Fund of the Helmholtz Association of German Research Centers (HGF) within the Virtual Institute SolarSynGas (Contract Number VH-VI-509) and EU’s FP7 project STAGE-STE “Scientific and Technological Alliance for Guaranteeing the European Excellence in Concentrating Solar Thermal Energy,” Grant agreement no: 609837.

References [1] Francis W, Peters MC. Fuels and fuel technology: a summarized manual. Amsterdam: Elsevier; 2013. [2] Graves C, Ebbesen SD, Mogensen M, Lackner KS. Sustainable hydrocarbon fuels by recycling CO2 and H2O with renewable or nuclear energy. Renew Sustain Energy Rev 2011;15:1–23. [3] Probstein RF, Hicks RE. Synthetic fuels. Mineola, NY: Dover Publications Inc.; 2006. [4] Takeshita T, Yamaji K. Important roles of Fischer–Tropsch synfuels in the global energy future. Energy Policy 2008;36:2773–84. [5] Simbolotti G. Hydrogen production & distribution, IEA Energy Technology Essentials, IEA; 2007. [6] Bertuccioli L, Chan A, Hart D, et al., Development of water electrolysis in the European Union. Final Report, fuel cells and hydrogen joint undertaking; 2014. [7] Rostrup-Nielsen JR, Sehested J, Nørskov JK. Hydrogen and synthesis gas by steam – and CO2 reforming. Adv Catal 2002;65–139. [8] Trainham JA, Newman J, Bonino CA, Hoertz PG, Akunuri N. Whither solar fuels? Curr Opin Chem Eng 2012;1:204–10. [9] International Energy Agency OECD/IEA. Technology roadmap: solar thermal electricity; 2014. [10] I.E. Agency. Technology roadmap: concentrating solar power. International Energy Agency, OECD/IEA; 2010. [11] Steinfeld A. Solar thermochemical production of hydrogen – a review. Solar Energy 2005;78:603–15. [12] Romero M, Steinfeld A. Concentrating solar thermal power and thermochemical fuels. Energy Environ Sci 2012;5:9234. [13] Hinkley J, Hayward J, McNaughton R, Edwards J, Lovegrove K. Concentrating solar fuels roadmap Final Report; 2016. [14] Joshi AS, Dincer I, Reddy BV. Solar hydrogen production: a comparative performance assessment. Int J Hydrogen Energy 2011;36:11246–57. [15] von Storch H, Roeb M, Stadler H, et al. On the assessment of renewable industrial processes: case study for solar co-production of methanol and power. Appl Energy 2016;183:121–32. [16] Dry ME. High quality diesel via the Fischer–Tropsch process – a review. J Chem Technol Biotechnol 2002;77:43–50. [17] Möller S, Kaucic D, Sattler C. Hydrogen production by solar reforming of natural gas: a comparison study of two possible process configurations. J Solar Energy Eng 2006;128:16–23. [18] Piatkowski N, Wieckert C, Weimer AW, Steinfeld A. Solar-driven gasification of carbonaceous feedstock – a review. Energy Environ Sci 2011;4:73–82.

758 [19] [20] [21] [22] [23] [24] [25] [26] [27] [28] [29] [30] [31] [32] [33] [34] [35] [36] [37] [38] [39] [40] [41] [42] [43] [44] [45] [46] [47] [48] [49] [50] [51] [52] [53] [54] [55] [56] [57] [58] [59] [60] [61] [62] [63] [64] [65] [66] [67] [68] [69]

Solar Fuels Miller JE. Initial case for splitting carbon dioxide to carbon monoxide and oxygen, Sandia Report SAND2007-8012; 2007. Chueh WC, Haile SM. Ceria as a thermochemical reaction medium for selectively generating syngas or methane from H2O and CO2. ChemSusChem 2009;2:735–9. Steinfeld A. Solar thermochemical production of hydrogen – a review. Solar Energy 2005;78:603–15. Kodama T, Gokon N. Thermochernical cycles for high-temperature solar hydrogen production. Chem Rev 2007;107:4048–77. Chueh WC, Falter C, Abbott M, et al. High-flux solar-driven thermochemical dissociation of CO2 and H2O using nonstoichiometric ceria. Science 2010;330:1797–801. Roeb M, Neises M, Monnerie N, et al. Materials-related aspects of thermochemical water and carbon dioxide splitting: a review. Materials 2012;5:2015–54. Call F, Roeb M, Schmücker M, et al. Thermogravimetric analysis of zirconia-doped ceria for thermochemical production of solar fuel. Am J Anal Chem 2013;4:37–45. Centi G, Perathoner S. Towards solar fuels from water and CO2. ChemSusChem 2010;3:195–208. Trommer D, Noembrini F, Fasciana M, et al. Hydrogen production by steam-gasification of petroleum coke using concentrated solar power – I. Thermodynamic and kinetic analyses. Int J Hydrogen Energy 2005;30:605–18. Piatkowski N, Wieckert C, Weimer AW, Steinfeld A. Solar-driven gasification of carbonaceous feedstock – a review. Energy Environ Sci 2011;4:73–82. Agrafiotis C, von Storch H, Roeb M, Sattler C. Solar thermal reforming of methane feedstocks for hydrogen and syngas production – a review. Renew Sust Energy Rev 2014;29:656–82. Agrafiotis C, Roeb M, Sattler C. A review on solar thermal syngas production via redox pair-based water/carbon dioxide splitting thermochemical cycles. Renew Sustain Energy Rev 2015;42:254–85. Muhich CL, Ehrhart BD, Al‐Shankiti I, et al. A review and perspective of efficient hydrogen generation via solar thermal water splitting. Wiley Interdiscip Rev: Energy Environ 2015;5(3):261–87. Koepf E, Alxneit I, Wieckert C, Meier A. A review of high temperature solar driven reactor technology: 25 years of experience in research and development at the Paul Scherrer Institute. Appl Energy 2017;188:620–51. Villafán-Vidales H, Arancibia-Bulnes C, Riveros-Rosas D, Romero-Paredes H, Estrada C. An overview of the solar thermochemical processes for hydrogen and syngas production: reactors, and facilities. Renew Sustain Energy Rev 2016;75:894–908. Yadav D, Banerjee R. A review of solar thermochemical processes. Renew Sustain Energy Rev 2016;54:497–532. Nakamura T. Hydrogen production from water utilizing solar heat at high temperatures. Solar Energy 1977;19:467–75. Chueh WC, Haile SM. A thermochemical study of ceria: exploiting an old material for new modes of energy conversion and CO2 mitigation. Philos Trans R Soc A: Math, Phys Eng Sci 2010;368:3269–94. McDaniel AH. Renewable energy carriers derived from concentrating solar power and nonstoichiometric oxides. Curr Opin Green Sustain Chem 2017;4:37–43. Lundberg M. Model calculations on some feasible two-step water splitting processes. Int J Hydrogen Energy 1993;18:369–76. Allendorf MD, Diver RB, Siegel NP, Miller JE. Two-step water splitting using mixed-metal ferrites: thermodynamic analysis and characterization of synthesized materials. Energy & Fuels 2008;22:4115–24. Tamaura Y, Steinfeld A, Kuhn P, Ehrensberger K. Production of solar hydrogen by a novel, 2-step, water-splitting thermochemical cycle. Energy 1995;20:325–30. Meredig B, Wolverton C. First-principles thermodynamic framework for the evaluation of thermochemical H2O – or CO2 – splitting materials. Phys Rev B 2009;80. doi:10.1103/PhysRevB.83.239901. Panlener RJ, Blumenthal RN, Garnier JE. A thermodynamic study of nonstoichiometric cerium dioxide. J Phys Chem Solids 1975;36:1213–22. Scheffe JR, Welte M, Steinfeld A. Thermal reduction of ceria within an aerosol reactor for H2O and CO2 splitting. Ind Eng Chem Res 2014;53:2175–82. Hao Y, Yang C-K, Haile SM. High-temperature isothermal chemical cycling for solar-driven fuel production. Phys Chem Chem Phys 2013;15:17084–92. Miller JE, McDaniel AH, Allendorf MD. Considerations in the design of materials for solar-driven fuel production using metal-oxide thermochemical cycles. Adv Energy Mater 2014;4:1300469. Agrafiotis CC, Pagkoura C, Zygogianni A, et al. Hydrogen production via solar-aided water splitting thermochemical cycles: combustion synthesis and preliminary evaluation of spinel redox-pair materials. Int J Hydrogen Energy 2012;37:8964–80. Dimitrakis D, Tsongidis N, Konstandopoulos A. Reduction enthalpy and charge distribution of substituted ferrites and doped ceria for thermochemical water and carbon dioxide splitting with DFT þ U. Phys Chem Chem Phys 2016;18:23587–95. Kodama T, Nakamuro Y, Mizuno T. A two-step thermochemical water splitting by iron-oxide on stabilized zirconia. J Solar Energy Eng 2006;128:3–7. Scheffe JR, McDaniel AH, Allendorf MD, Weimer AW. Kinetics and mechanism of solar-thermochemical H2 production by oxidation of a cobalt ferrite–zirconia composite. Energy Environ Sci 2013;963–73. Gokon N, Mizuno T, Nakamuro Y, Kodama T. Iron-containing yttria-stabilized zirconia system for two-step thermochemical water splitting J Solar Energy Eng 2008;130:011011–6 011018. Abanades S, Legal A, Cordier A, et al. Investigation of reactive cerium-based oxides for H2 production by thermochemical two-step water-splitting. J Mater Sci 2010;45:4163–73. Trovarelli A, Fornasiero P. Catalysis by ceria and related materials. Singapore: World Scientific Publishing Co. Pte. Ltd.; 2013. Scheffe JR, Weibel D, Steinfeld A. Lanthanum–strontium–manganese perovskites as redox materials for solar thermochemical splitting of H2O and CO2. Energy & Fuels 2013;27:4250–7. McDaniel AH, Miller EC, Arifin D, et al. Sr-and Mn-doped LaAlO3 δ for solar thermochemical H2 and CO production. Energy Environ Sci 2013;6:2424–8. Jiang Q, Tong J, Zhou G, et al. Thermochemical CO2 splitting reaction with supported LaxA1 xFeyB1 yO3 (A ¼ Sr, Ce, B¼ Co, Mn) perovskite oxides. Solar Energy 2014;103:425–37. Scheffe JR, Li J, Weimer AW. A spinel ferrite/hercynite water-splitting redox cycle. Int J Hydrogen Energy 2010;35:3333–40. Arifin D, Aston VJ, Liang X, McDaniel AH, Weimer AW. CoFe2O4 on a porous Al2O3 nanostructure for solar thermochemical CO2 splitting. Energy Environ Sci 2012;5:9438–43. Muhich CL, Evanko BW, Weston KC, et al. Efficient generation of H2 by splitting water with an isothermal redox cycle. Science 2013;341:540–2. Perkins C, Weimer AW. Solar-thermal production of renewable hydrogen. AIChE J 2009;55:286–93. Xiao L, Wu S-Y, Li Y-R. Advances in solar hydrogen production via two-step water-splitting thermochemical cycles based on metal redox reactions. Renew Energy 2012;41:1–12. U.S.D. Partnership. Hydrogen production technical team roadmap. Available from: https://energy.gov/eere/vehicles/downloads/us-drive-hydrogen-production-technicalteam-roadmap; 2013. Ávila-Marín AL. Volumetric receivers in solar thermal power plants with central receiver system technology: a review. Solar Energy 2011;85:891–910. Ho CK, Iverson BD. Review of high-temperature central receiver designs for concentrating solar power. Renew Sustain Energy Rev 2014;29:835–46. Heck RM, Farrauto RJ. Catalytic air pollution control: commercial technology. New York, NY: Van Nostrand Reinhold; 1995. Geus JW, Van Giezen JC. Monoliths in catalytic oxidation. Catal Today 1999;47:169–80. Cybulski A, Moulijn JA. Structured catalysts and reactors. Boca Raton, FL: CRC Press; 2005. Twigg MV, Richardson JT. Fundamentals and applications of structured ceramic foam catalysts. Ind Eng Chem Res 2007;46:4166–77. Roeb M, Sattler C. Isothermal water splitting. Science 2013;341:470–1. Siegel NP, Miller JE, Ermanoski I, Diver RB, Stechel EB. Factors affecting the efficiency of solar driven metal oxide thermochemical cycles. Ind Eng Chem Res 2013;52:3276–86.

Solar Fuels

759

[70] U.S. Department of Energy. Fuel cell technologies office: multi-year research, development, and demonstration plan. Planned program activities for 2011–2020. Available from: https://energy.gov/eere/fuelcells/downloads/fuel-cell-technologies-office-multi-year-research-development-and-22; 2012. [71] Hathaway BJ, Bala Chandran R, Gladen AC, Chase TR, Davidson JH. Demonstration of a solar reactor for carbon dioxide splitting via the isothermal ceria redox cycle and practical implications. Energy & Fuels 2016;30:6654–61. [72] Bader R, Venstrom LJ, Davidson JH, Lipin´ski W. Thermodynamic analysis of isothermal redox cycling of ceria for solar fuel production. Energy & Fuels 2013;27:5533–44. [73] Ermanoski I, Miller J, Allendorf M. Efficiency maximization in solar-thermochemical fuel production: challenging the concept of isothermal water splitting. Phys Chem Chem Phys 2014;16:8418–27. [74] Charvin AS, Flamant P, Lemort F. G. Two-step water splitting thermochemical cycle based on iron oxide redox pair for solar hydrogen production. Energy 2007;32:1124–33. [75] Lange M, Roeb M, Sattler C, Pitz-Paal R. T–S diagram efficiency analysis of two-step thermochemical cycles for solar water splitting under various process conditions. Energy 2014;67:298–308. [76] Steinfeld A. Thermochemical production of syngas using concentrated solar energy. Begell House Inc.Annu Rev Heat Transf 2012;; 2012. p. 255–75. [77] Bilgen E, Ducarroir M, Foex M, Sibieude F. Use of solar energy for direct and two-step water decomposition cycles. Int J Hydrogen Energy 1977;2:251–7. [78] Gaĺ vez ME, Loutzenhiser PG, Hischier I, Steinfeld A. CO2 splitting via two-step solar thermochemical cycles with Zn/ZnO and FeO/Fe3O4 redox reactions: thermodynamic analysis. Energy & Fuels 2008;22:3544–50. [79] Abanades S, Charvin P, Flamant G, Neveu P. Screening of water-splitting thermochemical cycles potentially attractive for hydrogen production by concentrated solar energy. Energy 2006;31:2805–22. [80] Steinfeld A. Solar hydrogen production via a two-step water splitting thermochemical cycle based on Zn/ZnO redox reactions. Int J Hydrogen Energy 2002;27:611–9. [81] Loutzenhiser PG, Steinfeld A. Solar syngas production from CO2 and H2O in a two-step thermochemical cycle via Zn/ZnO redox reactions: thermodynamic cycle analysis. Int J Hydrogen Energy 2011;36:12141–7. [82] Abanades S, Charvin P, Lemort F, Flamant G. Novel two-step SnO2/SnO water-splitting cycle for solar thermochemical production of hydrogen. Int J Hydrogen Energy 2008;33:6021–30. [83] Chambon M, Abanades S, Flamant G. Kinetic investigation of hydrogen generation from hydrolysis of SnO and Zn solar nanopowders. Int J Hydrogen Energy 2009;34:5326–36. [84] Haueter P, Moeller S, Palumbo R, Steinfeld A. The production of zinc by thermal dissociation of zinc oxide – solar chemical reactor design. Solar Energy 1999;67:161–7. [85] Loutzenhiser PG, Meier A, Steinfeld A. Review of the two-step H2O/CO2-splitting solar thermochemical cycle based on Zn/ZnO redox reactions. Materials 2010;3:4922–38. [86] Schunk LO, Haeberling P, Wepf S, Meier A, Steinfeld A. A receiver–reactor for the solar thermal dissociation of zinc oxide. J Solar Energy Eng 2008;130. [87] Chambon M, Abanades S, Flamant G. Design of a lab-scale rotary cavity-type solar reactor for continuous thermal dissociation of volatile oxides under reduced pressure. J Solar Energy Eng 2010;132:021006–7. [88] Moller S, Palumbo R. The development of a solar chemical reactor for the direct thermal dissociation of zinc oxide. J Solar Energy Eng 2001;123:83–90. [89] Chambon M, Abanades S, Flamant G. Thermal dissociation of compressed ZnO and SnO2 powders in a moving-front solar thermochemical reactor. AIChE J 2011;57:2264–73. [90] Koepf E, Advani SG, Steinfeld A, Prasad AK. A novel beam-down, gravity-fed, solar thermochemical receiver/reactor for direct solid particle decomposition: design, modeling, and experimentation. Int J Hydrogen Energy 2012;37:16871–87. [91] Stamatiou A, Steinfeld A, Jovanovic ZR. On the effect of the presence of solid diluents during Zn oxidation by CO2. Ind Eng Chem Res 2013;52:1859–69. [92] Villasmil W, Brkic M, Wuillemin D, Meier A, Steinfeld A. Pilot scale demonstration of a 100-kWth solar thermochemical plant for the thermal dissociation of ZnO. J Solar Energy Eng 2014;136:011016. [93] Koepf E, Villasmil W, Meier A. Pilot-scale solar reactor operation and characterization for fuel production via the Zn/ZnO thermochemical cycle. Appl Energy 2016;165:1004–23. [94] Kodama T, Enomoto S-I, Hatamachi T, Gokon N. Application of an internally circulating fluidized bed for windowed solar chemical reactor with direct irradiation of reacting particles. J Solar Energy Eng 2008;130:014504. [95] Gokon N, Mizuno T, Takahashi S, Kodama T. A two-step water splitting with ferrite particles and its new reactor concept using an internally circulating fluidized-bed. In: ASME 2006 international solar energy conference, vol. 1; 2006. p. 205–214. [96] Gokon N, Takahashi S, Yamamoto H, Kodama T. New solar water-splitting reactor with ferrite particles in an internally circulating fluidized bed. J Solar Energy Eng 2009;131:011007–9. [97] Gokon N, Mataga T, Kondo N, Kodama T. Thermochemical two-step water splitting by internally circulating fluidized bed of NiFe2O4 particles: successive reaction of thermal-reduction and water-decomposition steps. Int J Hydrogen Energy 2011;36:4757–67. [98] Gokon N, Takahashi S, Yamamoto H, Kodama T. Thermochemical two-step water-splitting reactor with internally circulating fluidized bed for thermal reduction of ferrite particles. Int J Hydrogen Energy 2008;33:2189–99. [99] Kodama T, Gokon N, Cho HS, et al., Particles fluidized bed receiver/reactor with a beam-down solar concentrating optics: 30-kWth performance test using a big sun-simulator, In: AIP conference proceedings, AIP Publishing; 2016. p. 120004. [100] Kodama T, Gokon N, Matsubara K, et al. Flux measurement of a new beam-down solar concentrating system in Miyazaki for demonstration of thermochemical water splitting reactors. Energy Proc 2014;49:1990–8. [101] Ermanoski I, Siegel NP, Stechel EB. A new reactor concept for efficient solar-thermochemical fuel production. J Solar Energy Eng 2013;135:031002. [102] Ermanoski I, Grobbel J, Singh A, et al., Design and construction of a cascading pressure reactor prototype for solar-thermochemical hydrogen production. In: SolarPACES 2015 AIP conference proceedings, 1734; 2016. p. 1200011–1200018. [103] Felinks J, Brendelberger S, Roeb M, Sattler C, Pitz-Paal R. Heat recovery concept for thermochemical processes using a solid heat transfer medium. Appl Therm Eng 2014;73:1004–11. [104] Brendelberger S, Sattler C. Concept analysis of an indirect particle-based redox process for solar-driven H2O/CO2 splitting. Solar Energy 2015;113:158–70. [105] Felinks J, Richter S, Lachmann B, et al. Particle-particle heat transfer coefficient in a binary packed bed of alumina and zirconia-ceria particles. Appl Therm Eng 2016; doi:10.1016/j.applthermaleng.2016.01.066. [106] Ermanoski I, Miller JE, Allendorf MD. Efficiency maximization in solar-thermochemical fuel production: challenging the concept of isothermal water splitting. Phys Chem Chem Phys 2014;16:8418–27. [107] Krenzke PT, Davidson JH. On the efficiency of solar H2 and CO production via the thermochemical cerium oxide redox cycle: the option of inert-swept reduction. Energy Fuels 2015;29:1045–54. [108] Brendelberger S, Roeb M, Lange M, Sattler C. Counter flow sweep gas demand for the ceria redox cycle. Solar Energy 2015;122:1011–22. [109] Jarrett C, Chueh W, Yuan C, et al. Critical limitations on the efficiency of two-step thermochemical cycles. Solar Energy 2016;123:57–73. [110] Ehrhart BD, Muhich CL, Al-Shankiti I, Weimer AW. System efficiency for two-step metal oxide solar thermochemical hydrogen production – Part 1: thermodynamic model and impact of oxidation kinetics. Int J Hydrogen Energy 2016;41:19881–93.

760

Solar Fuels

[111] Ehrhart BD, Muhich CL, Al-Shankiti I, Weimer AW. System efficiency for two-step metal oxide solar thermochemical hydrogen production – Part 2: impact of gas heat recuperation and separation temperatures. Int J Hydrogen Energy 2016;41:19894–903. [112] Kaneko H, Fuse A, Miura T, Ishihara H, Tamaura Y. Two-step water splitting with concentrated solar heat using rotrary-type reactor. In: 13th solar PACES international symposium, Seville, Spain; 2006. [113] Kaneko H, Miura T, Fuse A, et al. Rotary-type solar reactor for solar hydrogen production with two-step water splitting process. Energy & Fuels 2007;21:2287–93. [114] Kaneko H, Lee C-I, Ishihara T, et al., Solar H2 production with rotary-type solar reactor in international collaborative development between Tokyo Tech (Japan) and CSIRO (Australia). In: 15th solar PACES international symposium, Berlin, Germany; 2009. [115] Lapp J, Davidson JH, Lipin´ski W. Heat transfer analysis of a solid–solid heat recuperation system for solar-driven nonstoichiometric redox cycles. J Solar Energy Eng 2013;135:031004. [116] Diver RB, Miller JE, Allendorf MD, Siegel NP, Hogan RE. Solar thermochemical water-splitting ferrite-cycle heat engines. In: Proceedings of ISEC 2006 ASME international solar energy conference, Denver, Colorado; 2006. [117] Miller JE, Evans LR, Stuecker JN, et al., Materials development for the CR5 solar thermochemical heat engine. In: Proceedings of ISEC2006 ASME international solar energy conference, Denver, CO; 2006. [118] Kim J, Miller JE, Maravelias CT, Stechel EB. Comparative analysis of environmental impact of S2P (sunshine to petrol) system for transportation fuel production. Appl Energy 2013;111:1089–98. [119] Miller JE, Allendorf MA, Ambrosini A, et al., Final Report, Reimagining liquid transportation fuels: sunshine to petrol. In: SANDIA Report Sandia National Laboratories, Albuquerque, New Mexico; 2012. [120] Miller JE, Allendorf MA, Ambrosini A, et al., Development and assessment of solar-thermal activated fuel production: Phase 1 Summary. In: Sandia Report, Albuquerque, New Mexico: Sandia National Laboratories; 2012. [121] Levy M, Rosin H, Levitan R. Chemical reactions in a solar furnace by direct solar irradiation of the catalyst. J Solar Energy Eng 1989;111:96–7. [122] Levy M, Rubin R, Rosin H, Levitan R. Methane reforming by direct solar irradiation of the catalyst. Energy 1992;17:749–56. [123] Buck R, Muir JF, Hogan RE. Carbon dioxide reforming of methane in a solar volumetric receiver/reactor: the CAESAR project. Solar Energy Mater 1991;24:449–63. [124] Agrafiotis C, Roeb M, Konstandopoulos AG, et al. Solar water splitting for hydrogen production with monolithic reactors. Solar Energy 2005;79:409–21. [125] Roeb M, Monnerie N, Schmitz M, et al., Thermo-chemical production of hydrogen from water by metal oxides fixed on ceramic substrates. In: Proceedings of the 16th world hydrogen energy conference, Lyon, France; 2006. [126] Roeb M, Sattler C, Klüser R, et al. Solar hydrogen production by a two-step cycle based on mixed iron oxides. J Solar Energy Eng 2006;128:125–33. [127] Roeb M, Säck JP, Rietbrock P, et al. Test operation of a 100 kW pilot plant for solar hydrogen production from water on a solar tower. Solar Energy 2011;85: 634–644. [128] Roeb M, Neises M, Säck J-P, et al. Operational strategy of a two-step thermochemical process for solar hydrogen production. Int J Hydrogen Energy 2009;34: 4537–4545. [129] Gokon N, Kodama T, Imaizumi N, Umeda J, Seo T. Ferrite/zirconia-coated foam device prepared by spin coating for solar demonstration of thermochemical watersplitting. Int J Hydrogen Energy 2011;36:2014–28. [130] Furler P, Scheffe J, Gorbar M, et al. Solar thermochemical CO2 splitting utilizing a reticulated porous ceria redox system. Energy & Fuels 2012;26:7051–9. [131] Furler P, Scheffe JR, Steinfeld A. Syngas production by simultaneous splitting of H2O and CO2 via ceria redox reactions in a high-temperature solar reactor. Energ Environ Sci 2012;5:6098–103. [132] Furler P, Scheffe J, Marxer D, et al. Thermochemical CO2 splitting via redox cycling of ceria reticulated foam structures with dual-scale porosities. Phys Chem Chem Phys 2014;16:10503–11. [133] Marxer DA, Furler P, Scheffe JR, et al. Demonstration of the entire production chain to renewable kerosene via solar-thermochemical splitting of H2O and CO2. Energy & Fuels 2015;29(5):3241–50. [134] Bala Chandran R, Davidson JH. Model of transport and chemical kinetics in a solar thermochemical reactor to split carbon dioxide. Chem Eng Sci 2016;146: 302–315. [135] Bader R, Bala Chandran R, Venstrom LJ, et al. Design of a solar reactor to split CO2 via isothermal redox cycling of ceria J Solar Energy Eng 2015;137:031007 031007. [136] Banerjee A, Bala Chandran R, Davidson JH. Experimental investigation of a reticulated porous alumina heat exchanger for high temperature gas heat recovery. Appl Therm Eng 2015;75:889–95. [137] Bala Chandran R, De Smith RM, Davidson JH. Model of an integrated solar thermochemical reactor/reticulated ceramic foam heat exchanger for gas-phase heat recovery. Int J Heat Mass Transf 2015;81:404–14. [138] Hathaway BJ, Chandran RB, Sedler S, et al. Effect of flow rates on operation of a solar thermochemical reactor for splitting CO2 via the isothermal ceria redox cycle. J Solar Energy Eng 2016;138:011007. [139] Rager T. Re-evaluation of the efficiency of a ceria-based thermochemical cycle for solar fuel generation. Chem Commun 2012;48:10520–2. [140] Graf D, Monnerie N, Roeb M, Schmitz M, Sattler C. Economic comparison of solar hydrogen generation by means of thermochemical cycles and electrolysis. Int J Hydrogen Energy 2008;33:4511–9. [141] Möller S, Friedmann S, Walter M, Dam J. SOLREF – development of an advanced solar high-temperature reformer. In: Proceedings of ISEC2006: ASME international solar energy conference, Denver, CO; 2006. [142] Buck R, Brauning T, Denk T, et al. Solar-hybrid gas turbine-based power tower systems (REFOS). J Solar Energy Eng 2002;124:2–9. [143] Neises M, Goehring F, Roeb M, Sattler C, Pitz-Paal R. Simulation of a solar receiver–reactor for hydrogen production. In: ASME conference proceedings, 2009; 2009. p. 295–304. [144] Houaijia A, Sattler C, Roeb M, et al. Analysis and improvement of a high-efficiency solar cavity reactor design for a two-step thermochemical cycle for solar hydrogen production from water. Solar Energy 2013;97:26–38. [145] Säck J-P, Breuer S, Cotelli P, et al. High temperature hydrogen production: design of a 750 KW demonstration plant for a two step thermochemical cycle. Solar Energy 2016;135:232–41. [146] Furler P, Steinfeld A. Heat transfer and fluid flow analysis of a 4 kW solar thermochemical reactor for ceria redox cycling. Chem Eng Sci 2015;137:373–83. [147] Marxer D, Furler P, Takacs M, Steinfeld A. Solar thermochemical splitting of CO2 into separate streams of CO and O2 with high selectivity, stability, conversion, and efficiency. Energy Environ Sci 2017;10:1142–9. [148] Steinfeld A, Kuhn P, Reller A, et al. Solar-processed metals as clean energy carriers and water-splitters. Int J Hydrogen Energy 1998;23:767–74. [149] Wieckert C, Frommherz U, Kräupl S, et al. A 300 kW solar chemical pilot plant for the carbothermic production of zinc. J Solar Energy Eng 2007;129:190–6. [150] Evdou A, Zaspalis V, Nalbandian L. La(1 x)SrxMnO3 δ perovskites as redox materials for the production of high purity hydrogen. Int J Hydrogen Energy 2008;33:5554–62. [151] Nalbandian L, Evdou A, Zaspalis V. La1 xSrxMyFe1 yO3 δ perovskites as oxygen-carrier materials for chemical-looping reforming. Int J Hydrogen Energy 2011;36:6657–70. [152] Krenzke PT, Davidson JH. Thermodynamic analysis of syngas production via the solar thermochemical cerium oxide redox cycle with methane-driven reduction. Energy & Fuels 2014;28:4088–95. [153] He F, Trainham J, Parsons G, Newman JS, Li F. A hybrid solar-redox scheme for liquid fuel and hydrogen coproduction. Energy Environ Sci 2014;7:2033–42.

Solar Fuels

761

[154] Sheu EJ, Ghoniem AF. Redox reforming based, integrated solar-natural gas plants: reforming and thermodynamic cycle efficiency. Int J Hydrogen Energy 2014;39:14817–33. [155] Sapountzi FM, Gracia JM, Weststrate CJ, Fredriksson HOA, Niemantsverdriet JW. Electrocatalysts for the generation of hydrogen, oxygen and synthesis gas. Prog Energy Combust Sci 2017;58:1–35. [156] Gahleitner G. Hydrogen from renewable electricity: an international review of power-to-gas pilot plants for stationary applications. Int J Hydrogen Energy 2013;38:2039–61. [157] Atkinson A, Ramos T. Chemically-induced stresses in ceramic oxygen ion-conducting membranes. Solid State Ion 2000;129:259–69. [158] Knoblauch N, Simon H, Schmücker M. Chemically induced volume change of CeO2 δ and nonstoichiometric phases. Solid State Ion 2017;301:43–52.

Further Reading Blanco M, Ramirez Santigosa L, editors. 2017. Advances in concentrating solar thermal research and technologyA volume in Woodhead Publishing Series in Energy, Elsevier Science & Technology Duxford: Woodhead Publishing; 2017. Goswami DY, Kreith F, Kreider JF. Principles of solar engineering. second ed. Philadelphia: Taylor & Francis; 2000. Graves C, Ebbesen SD, Mogensen M, Lackner KS. Sustainable hydrocarbon fuels by recycling CO2 and H2O with renewable or nuclear energy. Renew Sustain Energy Rev 2011;15:1–23. Kodama T, Gokon N. Thermochernical cycles for high-temperature solar hydrogen production. Chem Rev 2007;107:4048–77. Meredig B, Wolverton C. First-principles thermodynamic framework for the evaluation of thermochemical H2O – or CO2 – splitting materials Phys Rev B 2009;80.245119-1-8. Pitz-Paal R, Buck R, Heller P, Hirsch T, Steinmann W-D. Solar thermal power production. In: Stolten D, Scherer V, editors. Transition to renewable energy systems. Weinheim, Germany: Wiley-VCH Verlag GmbH & Co. KGaA; 2013. p. 307–38. Roeb M, Neises M, Monnerie N, Sattler C, Pitz-Paal R. Technologies and trends in solar power and fuels. Energy Environ Sci 2011;4:2503–11. Stechel EB, Miller JE. Re-energizing CO2 to fuels with the sun: issues of efficiency, scale, and economics. J CO2 Util 2013;1:28–36. Steinfeld A. Thermochemical production of syngas using concentrated solar energy. Begell House Inc Annu Rev Heat Transf 2012;; 2012. p. 255–75.

Relevant Websites http://www.dlr.de/sf/en/desktopdefault.aspx/tabid-9386/15915_read-39194/ DLR Institute of Solar Reserach. https://energy.gov/eere/sunshot/sunshot-initiative ENERGY.GOV. http://www.iea.org/ International Energy Agency. https://www.nrel.gov/csp/solarpaces/ NREL. http://sfera.sollab.eu/index.php?page=home SFERA. http://www.solarpaces.org/ SolarPACES.

4.19 PV-Based Energy Conversion Systems Ibrahim Dincer and Yusuf Bicer, University of Ontario Institute of Technology, Oshawa, ON, Canada r 2018 Elsevier Inc. All rights reserved.

763 765 766 768 769 769 770 770 771 773 773 774 774 776 776 777 780 781 782 783 783 783 784 788 790 791 792 792 792 793

4.19.1 Introduction 4.19.2 Systems 4.19.2.1 Solar Photovoltaic 4.19.2.1.1 Crystalline silicon 4.19.2.1.2 Thin films 4.19.2.1.3 Optimum bandgaps for solar cells 4.19.2.1.4 Current–voltage characteristics 4.19.2.1.5 Solar cells losses 4.19.2.2 Solar Thermal Systems 4.19.2.2.1 Passive solar heating 4.19.2.2.2 Flat plate collectors 4.19.2.2.3 Evacuated tube collectors 4.19.2.2.4 Parabolic troughs 4.19.2.2.5 Parabolic dishes 4.19.2.3 Solar Photovoltaic and Thermal Systems 4.19.2.4 Concentrated Photovoltaic Systems 4.19.2.4.1 Optics 4.19.2.4.2 Temperature effect on concentrated photovoltaic performance 4.19.2.4.3 Sun tracking and control 4.19.3 Analyses and Assessment 4.19.3.1 Spectral Distribution Modeling 4.19.3.2 System Advisor Model 4.19.3.3 Photonic Calculations 4.19.3.4 Thermodynamic Conversion Efficiencies 4.19.4 Future Directions 4.19.5 Closing Remarks Acknowledgment References Further Reading Relevant Websites

Nomenclature A Al C c c E_ e e Eg _ Ex ex FF h hc I I J J

762

2

Area (m ) Spectral absorbance Concentration factor Photonic constant (mK) Speed of light (3  108 m/s) Energy rate (W) Charge of an electron (1.60217657  1019 C) Solar elevation Bandgap (eV) Exergy rate (W) Specific exergy (J/kg) Fill factor Planck’s constant (6.62606957  10 34 m2kg/S) Heat transfer coefficient (W/m2 K) Current (A) Irradiance (W/m2) Current density (A/m2) Current density (mA/cm2)

k k kt n P PV _ Q R Rs S_ ST STo s T T U V v _ W

Boltzmann constant (1.3806488  1023 J/K) Extinction coefficient Thermal conductivity (W/mK) Refraction index Power (W) Photovoltaic Heat transfer rate (W) Reflectance Internal series resistance of PV cell Entropy rate (W/K) Global solar radiation (W/m2) Total amount of normal radiation (W/m2) Specific entropy (J/kg K) Transmittance Temperature (K) Overall heat transfer coefficient (W/m2 K) Voltage (V) Wind speed (m/s) Work rate (W)

Comprehensive Energy Systems, Volume 4

doi:10.1016/B978-0-12-809597-3.00430-2

PV-Based Energy Conversion Systems

Zenith angle

DG

Gibbs free energy change (J/mol)

Greek Letters y Incident angle e Emissivity factor Z Efficiency l Wavelength

ξc ξs p F

Étendue of total converter emission Étendue of the sun Pi number Spectral quantum efficiency

Acronyms AC AM AOD BAPV BIPV BOS CIGS CIS CoC CPC CPV CSP CTE DC DNI HTF

IEC LMTD NIR NREL PCM PMMA POE PV PV/T PW SAM SDK SMARTS SOE SOG STE

International electrotechnical commission Logarithmic mean temperature difference Near infrared National Renewable Energy Laboratory Phase change materials Polymethyl methacrylate Primary optical element Photovoltaics Photovoltaic/thermal Precipitable water System advisor model Software development kit Simple model of the atmospheric radiative transfer of sunshine Secondary optical element Silicon on glass Solar thermal electricity

mpp oc ov pce ph POA r rad rev s s sc SC sh tot waf x

Maximum power point Open circuit Overall Power conversion efficiency Photon Plane of array Receiver Radiation Reversible Serial Sun Short circuit Solar constant Shunt Total Wafer Reservoir

z

Subscripts 1 a abs act b c cas d D diss g h in l m max min

4.19.1

Alternative current Air mass Aerosol optical depth Building-adapted photovoltaic Building-integrated photovoltaic Balance of system Copper–indium–gallium–(Di) selenide Copper–indium–(Di) selenide Cell-on-carrier Compound parabolic collector Concentrated photovoltaic Concentrated solar power Coefficient of thermal expansion Direct current Direct normal irradiance Heat transfer fluid

and Superscripts Ambient condition Aperture Absorbed Actual Blackbody Cell Casing Destruction Diode Dissipation Gap High Input Low Maximum Maximum Minimum

763

Introduction

Solar energy is the most abundant source of renewables in the world. There are numerous pathways for utilization of solar energy ranging from solar collectors to concentrated photovoltaic (CPV) applications. This section provides background information for photovoltaics (PV), photovoltaic and thermal (PV/T), and CPV systems by explaining the working principle of the technologies. Solar radiation and its spectrum, intensity, and exergy are introduced. PV systems are explained. Concentrated solar collectors that generate high-temperature heat are discussed, and some methods to store solar thermal energy at high-temperature are briefly mentioned.

764

PV-Based Energy Conversion Systems

2.5

Iλ, etr

1

Iλ (W/m2nm)

Iλ, dc

0.1 Iλ, diff

Iλ, gt

0.01

0.001 250

500

1000

2000

4000

 (nm) Fig. 1 The reference spectrum for solar irradiation based on ASTM 1.5. Data from American Society for Testing and Materials (ASTM). Terrestrial reference spectra for photovoltaic performance evaluation. Solar spectral irradiance: air mass 1.5. Available from: http://rredc.nrel.gov/solar/spectra/ am1.5/; 2017 [accessed 17.01.17].

Solar light is an electromagnetic radiation of wavelength spectrum ranging from ultraviolet (100 nm) to far infrared (1 mm). Actually, the ultraviolet-C (UVC) spectrum, comprising shortest wavelengths from 100 to 280 nm, is almost negligible in the total amount of sunlight falling on the light surface. With respect to energy rate, the most sunlight is in the visible light spectrum (380–780 nm), with a 44% energy fraction. The rest of the energy content of sunlight on the earth is comprised of 4% ultraviolet A and B (UVA and UVB), from 380 to 280 nm, and 52% infrared (IR), covering the long wavelength range from 780 to 1 mm. However, the light intensity in the infrared-C (IRC) sub-spectrum from 3 to 1 mm is negligible. The solar light spectrum is shown in Fig. 1, based on the reference standard. The reference solar spectrum is as a chart that expresses the variation of spectral irradiance (measured in W/m2 nm) with the wavelength. The spectrum has four irradiation components as shown in Fig. 1: extraterrestrial Il,etr, global on a 37 degree tilt south-facing surface Il,gt, direct normal and circumsolar Il,dc, and diffuse radiation Il,diff. This reference spectrum corresponds to a zenith angle of 48.2 degree where the solar zenith angle is the angle between the local vertical and the direction of the sun. The extraterrestrial radiation intensity (measured in W/m2) corresponds to the light intensity at the upper edge of the atmosphere and is obtained by integration of the extraterrestrial spectral irradiance over the whole spectrum of wavelengths. The presence of the atmosphere attenuates the solar radiation intensity due to various aspects, such as albedo, atmospheric absorption, and scattering. Due to scattering, an observer on the surface of the earth sees sunlight from two sources: the direct and circumsolar radiation with a blue-yellow color which shows that the peak spectrum is at about 550 nm, and the sky radiation (or diffuse radiation) with blue color, with a peak around 450 nm as shown in Fig. 1. The air spectra can be predicted according to the methodology adopted by National Renewable Energy Laboratory (NREL) [1] and it can be calculated with the help of the software simple model of the atmospheric radiative transfer of sunshine (SMARTS), described in Gueymard [2]. Besides the air mass (AM), the solar spectrum depends on the water content and ozone in the atmosphere, and also on turbidity, aerosol types and concentration, cloudiness, haziness, and optical thickness of the atmosphere. Direct radiation is obtained directly from the solar disk which is viewed at an angle of 5 degree. The direct radiation has two portions: the direct beam which is the radiation of the solar disk itself viewed at an angle of 0.53 degree, and the circumsolar radiation which is related to the ring around the sun covering the angular region from 0.53 to 5 degrees. The diffuse component, which is the light coming indirectly to the observer, is more intense when AM is higher. In general the diffuse radiation is only 10% of global radiation, the rest being the direct and circumsolar components. One of the important aspects of utilizing solar energy is the conversion of light into other forms of energy which are more easily accessible. In principle, solar energy can be converted into thermal energy, electricity, and chemical energy. Here, some insights into the mechanisms of light interaction with matter, which are encountered in light energy conversion processes are introduced. In physics, the notion of “matter” refers to any substance that occupies space and possesses rest mass. However, light has no rest mass. In a vacuum it propagates with a speed equal to the speed of light, given by the constant c. When light passes through transparent matter (e.g., the earth’s atmosphere), the speed of light is reduced according to the refractive index defined with n¼c/v, where v is the speed of light propagation through matter. As the refractive index of the atmosphere is about 1.0003, the speed of light in the terrestrial atmosphere is about 299,700,000 m/s. This is a simple example, showing that matter interacts with light through refraction. Other known matter–light interactions are reflection, absorption, and emission. Max Planck discovered in 1901 that light (or very high-frequency electromagnetic radiation) can be absorbed or emitted

PV-Based Energy Conversion Systems

765

in quanta of energy which are proportional to frequency. Using such a phenomenon, Planck solved the “ultraviolet catastrophe,” that is, the impossibility of explaining the blackbody radiation spectrum using the classical theory expectation based on a continuous mode oscillator model. The blackbody concept emerged in 1860, with Kirchhoff, Stefan, Boltzmann, and Wien being the main contributors. The blackbody model consists of an ideal absorber in the form of a cavity with a pinhole. Light that enters through the pinhole is entrapped in the cavity and never escapes; rather, it is thermalized. Similarly, light is emitted from the cavity. Early discoveries showed that the emitted energy rate is proportional to the fourth power of the temperature. Spectroscopes were invented at that time and light irradiance measured at every wavelength. It was observed that spectral irradiance has a maximum that, according to the Wien law, depends on temperature only [3]. Obviously, solar electric power generation can be applied to a broad range of applications. Solar generators can operate either stand-alone or as grid-connected systems for electricity generation and other useful commodities such as hydrogen. One remarkable application is to use solar electricity to drive electrolyzers for hydrogen generation. Water irrigation systems with electricity generated by PV panels to drive pumps became familiar in recent decades. Other applications of PV electricity are for highway signaling, remote located traffic indicators, and many other remote systems or aerospace applications. Thermoelectric concentrated solar generators are of medium to large-scale. Concentrated solar power system (CSP) using heat engines appear to be an emerging technology that is still being improved to obtain commercially available systems. Concentrated solar power generators are also found to be an attractive option for satellites and space missions, in which they operate outside the terrestrial atmosphere. Two important advantages of solar electricity are reducing pollution and mitigating the release of CO2. It is predicted that solar electric systems will proliferate in future years. The carbon dioxide mitigation can be estimated based on the installed electric power production capacity that replaces fossil fuel power plants. One principal characteristic of solar radiation is that it embeds two kinds of useful energies in it: light (or photonic radiation) and heat (or thermal radiation). It is known that the infrared spectrum of the solar radiation is considered as a form of heat. When solar radiation is used to generate electricity, a part of the harvested energy is lost and converted into heat. It makes good sense to generate electricity and heat from solar radiation. In this way, much better solar energy utilization is achieved than with systems that generate only electricity or heat. Moreover, it is possible to generate more products than heat and electricity from solar radiation with only one system. Electricity, high-temperature heat, low-temperature heat, refrigeration, hydrogen, oxygen, synthetic fuels, and chemicals can be generated simultaneously or in various combinations using solar energy [4]. Solar energy is an excellent resource to supply high-temperature thermal energy to heat engine systems for cogeneration of power and heating. One relevant advantage of such cogeneration system comes from the opportunity to recover the rejected heat by the heat engine with minimal losses. The design of the system offers the possibility of applying good thermal insulation around it. In fact, the system may have a point or line focus solar concentrator, characterized by reduced thermal and optical losses (of 5%–20% in total). Furthermore, the heat engine can be enclosed in an insulated box, forcing it to deliver the ejected heat only to the heat transfer fluid (HTF). Thus at the level of the heat engine, a very small amount of heat is lost (it can be lower than 1%). Next, the storage of hot water is made at a reasonably low-temperature (about 30–951C), a fact that facilitates the application of good, inexpensive thermal insulation for reducing the heat leakage (it may be another 1%–2% from the solar heat). Hence, the solar energy utilization in such a system for heat and power cogeneration can be over 80% [4].

4.19.2

Systems

In classification of the solar energy systems, we can employ the following approach. Light interacts with matter mainly in three ways: (1) it displaces electrons producing photovoltaic electricity, (2) it displaces electrons that release vibronic energy that dissipates into heat, generating heat, and (3) it displaces electrons, which eventually generates electro-chemical reactions to produce synthetic fuels (hydrogen, ammonia, methanol, ethanol, etc.) that store chemical energy convertible into power ondemand. Hence, electric or mechanical power can be obtained from solar energy in many ways. Fig. 2 gives a classification of solar power generation systems. Only the systems that directly produce electricity or mechanical shaft power are included in the classification. These are of two types: PV systems (which directly produce electrical power) and photo thermal systems that generate heat which is used as a heat source for a specific heat engine to run a turbine/expander and to generate mechanical shaft power; this is eventually converted into electrical power using an electrical generator. As the solar energy is intermittent, suitable means of energy storage are required. Three types of storage methods are mainly used for solar energy. These are: (1) storage of generated power in electrical batteries, (2) thermal storage of heat generated photo-thermally, and (3) conversion of solar energy to chemical fuels for storage and on-demand power generation with the help of power generating systems such as fuel cell. One of the heat engine options is Stirling engines which operate at very high pressures, on the order of 200 bar and temperatures in the range of 700–8001C, working with helium or hydrogen. Hydrogen is highly flammable, which imposes severe safety issues. A drawback with these systems is that hydrogen and helium leak easily, which raises maintenance problems. However, Stirling systems are very compact and reach high engine efficiency of around 40%, leading to overall electricity production efficiency of 22%–23% for 10 h/day operation and installed capacity of 10–25 kW. One of the main drawbacks of using Stirling engines in solar applications is related to the long warm-up time needed, which is in contradiction with the reality of solar energy’s fluctuating nature. Here, we introduce the three main categories which are PV systems, PV/T systems, and CPV systems.

766

PV-Based Energy Conversion Systems

Solar power generation systems

Solar thermal systems

Photovoltaic systems

Non-concentrating

Concentrating (C-PV)

Low temperature