Prospects and problems of concentrating solar power technologies for power generation in the desert regions

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Renewable and Sustainable Energy Reviews 53 (2016) 1106–1131

Contents lists available at ScienceDirect

Renewable and Sustainable Energy Reviews journal homepage: www.elsevier.com/locate/rser

Prospects and problems of concentrating solar power technologies for power generation in the desert regions Xinhai Xu a,b, K. Vignarooban c, Ben Xu d, K. Hsu a, A.M. Kannan a,n a

The Polytechnic School, Ira A. Fulton Schools of Engineering, Arizona State University, Mesa, AZ 85212, USA School of Mechanical Engineering and Automation, Harbin Institute of Technology Shenzhen Graduate School, Shenzhen, Guangdong 518055, China c Department of Physics, Faculty of Science, University of Jaffna, Jaffna 40000, Sri Lanka d Department of Aerospace and Mechanical Engineering, The University of Arizona, Tucson, AZ 85721, USA b

art ic l e i nf o

a b s t r a c t

Article history: Received 2 February 2015 Received in revised form 15 July 2015 Accepted 16 September 2015 Available online 10 November 2015

Concentrated solar power plants (CSPs) are gaining momentum due to their potential of power generation throughout the day for base load applications in the desert regions with extremely high direct normal irradiance (DNI). Among various types of the CSPs, solar tower power technologies are becoming the front runners especially in the United States and around the world with the possibility to compete with traditional power generation technologies in terms of efﬁciency and levelized cost of electricity (LCOE). A bibliometric analysis of the publications on the CSP systems and components since 1990 shows a total of 6400 þ publications and reveals an exponential growth due to reasons that CSP systems promises a lot of potential as the future large scale power source for varied applications. This review consolidates the beneﬁts and challenges of the CSP technologies particularly in the desert regions. Thorough literature analysis as well as the meteorological data projects the trend that the CSP systems would become a reality in the Middle East and North Africa (MENA), Australia, Southwestern region of the United States, Southwestern part of China and China/Mongolia border with high direct normal irradiance. However, enormous amount of support and capital investments are needed for making these CSP systems realistic as there is not much power grid network in existence. It is evident that there are multiple challenges speciﬁcally in water consumption, materials design and development for the optimum heat transfer ﬂuid, thermal energy storage and receiver subsystems in addition to commercial viability and environmental impacts. Each of the challenges is discussed in detail and suggestions are made to address the challenges. & 2015 Elsevier Ltd. All rights reserved.

Keywords: Concentrating solar power Levelized cost of electricity Direct normal irradiance Heat transfer ﬂuids Thermal energy storage Operational maintenance

Contents 1. 2.

3.

n

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1107 CSP in desert regions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1108 2.1. Overview of CSP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1108 2.2. CSP in Southwest of the United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1108 2.3. CSP in Spain . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1113 2.4. CSP in MENA (Middle East and North Africa) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1113 2.4.1. North African countries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1113 2.4.2. DESERTEC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1113 2.5. CSP in Australia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1113 2.6. CSP in China and Mongolia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1114 2.6.1. China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1114 2.6.2. GOBITEC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1115 2.7. CSP in India . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1115 Technical challenges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1116

Corresponding author. Tel.: þ 1 480 727 1102. E-mail address: [email protected] (A.M. Kannan).

http://dx.doi.org/10.1016/j.rser.2015.09.015 1364-0321/& 2015 Elsevier Ltd. All rights reserved.

X. Xu et al. / Renewable and Sustainable Energy Reviews 53 (2016) 1106–1131

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3.1.

Water consumption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1116 3.1.1. Dry cooling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1116 3.1.2. Dust cleaning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1116 3.1.3. CSP-desalination cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1117 3.2. Heat transfer ﬂuid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1118 3.3. Thermal energy storage (TES) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1118 3.3.1. Thermocline system. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1119 3.3.2. Sensible heat storage system (SHSS). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1119 3.3.3. Latent heat storage system (LHSS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1120 3.3.4. Combined system and cascade latent heat storage system (CLHSS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1121 3.3.5. Sizing strategies and cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1122 3.4. Heat receiver . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1122 3.4.1. Receiver system conﬁguration. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1122 3.4.2. High-temperature photothermal absorber materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1124 3.5. Environmental impacts and commercial viability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1125 4. Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1126 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1126

1. Introduction Dearth of electrical energy as well as environmental pollution are two of the most critical challenges our society faces in recent years, especially in the developing countries. According to International Energy Agency's (IEA) World Energy Outlook 2013, global energy demand will increase by one third from 2011 to 2035, and energy-related CO2 emission will rise by 20% to 37.2 Gtonne [1]. In this context, the study and application of renewable and sustainable energy becomes urgent. Among various types of renewable energy sources, solar energy is promising due to its large energy potential and clean nature. As a simple estimation, the energy from the sun to the earth in 1 h is 4.3 1011 GJ, which is more than the total energy consumed globally in 2001 (4.1 1011 GJ) [2]. However, the solar energy received by the planet is not evenly distributed [3]; major desert regions in the world have the highest potential for solar energy because of high Direct Normal Irradiance (DNI) [4]. The solar energy received by the worldwide desert regions within 6 h is roughly estimated more than the energy consumed by humankind in a year [5]. To put it another way, electricity produced by covering 1% of the area of the Sahara desert with solar thermal plants is enough for the world annual power consumption [6]. Fig. 1 shows the solar energy received by desert regions in the Middle East and North Africa (MENA), Spain, Australia, Southwestern of the United States, Southwestern of

China, border of China and Mongolia, and India with highest DNI (41800 kW h/m2/y) compared to other areas in the world. Besides extensive exposure to sunlight, the desert regions also have mostly sunny weather with quite low rain precipitation, low population density and large land availability, which enable the possibility of large scale solar energy projects [7]. Currently concentrating solar power (CSP) and solar photovoltaic (PV) are the two main technologies to utilize solar energy. CSP system uses mirrors or lenses to concentrate energy in sunlight and then employs a heat transfer ﬂuid (HTF) to transport the heat to turbines for power production. PV directly converts solar energy to electricity using solar cells [8]. The disadvantage of PV cell is its efﬁciency decreases as ambient temperature increases [9]. Power production in cloudy days and at night is also a problem. However, thermal energy storage (TES) system can be integrated with CSP systems to deliver dispatchable power on demands regardless the time or weather conditions. Incorporation of TES with CSP signiﬁcantly adds value of the system in regards with energy and grid services. Moreover, CSP system is more suitable for large scale applications (4100 MW) because it generates electrical power using conventional turbines [7]. A bibliometric analysis of the publications on concentrating solar power systems, sub-systems and components since 1990 has been carried out. The data were based on the online version of the Web of Science Core Collection. “Concentrating solar power” was

Fig. 1. Solar annual direct normal irradiation (DNI) across the world (unit: kW h/m2/year) (SolarGIS © 2015 GeoModel Solar).

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X. Xu et al. / Renewable and Sustainable Energy Reviews 53 (2016) 1106–1131

greenhouse gas (GHG) emissions by 2050 compared to that in 1990 [14]. Therefore CSP technology is strongly supported by the EU governments because of its clean nature [15]. With the aim to assess the potential technical challenges related to CSP in desert regions, the following questions are discussed in detail in the subsequent sections: What is the current status of CSP in desert regions? What technical challenges does the CSP technology have in the long term? Can the water availability issue in semi-arid and arid regions be resolved? What are the advantages of molten-salt HTFs? What is the status of heat receiver development? Is TES a mature technology so far? What are the commercial viability and environmental impact of CSP installation in the long term?.

2. CSP in desert regions Fig. 2. Bibliometric analysis of the publications on CSP related topics along with cumulative CSP systems installed on annual basis.

Fig. 3. Various CSP technologies along with their installed ratios.

used as keywords to search and the number of publications in the past 25 years (Fig. 2) clearly reveals that there is a signiﬁcant and unprecedented growth of research around the world on the CSP areas. Even though the CSP related research was evident from the early 90s, the number of publications was only around 100 per year up to the year 2005. However, the number of publications jumped to 4700 every year after 2010 indicating the interest and funding support from various agencies. As seen from Fig. 2, the installed capacity of the CSP systems stands above 2500 MW with more additional capacity after 2010. At present, Spain and the United States are the only two countries with signiﬁcant installed CSP capacity with respectively about 57.9% and 40.1% of the total 1220 MW installed CSP capacity in the world in 2011 [10]. The global CSP installed capacity increased more than 600 MW within two years from 604 MW in 2009 [11]. The United States used to be the only major player until 2007 when Spain joined the CSP market. The energy supply security is a critical factor for Spain to build CSP plants. Because Spain is highly dependent on fossil fuel imports, and CSP is a high potential source to diverse the energy sources and increase the share of domestic energy supply [11]. The IEA set a target of 1089 GW global installed CSP capacity by 2050, which provides 4770 TWh annually with an average capacity factor of 50% (4380 h per year) [12], or 11.3% of the estimated global electricity production [13]. From the environmental protection perspective, the European Union (EU) sets a target of 80–95% reduction of EU

2.1. Overview of CSP CSP technology dates back to 1970s, but most of the commercial CSP installations were made in the last decade particularly in Spain and the United States [16,17]. Four commonly used types of CSP technology are shown in Fig. 3: parabolic trough collector (PTC), linear Fresnel reﬂector (LFR), solar power tower (SPT) and parabolic dish systems (PDS). PTC and LFR are line-focused technologies focusing the sun-light to a line of receivers typically oriented in the north-south direction, whereas SPT and PDS are point-focused technologies focusing the sun-light to a point where the receiver is located. Currently PTC occupies more than 82% of the global CSP installations. However, most recent CSP installations in the United States, including the world's largest CSP plant Ivanpah Solar Power Tower (Ivanpah Dry Lake, CA) commissioned in 2014, are SPT systems. [18]. The main reason for the present trend of installing SPT systems is the potential enhancement in efﬁciency of converting heat into electricity with SPT, and SPT is also more suitable for achieving very high temperatures [19]. The only disadvantage of SPT is that the initial installation cost is high compared to other CSP technologies [18]. Table 1 shows more details about the costs and other characteristics of all the CSP technologies. With regard to constraints of CSP installation, key factors are water availability particularly in desert regions, electricity transmission and energy supply security [15,20]. Large amount of water is needed for CSP cooling and mirror cleaning, but the water availability is very restricted in desert regions [21]. Energy supply security is a serious issue, particularly when considering the inherent vulnerability in electricity imports from other countries. A short power disruption could cause more than 10 $/kW h loss and it is unrecoverable because electricity cannot be stored [22]. 2.2. CSP in Southwest of the United States The U.S. Department of Energy (DOE) sponsored two independent studies in 2012 to investigate the potential of large scale solar deployment. Both the SunShot Vision and the Renewable Electricity Futures illustrate that solar could make signiﬁcant contribution for the U.S. electricity over the following 20–40 years [23]. Southwestern part of the United States is particularly suitable for CSP plants because of abundant solar energy availability as shown in Fig. 4(a) [24,25]. In the SunShot scenario, about 78 GW CSP systems are expected to be installed in the southwestern region by 2050 [23]. CSP development has made great progress in U.S. through longterm and sustainable investments by the DOE and industry partners. More than 13 GW CSP installed capacity are already in operation and ﬁve most innovative plants in the world will be

X. Xu et al. / Renewable and Sustainable Energy Reviews 53 (2016) 1106–1131

completed by the end of 2014 [26]. National Renewable Energy Laboratory (NREL) summarizes the CSP plants in operation in U.S. by now [27]. Table 2 lists detailed information of the CSP plants in operation. Solar Energy Generating Systems (SEGS) with parabolic troughs is currently the second largest CSP facility in the world. It has nine solar power plants in California's Mojave Desert and a total installed gross capacity of 354 MW (net capacity: 314 MW) [28]. Saguaro Power plant with 1.0 MW net capacity located in Red Rock, AZ is another parabolic trough type CSP plant, commissioned in 2006 [29]. Nevada Solar One is also a parabolic trough type CSP plant with a net capacity of 72 MW and started operation from 2007 [30]. The 75 MW Martin Next Generation Solar Energy Center located in Indiantown, Florida is the ﬁrst hybrid facility in the world to connect a solar facility to an existing combined-cycle

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power plant. The 5 MW Kimberlina Solar Thermal Energy Plant was completed in 2008 using Compact Linear Fresnel Reﬂector technology. This power plant locates in Bakersﬁeld, California [31]. The 5 MW Sierra SunTower is the ﬁrst CSP tower facility in U.S. which was unveiled in 2009 in Lancaster, California [32]. Other small CSP plants in operation include 2 MW Holaniku at Keahole Point, Hawaii, 2 MW and 1.5 MW Tooele Army Depot at Tooele, Utah. The ﬁve most innovative CSP plants are Solana, Genesis Solar, Ivanpah Solar Electric Generating System, Crescent Dunes and Mojave Solar One, all of which locate in southwestern region of U.S. [26]. The ﬁrst four plants are already operational and the last one is still under construction. The 250 MW Solana plant uses parabolic trough and has a six hour thermal storage unit. It locates

Table 1 Comparison of major CSP technologies along with operating temperature range [18,19].

Capacity range (MW) Operating temperature range (°C) Solar concentration ratio Solar to electricity efﬁciency (%) Relative cost Power cycle

Commercial maturity Outlook for improvements Advantages

Disadvantages

PTC

SPT

LFR

PDS

10–250 150–400

10–100 300–1200

5–250 150–400

0.01–1 300–1500

50–90 10–16

600– 1000 10–22

35–170 8–12

o 3000 16–29

Low Steam Rankine;

High Steam Rankine;

Low Steam Rankine;

Organic Rankine High limited

Brayton cycle (gas turbine) Medium Very signiﬁcant

Organic Rankine Medium signiﬁcant

Long term proved reliability and durability; Modular components;

High efﬁciency;

Simple structure and easy construction; Modular units;

Very high Stirling Engine; Steam Rankine; Brayton cycle (gas turbine) Low High potential through mass production High efﬁciency;

Compatible with combined cycles burning oil or gas; Relatively low efﬁciency; Limited operational temperature; Complex structure; Need water for cooling and cleaning

Compatible with Brayton cycle and combined cycles burning oil or gas; Modular components; High maintenance and equipment costs; Need water for cooling and cleaning

Compatible with combined cycles burning oil or gas; Relatively low efﬁciency; limited operational temperature

Modular units; No need for water cooling Low commercial maturity; No thermal storage available

Fig. 4. Solar average annual DNI in (a) U.S., (b) Spain, (c) Africa and Middle East, (d) Australia, (e) China and (f) India (SolarGIS © 2015 GeoModel Solar).

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X. Xu et al. / Renewable and Sustainable Energy Reviews 53 (2016) 1106–1131

Fig. 4. (continued)

in Gila Bend, Arizona and started to produce power from 2013 [33]. The 250 MW Genesis Solar plant without thermal storage consists of two 125 MW parabolic trough technology units. It locates in Blythe, California and started operation in 2014 [34]. Ivanpah Solar Electric Generating System with a gross capacity of 392 MW is the largest CSP project in the world by now. Ivanpah Solar employs the state of the art power tower technology and

uses more than 173,500 software-controlled heliostats to track the sun across the sky. It locates in Ivanpah Dry Lake, California and started operation in 2014 [35]. The 110 MW Crescent Dunes power tower project is the nation's ﬁrst commercial scale solar power tower facility with energy storage and the storage capacity is 10 h. This plant in Tonopah, Nevada with 10,000 heliostats was commissioned in 2013 [26,36]. The 250 MW Mojave Solar One

Table 2 Summary of operational CSP plants in various countries. Name

Net capacity (MW)

CSP type HTF

USA/Mojave Desert, CA

Solar Energy Generating Systems (SEGS) Martin Next Generation Solar Energy Centerb Saguaro Power Plant

314

PTC

Therminol ﬂuid

75

PTC

Dowtherm A

1

PTC

72 5

PTC LFR

USA/Lancaster, CA USA/Keahole Point, HI USA/Tooele, UT

Nevada Solar One Kimberlina Solar Thermal Energy Plant Sierra SunTowerc Holaniku Tooele Army Depot

Xceltherm 600 (solar ﬁeld) and n-pentane (ORC) Dowtherm A Water/steam

SPT PTC PDS

Water/steam Xceltherm 600 Helium

None 2 h capacity; storage type unknown None

USA/Gila Bend, AZ

Solana Generating Station

250

PTC

Therminol VP-1

USA/Blythe, CA USA/Ivanpah Dry Lake, CA

250 377

PTC SPT

Therminol VP-1 Water/steam

USA/Tonopah, NV

Genesis Solar Energy Ivanpah Solar Electric Generating Systemd Crescent Dunes Solar Energye

110

SPT

Molten salts

USA/Harper Dry Lake, CA Spain/Aldeire, Granada

Mojave Solar Project Andasol Solar Power Station

250 150

PTC PTC

Spain/Alvarado, Badajoz Spain/San José del Valle, Cádiz

Alvarado I Arcosol 50

50 50

PTC PTC

Spain/Morón de la Frontera, Sevilla Spain/Alcázar de San Juan, Ciudad Real Spain/Olivenza, Badajoz

Arenales

50

PTC

100

PTC

Astexol II

50

PTC

Spain/Les Borges Blanques, Lleida Spain/Talarrubias, Badajoz

Borges Termosolar

22.5

PTC

10 h capacity 2-tank direct storage with molten salts Therminol VP-1 None Dowtherm A for AS-1 and AS-2; 7.5 h capacity 2-tank indirect storage Thermal oil for AS-3 with Solar Salt for each of AS 1–3 Biphenyl/Diphenyl oxide None Biphenyl/Diphenyl oxide 7.5 h capacity 2-tank indirect storage with Solar Salt Diphyl 7 h capacity 2-tank indirect storage with Solar Salt Dowtherm A 8 h capacity 2-tank indirect storage with Solar Salt Thermal oil 8 h capacity 2-tank indirect storage with Solar Salt Thermal oil None

Casablanca

50

PTC

Biphenyl/Diphenyl oxide

50 150

PTC PTC

Thermal oil Biphenyl/Diphenyl oxide

20

SPT

Solar Salt

50 100

PTC PTC

100 50

USA/Indiantown, FL USA/Red Rock, AZ USA/Boulder City, NV USA/Bakersﬁeld, CA

Spain/Villena, Alicante Spain/Torre de Miguel Sesmero, Badajoz Spain/Fuentes de Andalucía, Andalucía Spain/Palma del Río, Córdoba Spain/Écija, Sevilla

Aste Solar Power Station

Enerstar Extresol Gemasolar Thermosolar Plantf Guzmán Helioenergy

Spain/Puerto Lápice, Ciudad Real Helios Ibersol Ciudad Real Spain/Puertollano, Castilla-La Mancha Spain/Posadas, Córdoba La Africana

5 2 1.5

TES

Cooling method

Commission date

3 h capacity 2-tank direct for SEGS I; None for the othersa None

Undeﬁned

SEGS I 1984-EGS IX 1990

Wet cooling

2010

None

Wet cooling

2006

0.5 h capacity; Storage type unknown None

Wet cooling Undeﬁned

2007 2008

Wet cooling Wet cooling Closed-loop cooling 6 h capacity 2-tank indirect storage with Wet cooling molten salts None Dry cooling None Dry cooling

2009 2009 2013 2013 2014 2014

Hybrid cooling

2013

Wet cooling Wet cooling

2014 AS-1 2008 – AS-3 2011

Wet cooling Wet cooling

2009 2011

Wet cooling

2013

Wet cooling

2012

Wet cooling

2012

Wet cooling

2012

Wet cooling

2013

Wet cooling Wet cooling

2013 EX-1 and EX -2 2010 – EX-3 2012 2011

Wet cooling Wet cooling

PTC PTC

Thermal oil Dowtherm A

None None

Wet cooling Wet cooling

2012 Helioenergy 1 2011 -Helioenergy 2 2012 2012 2009

50

PTC

Undeﬁned

7.5 h capacity 2-tank indirect storage with Solar Salt 7.5 h capacity 2-tank indirect storage with Solar Salt 7.5 h capacity 2-tank indirect storage with Solar Salt None

Wet cooling

2012

Wet cooling

2011

Wet cooling

2010

Wet cooling

2011

Spain/La Garrovilla, Badajoz

La Dehesa

50

PTC

Biphenyl/Diphenyl oxide

Spain/Badajoz

La Florida

50

PTC

Biphenyl/Diphenyl oxide

Spain/Lebrija, Sevilla

Lebrija 1

50

PTC

Therminol VP1

Wet cooling

1111

Dowtherm A Thermal oil

7.5 h capacity 2-tank indirect storage with Solar Salt none 7.5 h capacity 2-tank indirect storage with Solar Salt for each of EX 1-3 15 h capacity 2-tank direct with Solar Salt None None

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Country/Location

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Table 2 (continued ) Name

Net capacity (MW)

CSP type HTF

TES

Cooling method

Commission date

Spain/Majadas de Tiétar, Cáceres Spain/Alcazar de San Juan, Ciudad Real Spain/Morón de la Frontera, Seville Spain/Olivenza, Badajoz Spain/Orellana, Badajoz Spain/Palma del Río, Córdoba Spain/Sevilla, Sanlúcar la Mayor

Majadas I Manchasol

50 100

PTC PTC

Biphenyl/Diphenyl oxide Biphenyl/Diphenyl oxide

Wet cooling Wet cooling

2010 2011

50

PTC

Thermal oil

None 7.5 h capacity 2-tank indirect storage with Solar Salt for each of MS 1–2 None

Wet cooling

2012

Olivenza 1 Orellana Palma del Río Planta Solar

50 50 100 31

PTC PTC PTC SPT

Thermal oil Thermal oil Biphenyl/Diphenyl oxide Water/steam

Wet Wet Wet Wet

2012 2012 2011 PS10 2007-PS20 2009

Spain/Calasparra, Murcia Spain/Logrosán, Cáceres Spain/El Carpio, Córdoba Spain/Sevilla, Sanlúcar la Mayor Spain/San José del Valle, Cádiz

Puerto Errado 1 Solaben Solacor Solnova Termesol 50

31.4 200 100 150 50

LFR PTC PTC PTC PTC

Water/steam Thermal oil Thermal oil Thermal oil Biphenyl/Diphenyl oxide

Spain/Navalvillar de Pela, Badajoz Morocco/Ain Beni Mathar Morocco/Undeﬁned Morocco/Ait Baha

Termosol

100

PTC

Thermal oil

ISCC Ain Beni Matharg eCare Solar Thermal Project Airlight Energy Ait Baha Plant

20 1 3

PTC LFR PTC

Therminol VP-1 Water/steam Air at ambient pressure

ISCC Hassi R'mel ISCC Kuraymat Liddell Power Station

25 20 9

PTC PTC LFR

Thermal oil Therminol VP-1 Water/steam

None None None 1 h capacity; Storage type unknown for each of PS10-20 0.5 h capacity one-tank thermocline None None None 7.5 h capacity 2-tank indirect storage with Solar Salt 9 h capacity 2-tank indirect storage with Solar Salt None 2 h capacity steam drum 12 h capacity one-tank thermocline with packed bed None None None

Algeria/Hassi R'mel Egypt/Kuraymat Australia/Liddell, New South Walles Australia/Jemalong, New South Wales Australia/Lake Cargelligo, New South Wales China/Beijing India/Gurgaon India/Naukh, Rajasthan India/Anantapur, Andhra Pradesh India/Dhursar, Rajasthan India/Bikaner, Rajasthan

Morón

PE1 2009-PE2 2012 2012/2013 2012 2009 2011

Wet cooling

2013

Wet cooling Dry cooling Undeﬁned

2010 2014 2014

Dry cooling Wet cooling Dry cooling

2011 2011 2012

3 h capacity 2-tank direct storage with Dry cooling molten salt Core graphite thermal storage technology Undeﬁned

2014

1 h capacity two stages storage with saturated steam/oil

Wet cooling

2012

Undeﬁned

2012

1.1

SPT

Molten salt

3

SPT

Water/steam

Dahan Power Plant

1

SPT

Water/steam

National Solar Thermal Power Facility Godawari Solar Project Megha Solar Plant

1

PTC

Therminol VP-1

50 50

PTC PTC

Dowtherm A Xceltherm MK1

None None

Wet cooling Wet cooling

2013 2014

125 2.5

LFR SPT

Undeﬁned Water/steam

None None

Wet cooling Wet cooling

2014 2011

Dhursar ACME Solar Tower

TES for SEGS I was damaged by ﬁre in 1999 and was not replaced. The ﬁrst hybrid facility in the world connects a solar facility to an existing combined-cycle power plant. c The ﬁrst SPT plant in USA. d The largest CSP plant in the world. e The nation's ﬁrst SPT plant with TES. f The ﬁrst high-temperature solar receiver with molten salt. g The project consist of a 470 MW hybrid power plant composed of a combined cycle and a 20 MW solar thermal system. b

Dry cooling Wet cooling Wet cooling Wet cooling Wet cooling

Jemalong Solar Thermal Station Lake Cargelligo

All information is from NREL website (http://www.nrel.gov/csp/solarpaces/) on Concentrating Solar Power Project Proﬁles. a

cooling cooling cooling cooling

2011

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X. Xu et al. / Renewable and Sustainable Energy Reviews 53 (2016) 1106–1131

facility uses parabolic trough technology and locates in Harper Dry Lake, California (100 miles northeast of Los Angeles), started in December 2014[37]. 2.3. CSP in Spain Spain is one of the global leaders in CSP installation and major part of Spain has high DNI ( 41800 kW h/m2/year) as shown in Fig. 4(b). All the plants in operation in Spain are listed in Table 2. In 2008, the total CSP energy production capacity of Spain was only 60 MW, but it increased by 30 times to 1800 MW power generation capacity by the end of 2012 [38]. The tremendous growth of CSP in Spain is not only due to the efforts in the R&D sector, but also due to the measures taken by the government such as feed-in tariffs and the policies which require a portion of solar power in their energy mix [39]. Spain is also the pioneer in utilizing thermal energy storage technologies for night-time power generation. Thermal energy storage capability of CSP systems employing molten-salts has been commercially proven after the launch of Andasol-1 trough plant in Spain at the end of 2008 [40]. Presently, almost half of the CSP plants in Spain have thermal energy storage capability. One of the special features of CSP designs in Spain is that almost all the plants are constructed to provide 50 MW power output. This is due to a cap in the national support scheme, which does not allow larger turbine sizes [38]. Most of the CSP plants in Spain use water, thermal oils or organics as HTF. Currently there are seven commercial CSP plants in the world using water/steam as the HTF. Among these, four plants are in Spain (Puerto errado 1, PS10 solar power tower, PS20 solar power tower and Puerto errado 2) [17]. Biphenyl/Diphenyl oxide pair is also used as HTF in commercial CSP plants located in Spain. The ﬁrst solar thermal plant with this organic liquid as HTF was commissioned in 2009 at Badajoz, Spain and was named as Alvarado 1. Currently eight CSP plants in Spain are operating with Biphenyl/Diphenyl oxide. 2.4. CSP in MENA (Middle East and North Africa) 2.4.1. North African countries Very high solar DNI and land availability existing in the Sahara Desert in North Africa make this area promising for the CSP applications. Fig. 4(c) shows the annual DNI in the MENA area for the year 2002. Several North African countries including Morocco, Algeria and Egypt have made large progress in solar energy utilization during 2007–2009 as participants of the DISTRES (Promotion and consolidation of all RTD activities for renewable distributed generation technologies in the Mediterranean region) project funded by FP6-INCO (the 6th Framework Program for Research and Development of the EU as an International Coordination action) with a primary interest on the electricity produced from solar energy [41]. The projects constructed in these countries can serve as good paradigms for other areas of the world. The CSP plants currently in operation in these countries are listed in Table 2. Morocco has a high rate dependence on imports of crude oil, coal and electricity. CSP plants are expected to play signiﬁcant role in achieving this country's target to increase energy mix of renewable energy [42]. Recently Morocco announced a $ 9 billion plan to construct integrated solar energy projects with combined cycle units in ﬁve potential sites (Sebhate Tah, Foum Al Quad, Ain Beni Mathar, Ourzazate, and Boujdour). DNI in these sites are between 2140 and 2642 kW h/m2/year. The total installed capacity will reach 2000 MW and net estimated production might reach 4400 GW h/year in 2020. The ﬁrst 472 MW integrated power plant in Ain Beni Mathar consisting of 20 MW solar energy ﬁeld with

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parabolic trough arrays was commissioned in 2010. The last project is supposed to begin operation in 2019 [42,43]. Algeria is the largest country of the Mediterranean region and one of the countries with abundant natural gas production in Africa. Currently the Integrated Solar Combined Cycle (ISCC) plant in Hassi R'mel is in operation starting from 2011 [44]. The plant combines a 25 MW parabolic trough arrays with a 130 MW combined cycle gas turbine plant [45]. The New Energy Algeria (NEAL), a joint venture of Sonatrach Sonelgaz and SIM, developed this plant and Sonatrach will buy all the power produced estimated as 1250 GW h/year [42]. Egypt has DNI ranging between 1970 and 3200 kW h/m2/year from north to south across the country [42]. The ﬁrst ISCC plant in Kuraymat (100 km south of Cairo) started electricity production from 2011 [46]. Kuraymat has DNI of 2400 kW h/m2/year and locates close to the River Nile [42]. This power plant has capacity of 140 MW, 20 MW of which is from parabolic trough arrays [46]. 2.4.2. DESERTEC DESERTEC concept to use solar energy in Sahara Desert to provide electricity to Europe and MENA countries was created in 2003 by the German-based Trans-Mediterranean Renewable Energy Cooperation (TREC) [47]. Within this scheme large scale CSP systems, PV arrays and wind farms would be constructed across the more accessible southern and northern of the Sahara desert as shown in Fig. 5 [47]. A feasibility study shows that a power grid of 100 GW including 25% solar power and 53% wind power at the cost of $ 400 million can supply 15% of European demand for electricity by 2050 [48–50]. If successfully completed, the DESERTEC project can not only improve the competitiveness of the Europe-MENA power system by signiﬁcant CO2 emission reduction and cost saving, but also enhance the energy supply security of participating countries. Countries involved in this project can be distinguished as renewables super producers, importers and countries with balanced renewables and demand. In this mutual reliance situation, no one country is completely dependent on another but instead each country is reliant on the whole system. From a political and geopolitical point of view, the relations of the involved countries are also enhanced [51]. In 2009a consortium, DESERTEC Industrial Initiative was signed by 12 initial companies from Europe, mainly from Germany, including Siemens, Deutsche Bank, ABB, Munich RE, RWE, E.ON and Abengoa Solar etc. to commercialize this project [52]. The participation of major industrial companies and energy producers showed a stronger determination that the DESERTEC project was not just a dream. However, 47 out of 50 shareholders had left the consortium in 2014. Only Saudi Arabia's ACWA Power IPO-ACWA. SE, Germany's RWE and China's State Grid decided to stay and continue the project on a much smaller scale. High cost, political risks in north African countries, and the development of solar power in Europe were reasons for the major shareholders such as Siemens, Bosch, E.ON and Bilﬁnger to quit [53]. Risk of being a target of terrorist attacks, extensive and challenging economic and political cooperation between countries, extreme high demand of water to clean dust off panels and for turbine coolant in deserts are also concerned as major obstacles [54,55]. 2.5. CSP in Australia Australia is abundant of solar energy in the large inland desert regions with high temperatures and low precipitation year round [56]. A large part of Australia has DNI above 2200 kW h/m2/year as shown in Fig. 4(d) [57]. Port Augusta region in South Australia, north-west Victoria, and central and north-west New South Wales are claimed to be locations with high potential for CSP plants due

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Fig. 5. Large scale CSP systems, PV arrays and wind farms proposed for the DESERTEC network in MENA (Source: DESERTEC Foundation) [47].

to high DNI and ease of connection to grids [58,59]. Australia also has the ability to construct CSP plants at competitive cost because of its well-developed heavy industries and experience with thermal power stations [60]. The CSP plants currently in operation in Australia are listed in Table 2. Commonwealth Scientiﬁc and Industrial Research Organization (CSIRO) made a prediction that solar energy would be responsible for 30% of Australia's energy supply by 2050 [61]. Currently a 9.3 MW CSP-coal hybrid plant is in operation at Liddell Power Station, and another 44 MW CSP-coal plant was launched in 2011 at Kogan Creek but will not be commissioned until 2015 [62,63]. However, no standalone large scale CSP plant exists in Australia until now because of very limited ﬁnancial support from the government [64]. The two planned CSP plants of 250 MW SolarDawn and 40 MW SolarOasis were withdrawn in 2012 and 2013 separately because of funding issues [57]. Another new Solar Flagships Program (SRP) announced in 2009 may encourage development of CSP in Australia. The $ 1.6 billion program aims to construct four solar power plants (PV and CSP) with a total capacity of 1000 MW during 2009–2015, at least one of which will be CSP plant [64]. Even though the SRP program didn't go well in the ﬁrst four years because of failure to secure funding, it was back on track in 2013 with the effort of AGL Energy (one of the “Big 3” utilities in Australia) to bridge the funding gap. The ﬁrst 155 MW PV plant of the four solar power plants is anticipated to be completed by 2015 [65,66]. 2.6. CSP in China and Mongolia 2.6.1. China While only 2.8% of the total energy consumed in China was from renewable energy in 2005 [67], the National People's Congress of China passed a law to replace 15% of the total energy consumption with renewable resources by 2020 [68], and the Chinese government committed to reduce 40–45% CO2 emission per unit of gross domestic product (GDP) by 2020 against the 2005 level [69]. In 2007 China has almost three-quarters of the energy

from coal-ﬁred power stations [70], and the large scale coal mining and combustion causes serious GHG emissions as well as health and life threatening consequences [71,72]. China was considered to be responsible for two-thirds of the global increase in anthropogenic CO2 emissions as the second largest emitters in the world in 2007 [73] and the total direct GHG emissions of China was estimated to be 7456.12 Mtonne CO2 equivalent (CO2-eq) [74]. In China's plan to achieve a sustainable future, solar energy is expected to make relatively minor contribution of less than 1% of China's total renewable energy capacity by 2020 [75]. However, China's decision was argued as a mistake and should be reconsidered particularly considering the enormous solar potential for large scale plants in northwestern and southwestern parts of China [76]. In fact, power generation up to 100 GW through solar thermal has been suggested possible by 2025 in China [70]. Fig. 4(e) shows the average annual DNI for China. As the DNI should be 45 kW h/m2/day for CSP to be economical, the Tibet Autonomous Region, Xinjiang Autonomous Region, central areas of Inner Mongolia and parts of Qinghai Province are potential sites for CSP plants [76–78]. Nevertheless, these areas are all far from the eastern region with the most population and highest power demands. This problem can be practically resolved if China completes its extensive smart grid, which is slowly under construction via the “Power Transmission from the West to the East” plan. The smart grid includes the development of a new 800 kV ultrahighvoltage direct current (UHVDC) and 1000 kV ultrahigh-voltage alternating current (UHVAC) transmission systems [79]. With respect to the land availability, it was predicted that China can match its net installed electricity capacity of 602,570 GW in 2006 by utilizing only 1.2% of the desert areas in Tibet, Inner Mongolia and Qinghai [76]. Although China has become the largest solar water heater producer and user with about 150 million square meters installation by 2010 [75], the development of CSP plant in China is still in an early stage. In order to reduce dependence on imported technologies, China decided to fund domestic research on CSP development. China's ﬁrst and only MW class CSP tower plant in

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Fig. 6. HVDC transmission cables proposed for the GOBITEC network in Northeastern Asia (Source: www.hss.or.kr/A1189English.html) [85].

operation named “Dahan” was funded in 2006 and started power production in 2012 [80]. The Dahan plant with a rated power of 1.5 MW locates in Yanqing County in the northwestern of Beijing and connects with power grid line in Yanqing district. It has a TES system with capacity of 1 h full load operation. The solar collectors and power station cover 0.16 km2 land. The mean annual efﬁciency of the receiver is 90% and about 8 t/h superheated steam (2.8 MPa, 400 °C) can be generated. Water/steam is employed as HTF in this plant and thermal oil is used as heat storage media. Dahan is expected to generate 2.7 million kW h electricity annually and operate for 20 years [81,82]. If it is assessed successful, it will be expanded to 5–10 MW by 2015 [83]. The GHG emission of the Dahan plant was evaluated as 0.04 kg CO2-eq/MJ in the 20 years operation life, 95% of which is from construction and only 5% is caused in the maintenance and operation. The total GHG mitigation of this plant was estimated as 41.7 ktonne CO2-eq [83]. As for daily operation and maintenance, 1 t of water is needed per day for collectors cleaning; 35 t of water is used per day for circulating cooling; 14 t of water is consumed per day as chemical feed; 30 t of water is used per day for auxiliary cooling; 20 t of water per day is consumed as domestic water; and 100 t of water is consumed by the turbo-generator system [83]. Besides Dahan plant, China is projected to increase the CSP plants capacity to 1 GW by 2015 and 3 GW by 2020, most of which will be based on SPT technology [84]. The plants under construction or planned are 1 MW Badaling pilot project, 12 MW (short-term)/300 MW (long term) project in Xinjiang, 50 MW project in Tibet, 100 MW project in Sichuan Abazhou, 100 MW project in Golmud, 100 MW project in Ningxia, 100 MW project in Gansu, 100 MW project in Qinghai and 2000 MW project in Shanxi [84]. 2.6.2. GOBITEC Inspired by the DESERTEC in MENA, GOBITEC project in Northeastern Asia was proposed in 2009 to harness the solar energy in the Gobi desert across the border of China and Mongolia [85]. 1 GW electricity was expected to be produced and delivered to Mongolia, China, North Korea, South Korea and Japan through 6000 km HVDC transmission cables as shown in Fig. 6 [86]. Large scale CSP plants with parabolic trough solar concentrators and molten salt storage facility were planned in the original GOBITEC proposal. Although Mongolia have potential avenues for economic

development as the host country of this CSP project, an anonymous Mongolian government leader expressed hesitation of integrating CSP with the country's current electricity infrastructure in an interview. Enormous amount of cooperation and coordination between countries involved and lacking of experience with CSP are the major concerns [7]. Potential beneﬁts of the GOBITEC project include several different aspects. Despite of being clean and low carbon, solar energy obtained from this project also merits energy security of the involved countries particularly for Japan and Korea, which both have few domestic sources of energy and highly dependent on imported fossil fuels from monopoly suppliers of Russia and the Middle East [86,87]. Energy cooperation, policy cooperation and even political integration can also be accelerated between the Northeastern Asian countries. The last but not the least, this project offers an opportunity to engage North Korea to become a nonnuclear and cooperative energy venture [7,86]. At the moment GOBITEC is still a fantasy due to many obstacles. The ﬁrst difﬁculty lies in ﬁnancing. As large scale CSP system is not included in the short term renewable energy development plan of Mongolia, investment of GOBITEC has to rely exclusively on foreign funding from private companies, investors and international organizations [88]. Land availability is another serious issue. Southern region of Mongolia is rich in mining sources and Mongolian government has issued long-term mining licenses covering most of the Gobi area to international joint ventures [88]. Even if the GOBITEC project is successfully constructed, the reliability of the system is critical for involved countries particularly for those with small net electricity capacity such as Mongolia and North Korea. An unexpected disruption or failure of the system may completely damage the vulnerable transmission infrastructure from Ulaanbaatar to Pyongyang and put the relations between countries in risk [88]. 2.7. CSP in India Most parts of India have about 300 sunshine days year round since it locates close to the equator [89]. Fig. 4(f) shows a map of solar DNI in India. India has ﬁnalized its long-term schedule to enhance the solar power generating capacity: 20 GW by 2020, 100 GW by 2030 and 200 GW by 2050 [89]. This includes energy

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produced by both CSP and PV cells. According to Jawaharlal Nehru National Solar Mission (JNNSM) of the Indian government, 50% would be from CSP technology out of the targeted 20 GW grid connected solar power by 2020 [90]. Northwestern of India, particularly the states of Rajasthan and Gujarat, are the primary locations having huge potential for CSP plants (DNI42000 kW h/m2/year) [90]. Most of the currently operating CSP plants in India locate in these two states. Presently, India has a total of almost 230 MW CSP power capacity from ﬁve operating CSP plants. Another four CSP plants with a total capacity of 275 MW are under construction. The ﬁve CSP plants currently in operation include three PTC plants, one SPT plant and one LFR plant. The three PTC plants are 1 MW National Solar Thermal Power Facility in Gurgaon (2012), 50 MW Godawari Solar Project in Naukh, Rajasthan (2013) and 50 MW Megha Solar Plant in Anantapur, Andhra Pradesh (2014). The SPT plant is 2.5 MW ACME Solar Tower in Bikaner, Rajasthan (2011) and the LFR plant is 125 MW project in Dhursar, Rajasthan (2014) [91]. Dhursar plant is the world's largest LFR facility. The main advantage of LFR technology is the low amount of required land area, but the efﬁciency of LFR is less compared to other CSP technologies [91]. Detailed information of the ﬁve plants are listed in Table 2. The four plants under construction are 50 MW Abhijeet Solar Project in Jaisalmer, Rajasthan, 100 MW Diwakar project in Askandra, Rajasthan, 25 MW Gujarat Solar One project in Kutch, Gujarat and 100 MW KVK Energy Solar project in Askandra, Rajasthan [91].

3. Technical challenges 3.1. Water consumption Large amount of water is required for CSP plants, but the availability of water is usually quite restricted in arid or semi-arid regions which are the best sites for CSP construction. For current CSP systems, the water requirement is estimated between 3 and 3.5 m3/kW h, 95% of which is attributed to cooling tower and 5% is consumed for mirror cleaning [92]. Development of dry cooling and mirror cleaning methods as well as other technologies are necessary to minimize the use of water in CSP plants. 3.1.1. Dry cooling Currently, most commercialized CSP plants are integrated with conventional steam Rankine cycle for power generation. A key step of the power generation in Rankine cycle is the cooling of exhaust steam, which needs to be condensed and returned to the steam generator. The lower the condensation temperature is, the higher the conversion efﬁciency of the power block becomes [93,94]. Wet cooling can provide higher conversion efﬁciency than dry cooling because the exhaust steam with wet cooling can be cooled faster to a lower temperature [95]. So that a CSP plant with wet cooling can offer better thermal performance [96]. Nevertheless, the most suitable regions to build a CSP plant are generally desert regions with high DNI and water scarcity [97]. Even if evaporative cooling systems are currently deployed in the majority of operating CSP plants in Spain, this solution will not be applicable for a large scale CSP development in arid regions [98]. As a result, a reasonable choice of the cooling system for a CSP plant is of particular interest for solar engineering community. Several studies by National Renewable Energy Laboratory (NREL) showed that dry cooling could save more than 90% of water consumption [99]. Liqreina and Qoaider [100] calculated the average monthly water saving by implementing dry cooling in comparison with a similar power plant operating with wet cooled power block, and concluded that dry cooling can save more than 90% of water consumption. On the other hand, dry cooling needs a

bigger solar ﬁeld than that for wet cooling with the same power output, and it results in higher investment costs [101]. As a consequence, a trade-off between all the cooling options should be made for each speciﬁc site to know whether to use dry cooling or not [102]. Dry cooling method is governed by the dry bulb air temperature. The heat rejection performance of the dry cooling system under varying ambient conditions and the thermodynamic performance characteristics of the turbine are closely interrelated [103]. Dry cooling systems can be realized with direct or indirect layout. In direct systems, exhaust steam from the turbine is transported to an air-cooled condenser (ACC), as shown in Fig. 7(a). In this system, an air exchanger is used for heat rejection; natural draft or forced draft towers can be installed. Heat transfer mainly occurs as sensible heat and its properties depend on weight, speciﬁc heat of the air and temperature variation during the cooling process under a constant speciﬁc humidity (i.e., the amount of water vapor present in the air). The steam condenses inside ﬁne tubes that are typically arranged in an A-frame conﬁguration and then cooled by air blown across the ﬁnned surfaces. The condensation of the steam turbine exhaust plus auxiliary cooling is estimated to represent 5% of the condensing heat load [104]. Despite the inefﬁciencies of dry-cooling systems, these systems provide environmental beneﬁt when installed in the arid and semi-arid environments with regard to lowering water consumption and using fewer chemicals for disinfecting and cleaning of hydraulic circuits. Ivanpah 1, 2 and 3 plants in the Mojave Desert, California [97] are projects which demonstrate the successful implementation of this system. An alternative approach of dry cooling is represented by the indirect layout. Particular interests are the so-called Heller systems, as shown in Fig. 7(b), which is an improved version of direct dry cooling system. In this type of system, thermal power is dissipated by heat exchange in a condenser through a closed-loop water cooling process. The heat that absorbs the water is transferred to the atmosphere through a tube heat exchanger. Air movement can be achieved through a natural or mechanical system, where air is used as a secondary cooling system. In the closed water loop, most of the energy is transferred through convection and a small amount is transferred through evaporation, saving 97% of the water used in the wet cooling system [97]. In this system, the ﬂow of cooling water never comes into contact with the cooling air. However, the main problem with the system is the greater initial capital investment and increased operational costs. The crucial design of Heller system is the barometric condenser, where the steam is condensed directly by a spray of cooling water. Thereby it is possible to achieve very low (0.5 °C) terminal temperature differences (TTD) compared with that of conventional surface condensers (3–4 °C) [105]. Driven by increasing interests of dry cooling, several approaches for the enhancement of dry cooling have been proposed and the hybrid dry–wet cooling system is the most promising [106– 109]. A hybrid cooling system involves the operation of two systems in parallel: dry and wet cooling, as shown in Fig. 7(c). Generally, the bybird system operates by the dry cooling mode when the ambient temperature is not high; but in summer days, the performance of the hybrid system can be enhanced by routing a portion of the exhaust steam from the turbine to a separate wet cooling system, which only rejects a portion of the total dissipated heat [97]. It is also reported that a hybrid system can save up to 80% of the annual water consumption of an evaporative cooling tower [110]. 3.1.2. Dust cleaning Dust accumulation on heliostat mirrors or on solar collectors installed at different tilt angles is an important problem in CSP

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Sayigh et al. [112] performed a study in Kuwait and found 64, 48, 38, 30 and 17% reduction in the transmittance of glass plates tilted at angles 0, 15, 30, 45 and 60°, respectively, after 38 days of exposure. El-Nasar et al. [113] studied the effect of dust accumulation on evacuated-tube ﬂat-plate type solar collectors installed in the United Arab Emirates and reported a 70% reduction in the collector performance, if the collectors were not cleaned for a whole year. In 2014, Grifﬁth et al. [114] have studied the effect of dust accumulation on CSP mirrors in a candidate CSP site near Kathu in the Northern Cape, South Africa and reported a mean rate of loss of 0.5% per day in specular reﬂectivity for an exposure period between 9 to 30 days. It was found that the reﬂectivity losses for horizontal (top-facing) mirrors were almost two fold of that of the mirrors tilted at 45°. Detailed information about the impact of dust on the use of solar energy is described in a recent review by Sarver et al. [115]. Cleaning the mirrors with water and detergent is the most effective method, but the scarcity of water in desert locations makes the water-cleaning an expensive method. Typically, 0.15 to 0.175 m3/kW h water is required for mirror cleaning in CSP systems [92]. As the number and size of commercial CSP plants increase, the time-consuming and labor-intensive water cleaning methods are given up these days in favor of automated cleaning systems or self-cleaning glass technologies. Several methods have been tested by researchers to develop alternative ways to clean the heliostat mirrors or solar collectors with less or even without water [116]. In 2014, Houda et al. [117] have investigated putting superhydrophobic coatings on CSP mirrors in order to create lotus effect leading to self-cleaning, and anti-contamination properties. After testing several super-hydrophobic materials, they reported that poly (p-phenylene butylene) is the best polymer as superhydrophobic coatings on CSP mirrors. It has high melting point, low absorbance, a refractive index close to 1 and high ﬂexibility. In another recent study of Hunter et al. [111], a low-cost, easy to apply anti-dusting coating has been developed based on superhydrophobic functionalized nano-silica materials and polymer binders.

Fig. 7. Dry cooling system layout for (a) Direct dry cooling system, (b) Indirect dry cooling system (Heller system) and (c) Hybrid dry–wet cooling system (adapted from cornerstonemag.net).

plants. Almost all the commercial CSP plants in the world have been installed in arid or semi-arid regions with high DNI. Hence the possibility of dust accumulation is very high. It is obvious that the reﬂectance of the heliostat mirrors or the transmittance of solar absorbers reduce due to the dust accumulation and so as the efﬁciency of the CSP system. A number of studies have reported the effect of dust accumulation on solar devices in semi-arid and arid regions. According to the Solar Power World, 40% of solar power conversion decreases because of a dust layer of 1/7 ounce per square yard [111]. Optical performance of CSP collectors or mirrors directly inﬂuences the electricity cost. 1% decrease in reﬂectance leads to 1% increase in levelized cost of electricity (LCOE) produced from the CSP systems [111].

3.1.3. CSP-desalination cogeneration CSP-desalination cogeneration is an attractive operation mode for new CSP development. Both power and fresh water are produced simultaneously, which not only reduces the cooling water requirements of a CSP system because part of the heat from steam is used to assist desalination, but also supplies fresh water to the population in desert regions that face severe water deﬁcits [118]. Among all the desert regions, MENA has the highest potential for the application of CSP-desalination cogeneration technology because of convenient access to seawater in the Mediterranean Sea [119]. The ideal desalination plant location should not be over 20 m above sea level or more than 5 km away from the shore [19]. In fact, MENA region also has a great need for fresh water as it is the most water scarce region due to high population growth rate, urbanization, and natural water scarcity [120]. Despite the promising prospective, the desalination coupling with CSP plant technology is still in an early stage [121]. Trieb et al. were the ﬁrst researchers to study the potential of CSPdesalination cogeneration in MENA region [122,123]. The AQUACSP Concentrating Solar Power for seawater desalination project have provided a comprehensive database on technology options, water demand, reserves and deﬁcits in the MENA region [124]. Economic studies [125,126], modeling and optimization works [119,127] of CSP-desalination plants and major barriers of introducing this technology [19] were also reported in the literature recently.

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Currently the most popular desalination technologies are Reverse Osmosis (RO) using electrical power as the driving force, multi-effect desalination (MED) and Multi-stage ﬂash (MSF) using thermal power as the driving force. RO and MED are the two most promising desalination technologies for utility scale CSPdesalination cogeneration plants [128,129]. MSF is excluded due to high investment, and high power and cooling water requirements [19]. The total energy requirements of RO, MED and MSF are estimated at 3.5–4.5, 4–4.5, and 14–25 kW h/m3 water, respectively [130]. CSP-MED technology is more competitive and cheaper compared to CSP-RO at large capacity (41000 m3/day) [131]. It is also more thermodynamically efﬁcient because of the replacement of the condenser with an MED plant [126]. Besides, RO is highly dependent on the effectiveness of water pre-treatment, MED nevertheless can treat very saline water [19]. 3.2. Heat transfer ﬂuid HTF is an essential component of a CSP plant as it transfers heat concentrated by the receiver to steam generator. Presently, several different types of HTFs are used in commercial CSP plants, including air, water/steam, thermal oils, organics and molten salts [16,17,132]. However, all of these materials have disadvantages as HTFs. Ideally the HTF is expected to not only transfer heat as a media in the CSP system, but also directly store heat in a thermal energy storage (TES) tank without additional heat exchanger. Several characteristics are desired for the ideal HTF. Low melting temperature is needed to reduce the freezing risk. High thermal stability temperature is required to increase the system efﬁciency. Particularly the solar tower systems demand a thermal stability temperature up to 700 °C. At high temperature the corrosion of metal alloys which are used as container and pipe materials for the HTF is a serious issue. Moreover, low viscosity is expected to reduce the pumping power, and high speciﬁc heat capacity is favorable to reduce size of the TES tanks. Cost is another important criterion for practical applications [133,134]. Among the currently used HTFs, air is only used in one 1.5 MW pre-commercial solar plant in Jülich, Germany [17]. The major advantages of air are free cost and very low viscosity [135]. However, its thermal conductivity is relatively low [136]. High temperature corrosion of alloys in air is not a severe issue. For instance, Klöwer [137] tested twelve iron-aluminum-chromium alloys with different mass contents in air at 1100 °C for 1008 h and the mass change for these alloys were only in the range of 7 to 1.4 mg/cm2. Water/steam is used in seven commercial CSP plants. Four plants are in Spain and three plants are in California, USA [17]. Water/steam has low viscosity at high temperature, high speciﬁc heat capacity and low thermal conductivity. High temperature corrosion of nickel based Inconel alloys in steam is almost negligible [138–140]. The main problem of using water/steam is also the water scarcity in arid regions. Thermal oils including mineral oil, silicone oil and synthetic oils have a narrow operating temperature range between 200 and 400 °C [141]. For instance, Xceltherm 600 (parafﬁnic mineral oil) is currently used in commercial CSP systems and its thermal stability temperature is only 315 °C. Thermal conductivity of thermal oils is close to that of air and steam. Cost of thermal oils is another issue as the price is commonly around 3 to 5 $/kg [142]. Biphenyl (C12H10) and Diphenyl oxide (C12H10O) pair is one organic HTF widely used in several commercial CSP plants in Spain [17]. Biphenyl/Diphenyl oxide has a limited working temperature range of 293–393 °C, low viscosity, very low thermal conductivity and high cost ( 100 $/kg) [132]. At the moment, salt mixtures seem to be the most promising HTF candidates because of high thermal stability temperatures and properties similar to steam at high temperatures [143]. Alkali

nitrate and nitrite mixtures have made the greatest progress by now. Solar Salt (KNO3 40 wt%–NaNO3 60 wt%), Hitec (NaNO3 7 wt%–KNO3 53 wt%–NaNO2 40 wt%) and HitecXL (NaNO3 7 wt%– KNO3 45 wt%–Ca(NO3)2 48 wt%) are three commercialized alkali nitrate and nitrite mixtures. Solar Salt was ﬁrstly tested in the 10 MW Solar Two plant in U.S. in 1996, and then was employed as HTF for the 17 MW commercial Gemasolar CSP plant (Solar TRES) in Spain in 2011 [144]. Solar Salt is also used at the newest 100 MW Crescent Dunes CSP plant in U.S. [17]. Solar Salt has the melting temperature of 220 °C and the thermal stability temperature of 600 °C [40]. Its speciﬁc heat capacity is 1.5 kJ kg 1 K 1 at 600 °C [145] and the cost is about 0.5 $/kg [146]. The corrosion rates of SS-304 and SS-316 in Solar Salt were reported to be 6–15 mm/year at 570 °C [147]. Hitec and HitecXL were developed by Halotechnics Inc. and they are not yet used in commercial CSP plants. The working temperature ranges of the two salt mixtures are 142–535 °C and 120–500 °C, respectively [40]. Their viscosities are similar to steam at high temperatures and the speciﬁc heat capacities are 1.56 and 1.45 kJ kg 1 K 1 at 300 °C, respectively [40]. The cost is around 1 $/kg for both salt mixtures [146]. Corrosion rate of stainless steel in the two salt mixtures is comparable to that in Solar Salt [147,148]. For example, SS 321 was reported to have a corrosion rate of 2 μm/year with Hitec at 570 °C, and SS 304 and SS 316 were reported to have corrosion rates of 6 to 10 μm/year with HitecXL at the same temperature [147]. More works have been reported in order to improve the thermal stability range of the nitrate and nitrite mixtures by adding LiNO3 [149– 151]. However, the cost of LiNO3 is relatively high ( 4.3 $/kg) and not any mixture has been reported to meet all the HTF requirements. Other nitric salts based HTFs include Sandia Mix (NaNO3 9–18 wt%–KNO3 40–52 wt%–LiNO3 13–21 wt.%–Ca(NO3)2 20–27 wt%) developed by Bradshaw et al. [152] at the Sandia National Laboratories and SS-500 (NaNO3 6 wt%–KNO3 23 wt%– LiNO3 8 wt%–CsNO3 44 wt%–Ca(NO3)2 19 wt%) developed by Halotechnics Inc. [153]. The working temperatures are 95–500 and 65–500 °C, respectively. Although most of the currently investigated salt mixtures for HTF are based on nitrates and nitrites, worldwide nitrate salt production is restricted [154]. In this context, alternative HTFs made from inexpensive and earth abundant materials are being intensively investigated. Carbonate salts were recently studied [155] and one LiNaK carbonate salt (LiCO3 32.1 wt%–Na2CO3 33.4 wt%–K2CO3 34.5 wt%) was reported to have a working temperature range of 400–850 °C, low viscosity and low cost around 1.3 $/kg [156]. In an ongoing project, Reddy et al. [157] are working on the development of alkali-ﬂuoride and carbonate salt mixtures (for example, LiF-NaF-K2CO3) as the HTF with a working temperature range of 400–900 °C. Researchers in another ongoing project recently proposed a chloride salt eutectic mixture (NaCl 7.5 wt%–KCl 23.9 wt%–ZnCl2 68.6 wt%) as one potential HTF [158]. The melting temperature of the ternary chloride mixture is about 850 °C. The viscosity is reported to be 0.325 Pa s at 300 °C and the thermal conductivity is about 0.81 W/(m K) in the temperature range of 300 and 600 °C. The cost of this ternary salt mixture is below 1 $/kg. Besides molten salts, in an ongoing project at UCLA and UC Berkeley, several binary mixtures of liquid metals including Cd-Bi, Sn-Bi, Bi-Zn and Ca-Cu are being investigated for potential use as HTF for CSP applications [159]. 3.3. Thermal energy storage (TES) TES system is one of the most distinguishing features of CSP with respect to other renewable energy technologies like wind power or photovoltaics, since it can smooth out the short-term transients and to extend the daily operation of CSP plants during the late afternoon and evening hours [160,161]; in other words,

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Fig. 8. Three generation TES systems. (a) The ﬁrst generation two-tank TES with HTF only, (b) The second generation one-tank TES with HTF only, (c) The third generation one-tank TES with HTF and a loosely packed solid material and (d) The third generation one-tank TES with HTF and an embedded heat storage material (© 2011 Li, Van Lew, Karaki, Chan, Stephens, O'Brien. Originally published in [166] under CC BY-NC-SA 3.0 license. Available from: http://dx.doi.org/10.5772/20979).

TES is highly dispatchable with electricity demand. TES has several advantages compared to mechanical or chemical storage technologies, such as low capital costs and high operating efﬁciency. A TES prototype system incorporated into the Solar Two project in Daggett, CA demonstrated a round-trip efﬁciency greater than 97% [162–164]. One TES system usually consists of three parts, the thermal storage medium, the HTF and the containment system. The thermal storage medium stores thermal energy either in the form of sensible heat, latent heat, or a combination of both forms, or in the form of reversible chemical reactions [165]. To date, sensible heat materials are the most widely used storage medium in commercial CSP systems, while latent heat or thermochemical materials are still in development. HTF supplies and extracts heat from the storage medium to the power generation block, and it has already been discussed in Section 3.2. The containment system holds the storage medium as well as the energy transfer equipment, and it requires good thermal insulation from the surroundings. TES system has been developed through three generations. The ﬁrst generation is called the direct HTF storage system with storage tanks, as shown in Fig. 8(a), one tank for hot ﬂuid and the other for cold ﬂuid [163]. In this case, HTF itself is directly used as the energy storage medium. The second generation system has only one tank, as shown in Fig. 8(b) [166]. A stratiﬁcation of ﬂuid, which maintains hot ﬂuid on top of cold ﬂuid, is important to such a single tank thermal storage system [167–170]. The third generation system uses two different mediums, a HTF and a primary thermal storage material [171], either solid or liquid, with only a single storage tank. Depend on the contact and heat transfer between the HTF and the primary energy storage material, the storage system may have two types. The ﬁrst type as shown in Fig. 8(c), includes loosely packed solid materials (such as rocks, pebbles of metals, capsules of phase change materials) as a porous bed, through which the HTF ﬂows and transports energy to or from the solid materials; while the second type of two-medium

heat storage system, as shown in Fig. 8(d), is the embedded structure system. 3.3.1. Thermocline system Currently, the 2-tank storage system is the most commercially mature technology and has been widely used in industry, and the thermocline TES system attracts a lot of attention in recent years. In a thermocline system, a thermal gradient is created and is ideally stabilized and preserved by buoyancy effects. As a result a stratiﬁcation of ﬂuid can be maintained in the storage system so that the hot ﬂuid remains at the top while the cold ﬂuid remains at the bottom [172]. An ideal thermocline model is shown in Fig. 9(a), which has an imaginary vertically movable perfect thermal insulation bafﬂe that prevent the mixing of hot and cold ﬂuids. A porous media packed bed thermocline thermal storage system can be applied. The presence of the ﬁller material aids in maintaining the gradient and reduces natural convection within the HTF [173]. 3.3.2. Sensible heat storage system (SHSS) Sensible heat storage system (SHSS) achieves thermal storage by raising the temperature of a sensible heat material (such as concrete, sand, rock, brick, soil, graphite, silicon carbide, taconite, cast iron, and even waste metal chips) [174]. All of the current CSP plants installed TES systems in commercial scales using sensible heat. Two types of one-tank SHSS undergoing extensive researches and studies are embedded structure system and packed bed system [175]. Embedded structure system is supposed to improve the heat transfer between storage material and HTF. For high temperature SHSS, concrete systems with an integrated tubular heat exchanger have been investigated by Laing et al. [176]. The HTF passes through embedded pipes in the storage concrete to transfer heat to concrete. Single unit and modular charging/discharging concrete storage concepts are also investigated [177,178]. Instead of using high heat conductive materials, the use of embedded heat pipes (HPs) or thermosyphons between a phase change material

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Fig. 9. Schematics of (a) An ideal sensible heat storage thermocline model system (© 2011 Li, Van Lew, Karaki, Chan, Stephens, O'Brien. Originally published in [166] under CC BY-NCSA 3.0 license. Available from: http://dx.doi.org/10.5772/20979), (b) A packed bed sensible heat storage thermocline system [184], (c) A three-part TES system combining sensible and latent storage charging process (adapted from Fig. 1 in [196]) and (d) A cascade latent heat storage system with 5 different PCMs (adapted from [197]).

(PCM) and the HTF are also explored to enhance the heat transportortation [179–182]. However, concrete can become fragile and easy to crack after a number of high temperature cycles of heat charging/discharging if it contains moisture. In order to overcome this disadvantage, Han et al. [183] proposed to use sand with high thermal conductive ﬂuid (XCELTHERM 600 thermal oil) instead of concrete. This method avoids issues of heat transfer degradation associated with the mismatch of thermal expansion of pipes and concrete, and this new thermal storage material can provide better heat transfer between HTF and thermal storage material. In a packed bed system, the bed consists of storage materials (rocks, ores, pebbles), a container and HTF, as shown in Fig. 9(b) [184]. This system can maintain the thermocline when low thermal conductive materials such as rocks are used. Most packed bed systems are single tank systems. Using a solid storage medium and the need of only one tank signiﬁcantly reduces the cost of this system [165]. The cost of a packed bed TES is only 2/3 of a two-tank system. One commercial example of the packed bed TES system is the Solar One pilot plant which uses Solar Salt as the HTF and quartzite and silica sand as the low cost ﬁller material [185]. Most of the experiments performed in a packed bed focused on developing the heat transfer correlations for different conﬁgurations and shapes of the particles that can be used for the thermal analysis of the system. A high temperature thermal storage system using a packed bed of rocks for air-based central receiver CSP plants was modeled and validated by Hanchen et al. [186]. According to their

study, the pumping power for a particle size of more than 10 mm was less than 1% of the power produced. Warekar et al. [187] described the results of simulations and experimental measurements of the heat exchanger, and discussed the scale-up options. 3.3.3. Latent heat storage system (LHSS) Latent heat storage is a nearly isothermal process that can provide signiﬁcantly larger storage capacity compared to sensible heat storage of the same temperature range. Isothermal storage is an important characteristic because solar ﬁeld inlet and exit temperatures are limited due to constraints of the HTF, solar ﬁeld equipment and Rankine cycle [188]. A major technology barrier limiting the use of PCM, however, is the higher thermal resistance due to low thermal conductivity [189]. As a result, a large heat transfer surface area between HTF and PCM is needed, and two approaches to increase the surface area are commonly used [190]. One apporach is the encapsulation of small amounts of PCM in spherical or cylindrical capsules [191], which can be arranged to form a packed bed. HTF ﬂows through the packed bed for energy delivery and extraction. PCM stored in capsules with a diameter of 10 mm has a surface area of more than 300 m2/m3[192]. The other approach is to embed the PCM in a matrix made of another solid material with high heat conductivity, and HTF pipes run through the PCM matrix [193,194]. The use of a matrix material (graphite or metal mesh) helps in enhancing heat conduction in the PCM.

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Fig. 10. Sizing strategies ﬂow charts for (a) Sensible thermocline TES system [165] and (b) Latent thermocline TES system [204].

3.3.4. Combined system and cascade latent heat storage system (CLHSS) In a traditional superheated steam Rankine cycle power block, it is desirable to minimize the temperature difference between the storage medium and HTF in order to reduce energy losses [195]. A three-part storage system demonstrated in Fig. 9(c) is proposed by

Laing et al. [196], where a PCM is deployed for two-phase evaporation in a CSP plant, while concrete storage is used for storing sensible heat, that is for preheating of water and superheating of steam. Laboratory test results of a PCM test module with 140 kg NaNO3, applying the sandwich concept for enhancement of heat transfer, provided the expected capacity and power density.

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Cascade latent heat storage systems (CLHSS) are one possible TES alternative, which is marked by a minimum of necessary storage material [165] as shown in Fig. 9(d) [197]. The use of a cascade of multiple PCMs shall ensure the optimal utilization of the storage material. A theoretical analysis based on a simpliﬁed optimization model of a CLHSS is presented by Aceves et al. [198]. For single charging and discharging processes, it is shown that a CLHSS yields exergetic advantages if operated in counterﬂow with respect to charging/discharging and if sufﬁcient heat transfer can be realized. Energy and exergy analysis of a thermal energy storage system employing multiple PCMs was developed by Domanski and Fellah [199]. It is shown that the exergy efﬁciency can be signiﬁcantly improved using multiple PCMs compared with a single PCM in a system. 3.3.5. Sizing strategies and cost The sizing of the storage tanks is necessary in order for the TES system to be integrated with the power generation block. This will highly depend upon the storage capacity required for the TES system, the operation time, operating temperature ranges and the thermal performance itself. Van Lew et al. [200,201] proposed to use the generalized charts of energy storage effectiveness to determine the size of sensible heat thermocline storage tank, and the sizing strategies are summarized in Fig. 10(a) [165]. The dimensionless 1D heat transfer governing equations were used and all scenarios of energy charge and discharge processes were also studied. It has been found that what can be provided through the analysis is a series of well-conﬁgured general charts bearing curves of energy storage effectiveness against four dimensionless parameters grouped up from the storage tank dimensions, properties of the ﬂuid and ﬁller material, and operational conditions. The generalized charts are applicable to general sensible heat thermocline TES systems. An accurate and efﬁcient model of latent heat thermocline system with encapsulated PCM has been proposed by Tumilowicz et al. [202], named as an enthalpy-based 1D transient model. The model was developed based on the work of Van Lew et al. [173] to include encapsulated PCM ﬁllers. The thermal resistance inside the encapsulated PCM is taken into account by incorporating the effective heat transfer coefﬁcient [203]. This model accurately describes the heat transfer and energy storage/extraction between HTF and the packed-bed solid ﬁller material and allows tracking of interfaces throughout the thermocline processes. Xu et al. [204,205] proposed a trial tank sizing strategy based on this enthalpy-based 1D transient model, and a trial storage tank volume is ﬁrst determined based on the cutoff temperature, below which the HTF will be returned to the solar ﬁeld to be reheated; and this trial storage tank volume will be used as a basis to ﬁnd a real storage tank volume that can satisfy the requirement of the cutoff temperature. The ﬂow chart of this volume sizing strategy is shown in Fig. 10(b). Yang and Garimella [206] and Bayón and Rojas [207] presented other sizing strategies, in which discharge efﬁciency was used to determine the storage tank size instead of cutoff temperature. Cost-effectiveness is one important criterion for selecting a thermal storage system. Pacheco et al. [208] presented a cost analysis of a packed bed thermocline system. Xu et al. [204] presented a rudimentary cost analysis to compare the cost of SHSS and LHSS, and concluded LHSS has 38–43% reduction of capacity cost than SHSS. 3.4. Heat receiver This section reviews overall designs of central heat receiver systems, and places more focus on the photothermal absorber materials that lie at the core of these systems. The receiver designs

can mainly be categorized into three types: (1) gas receivers, (2) liquid receivers, and (3) solid particle receivers. For each type of system design, a description of the working principle, current state-of-the-art development, and research needs are provided. The second part of this section provides a detailed review on the various types of photothermal absorber materials available to date. 3.4.1. Receiver system conﬁguration There are many factors in determining the optimal design of a central receiver. Among them, the thermal efﬁciency, ηth, represents the most important characteristic of a given system. This efﬁciency value, if maximized, plays a critical role in the over thermal-to-electric conversion efﬁciency of the entire CSP system. The thermal efﬁciency, ηth, is the ratio of the difference between the total solar power absorbed by the photothermal absorber and the heat loses to the total incoming solar radiation, and can be expressed in this form [209]: ηth ¼

αQ in Q loss εσF view T 4R þhðT R T amb Þ ¼ α ηf ield EDNI C Q in

ð1Þ

where α is the solar absorptance of the photothermal absorber, ε is the thermal emittance of the photothermal absorber, σ is the Stefan-Boltzmann constant (5.67 10 8 W/m2 K4), Fview is the radiative view factor from the absorber surface to the surroundings, TR is the absorber surface temperature (K), h is the convective heat transfer coefﬁcient, Tamb is the ambient temperature (K), ηﬁeld is the heliostat ﬁeld efﬁciency (including cosine losses, reﬂectance losses, and spillage), EDNI is the direct normal irradiance (W/m2), and C is the concentration ratio. Using the baseline values of an absorptance of 0.95, an ambient temperature of 20 °C, an annual heliostat ﬁeld efﬁciency of 0.6 [210], an average direct normal irradiance of 800 W/m2 [185], a convective heat transfer coefﬁcient of 10 W/m2 K [185], and a baseline radiative view factor of 1, the dependence of the receiver thermal efﬁciency on absorber surface temperature at a range of emittance values is calculated and presented in Fig. 11. From the predictions, it can be seen that at high temperatures reducing the radiative heat losses is crucial in keeping efﬁcient operation of a heat receiver system. 3.4.1.1. Gas receiver. Volumetric air receivers, small particle air receivers and tubular gas receivers are the three major types of gas receivers. They are discussed in details separately as follows: (1) Volumetric air receivers: The basic working principles of volumetric air/gas receiver systems are simple; a porous solid medium (e.g., porous ceramics) is used to absorb the concentrated sunlight, convert the optical energy to thermal, and then transfer the heat to the gas/air passing through it. The heated air/gas is then used to heat a separate working ﬂuid [211], charge a storage medium [136], or pass directly to a gas turbine. There are two basic types of volumetric air/gas receiver: (1) open-loop atmospheric receiver system for a Rankine cycle and (2) closed-loop pressurized receiver system for a Brayton cycle. Based on porous ceramic absorber, this type of system has been shown to reach 65% thermal efﬁciency at an outlet temperature of 550 °C, and a 54% efﬁciency at an outlet temperature of 730 °C [212]. In a twoslab selective receiver design, 90% efﬁciency was achieved at gas outlet temperature close to 730 °C [213,214]. This approach uses two panels of different absorbers to allow absorption of photons in a wider spectral range and reduction of heat losses by blocking and absorbing thermal radiations emitted as the absorber reaches its operating temperatures. The main issue associated with volumetric air/gas receiver designs is that the unstable ﬂow and non-uniform heating in

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Fig. 11. Receiver thermal efﬁciency versus absorber surface temperature at a range of emittance values.

the receiver can lead to overheating and local failures in the receiver material [215,216]. Current efforts in the research and development of gas receiver systems are placed in reducing the ﬂow instability by introducing uniform heating and lowering the porosity of absorber materials [217]. (2) Small particle air receivers: Originally proposed in the 1970s [218,219], this type of receiver design utilizes sub-micron particles suspended in air as the medium to absorb sunlight, convert it to thermal energy, and transfer the heat to the air surrounding them. Advantages of this type of system include large total particle surface area to increase solar absorption and low risk of thermal cyclic damage to the absorber material. Theoretical calculations have shown that a 700 °C air temperature and 90% efﬁciency can be reached when the operating parameters are optimized [220–222]. Current research in this area focuses on a solid–gas suspension system that allows for a desired solid concentration and temperature throughout the receiver domain. (3) Tubular gas receivers: With a potential of reaching a theoretical efﬁciency of 81%, tubular gas receivers work similar to the radiators used in most automobiles currently on the road. When integrated into a gas turbine system, the air/gas is pressurized by a compressor and distributed into parallel tubes where it receives the heat converted and transferred from the solar absorber material coated on the tubes. The heated air/gas then expands and is used to drive the turbine. This type of systems has been shown to be capable of reaching 43% efﬁciency, in practical, at an inlet and outlet temperatures of 600 °C and 800 °C, respectively. Current research and development in this type of systems has been focused in the area of reducing convective and radiative losses at higher temperatures, material and structural developments to reduce failures resulted from thermal cycles, as well as the use of carbon dioxide as the gas as it has been shown that CO2 Brayton cycles can reach thermodynamic efﬁciencies of greater than 50% in CSP applications [223–229].

3.4.1.2. Liquid receivers. Two major types of liquid receivers are tubular liquid receivers and falling-ﬁlm receivers, which are discussed as follows: (1) Tubular liquid receivers: Conceived in the 1970s and ﬁrst implemented in the 90s, the idea of using liquid state heat transfer media running through small-diameter pipes

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irradiated by sunlight to transport thermal energy from the photothermal absorber (coated on the pipes) to the heat storage or to the power block lies at the heart of the tubular liquid receiver designs [230]. This type of systems has been shown to be capable of reaching thermal efﬁciencies of close to 90% [231,232] when using high temperature working ﬂuids such as LiCl/KCl. Sharing similar design principles with the gas tubular type systems, the working ﬂuids in the liquid tubular systems, however, typically have much higher thermal conductivities and heat transfer coefﬁcients. As a result, higher incident ﬂux levels (above 1.5 MW/m2) and higher thermal efﬁciencies can be reached due to the reduced temperature gradient in the tubes and the associated thermal stresses. As the operating temperatures go beyond 600 °C, issues like decomposition, reactivity (corrosion) and leakage are encountered [233–235]. Current emphasis in the research and development of this type of systems are mainly in the areas of heat transfer ﬂuid development (please refer to the HTF section), high temperature corrosion and cyclic fatigue mitigation strategies [236,237]. (2) Falling-ﬁlm receivers: The working principle of this type of heat receiver relies on the direct or indirect exposure of a working ﬂuid to the photothermal energy as it ﬂows down an inclined wall as a liquid “ﬁlm”. This approach drastically reduces the requirements associated with pumping and plumping of the HTF, because the ﬂuid is directed to the top of the inclined surface and is pulled down the incline only by gravity. For the direct heating approach (also referred as Direct Absorption Receiver, DAR), photothermal absorber particles are suspended in the ﬂuid to collect sunlight and emit heat into the working ﬂuid in which they are suspended [238]. The location of the liquid ﬁlm can be on the interior (internal DAR) or exterior (external DAR) wall of the receiver and the heating of the ﬂuid can be done directly or indirectly. In the indirect heating implementation, the working ﬂuid ﬂows down the inclined photothermal absorber substrate surface and receives the heat as it travels down the surface [239]. For external DAR using molten carbonate salt, it has been shown to reach about 80–90% thermal efﬁciencies with heat transfer coefﬁcients about 3000 W/m2 K. In internal DAR cases, estimates of thermal efﬁciencies close to 95% have been predicted when rotating mechanisms are incorporated into the receiver to promote incidence and thermal uniformity [240]. A main concern with this type of receiver designs is that the falling ﬁlm in an external DAR system can become unstable and cause un-even thermal stresses. Recent efforts in the research and development of falling-ﬁlm receivers have focused mainly on internal DAR systems and have shown potentials of this implementation to reach high efﬁciencies at low start-up and maintenance costs [241–244]. 3.4.1.3. Solid particle receivers. Proposed in the 80s as an approach to increase operating temperature to above 1000 °C, this type of receivers uses the direct exposure to concentrated sunlight to heat up ceramic particles as they fall through the internal space of a receiver chamber [245]. The heat held by these particles is then stored or transferred to another working ﬂuid for the power cycle. Due to the “free-ﬂoating” nature of absorber particles that greatly reduces high stresses in components associated with storage and transport of working ﬂuids in ﬂuid-based receivers, this type of system is typically designed to have higher capacities (10 to 100 MW) [246]. Though most studies have been theoretical [247,248], and have shown that this type of systems can reach a thermal efﬁciency of up to 90%, the only experimental results currently available show a 50% efﬁciency and an increase of particle temperature of 250 °C from the inlet to the outlet without

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optimization. Current development in this type of receiver designs mainly focuses in the areas of increasing thermal efﬁciency by increasing solar concentration ratio and decreasing heat losses [249], optimization of particles with respect to packing density, heat capacity, resistance to sintering and thermal shock as well as corrosion [245]. The design aspect of the particle transport system and effective particle-to-working-ﬂuid heat transfer are under development now in light of increasing overall operation and thermal efﬁciency [250,251]. 3.4.2. High-temperature photothermal absorber materials The overall thermal-to-electric efﬁciency of CSP systems is bound by Carnot efﬁciency, and therefore, increasing the temperature of the power cycles sees beneﬁt in the overall conversion efﬁciency. Based on Eq. (1), the radiative losses of the absorber play a key role in determining the thermal efﬁciency of the photothermal absorber due to its 4th power dependence on absorber surface temperatures (4 600 °C). This dependence is clearly demonstrated in Fig. 11. It is, therefore, imperative that a photothermal absorber material with higher absorptance and low emittance be used in order to increase the thermal-to-electrical efﬁciency of CSP systems. An ideal selective absorber material for the CSP system not only needs to have high absorption in the spectral range with high concentrations of solar power and reﬂecting wavelengths with high amounts of blackbody radiation, but it also needs to be low cost and exhibit long-term chemical, physical, and thermal stability at their operating temperature. Here we review ﬁve groups of solar selective materials that are suitable for use as a mid- to hightemperature photothermal absorption application. This section provides a review on the working principles, current capabilities, as well as future research and development directions on these material groups. Five different material designs including intrinsic selective materials, semiconductor-metal tandems, multilayer absorbers, metal-dielectric composites, photonic crystals and nanostructured absorbers are separately discussed as follows: (1) Intrinsic selective materials: Intrinsic selective materials include some transition metals and semiconductors where the optical absorption is wavelength dependent, whereas in metals the absorption increases when the incident photon exceeds their plasmon frequency, in semiconductors their band gap determines the absorption. Though this type of materials is simple and easy to construct, they generally need structural modiﬁcation to be useful as there are no intrinsic materials that possess the ideal selectivity behavior for photothermal applications [252]. Among intrinsic materials with spectral selective absorption, tungsten (W) and copper sulﬁde (Cu2S) have selectivity beyond 2–5 μm wavelength and, with an anti-reﬂection coating, zirconium diboride (ZrB2), show reasonable spectrally averaged absorptance and emittance in the mid-temperature regime [252,253]. Intrinsic materials are in general used as a primary absorber in more complex absorber designs such as cermets. (2) Semiconductor-metal tandems: Owing to the electronic bandgaps of semiconductor materials, their absorption of incident photons is intrinsically wavelength selective. When backed with a metal, a photothermal absorber material can be constructed such that the photons with energy higher than the semiconductor bandgap are absorbed by it, while the lower energy photons pass through the semiconductor but are reﬂected back into space by the backing metal layer. When composed of proper materials, this type of absorber material system can obtain high spectrally averaged absorptance and low emittance [252]. Suitable semiconductors include silicon,

germanium, and lead sulﬁde, and an anti-reﬂection coating is typically used to address impedance mismatch on the airsemiconductor interface. Several semiconductor-metal tandems have been shown to be able to reach absorptance values between 0.79 and 0.89, and emittance values as low as 0.016, and 0.073 at 400 and 1000 K respectively by using silicon, germanium as the semiconductors and silver or aluminum as the backing metal [254–256]. (3) Multilayer absorbers: Stacks of alternating metal-dielectric thin layers can display increased absorptance in a range of wavelengths associated with the properties and dimensions of the constituent materials [252]. Resulted from the partial absorption in the metal layers and the multiple reﬂections at each metal-dielectric interfaces across the stack, this increased absorption can be used as the basic principle of a photothermal absorber material. Several examples have been used to show the potential of this type of approach. Materials including tungsten, titanium, aluminum are good candidates for metals, while dielectrics and high-band gap semiconductors such as silicon dioxide (SiO2), titanium dioxide (TiO2), magnesium ﬂuoride (MgF2), aluminum oxide (Al2O3), and silicon nitride (Si3N4) are good candidates to reach spectrally averaged absorptance values up to 0.97, and spectrally averaged emittance values of as low as 0.06 at temperatures as high as 450 °C [257–264]. These materials are in general not scalable as they are in general expansive to construct, complex, and prone to damage/failure under cyclic thermal loads. (4) Metal-dielectric composites: Metal-dielectric composites, or cermets, are typically made of metal particles dispersed in dielectric phases. An anti-reﬂection coating and a metal reﬂector backing are also typically incorporated into the device design with the cermet being the primary absorber. While a fair number of high-melting-temperature metals (such as copper, gold, nickel, molybdenum, chromium, cobalt and tungsten) are good candidates for the metal constituent, oxides such as silica, alumina and magnesia have shown potential to be used for forming usable cermets [265]. Whereas manipulation of the concentration, geometry, dimensions, and even orientation of the metal particle constituent in cermets has shown that noble metals can display desirable photothermal properties [266], the most widely used metal-dielectric mixture have been developed based on Cr–Cr2O3 and Ni–Al2O3 due mainly to their relatively low production and material cost at as respectable performance level of a spectrally averaged absorptance of 0.94 and a spectrally averaged emittance of 0.07 [267–272]. In addition to the tuning of performance of cermets from the changes in the metal constituent homogeneous concentration, geometry, and dimension, introducing heterogeneity into the material domain by introducing a gradient in the concentration of these properties can add another level of performance. This was ﬁrst demonstrated by either stacking two layers of cermets with different metal concentrations, or introducing a gradient in the concentration across a single layer cermet [273,274]. In doing so, the impedance mismatch between the anti-reﬂective coating and the cermet is reduced and the overall absorptance is increased. Through co-evaporation, platinum and alumina have been used to form a cermet layer with no metal at the AR coating-ermet interface, and completely metal at the cermet-back reﬂector interface, and have shown a measured absorptance and emittance values of 0.98 and 0.21 at 200 °C [275]. A double cermet design has also been proposed where an optimized Mo:Al2O3 composition combination of 0.34 and 0.53 has been shown to reach an absorptance of 0.955 and a normal emittance of 0.08 at 350 °C [276]. More recently, a four-layer cermet structure of tungsten and

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silica has been studied and optimized to show an absorptance of 0.979, and emittance of 0.042 at 400 K with a thermal efﬁciency of 0.843; and its potential in high-temperature applications where an absorptance of 0.945 and an emittance of 0.172 at a thermal efﬁciency of 0.756 can be obtained at 1000 K [277]. (5) Photonic crystals and nanostructured absorbers: In the simplest view, a photonic crystal is a periodic array of two or more materials with different dielectric constants. This allows a photonic bandgap to be formed where incident photons onto this periodic array is completely reﬂected for all angles and polarizations. The implication of using this type of material system in photothermal absorber designs is that an “ideal” solar selective material can be designed and obtained. An example of this type of surface is shown in Fig. 12 where a large array of tapered silicon nanowires is etched into a silicon surface to form a silicon nano-tip forest. This simple photonic crystal is easy to fabricate and scalable, and its spectral absorption selectivity shows strong dependence on the geometry and defect concentration [278]. In addition to 1-D grating type photonic crystals, 2D and 3D photonic crystals open the door to a new class of photothermal absorber materials with not only very high absorptance, but also extremely low radiative thermal losses. An array of holes in metal surfaces as a 2D photonic crystal has been shown to represent a feasible design. The emittance of such designs can be tuned to reach above 0.8 and 0.2 below and above the cutoff wavelength of 1.7 mm respectively, when an orthogonal array of rectangular cavities is made into a tungsten substrate [279–282]. When cylindrical holes arranged in either square or hexagonal arrays are made into tungsten surfaces, the emittance of the photonic crystal design can be tuned by optimizing the hole dimension, spacing, and depth to reach close to unity in the range of 750 nm and 1.3 mm with a sharp drop off to around 0.1 above the cutoff wavelength of 1.7 mm [283,284]. More recently, square arrays of pyramids and cones made on W and Mo have been demonstrated to show extremely high potential in maximizing absorption and minimizing radiative losses. By tuning the feature geometries and dimension, absorptance of near unity was achieved using tungsten nano-pyramids [285,286], while in the Mo micro-cones a spectrally averaged absorptance of 0.919 and emittance of 0.149 were calculated at 1000 °C [287]. Selective solar absorbers that are stable at high temperatures represent a critical part of reaching high thermal efﬁciencies in CSP applications. The ﬁve groups of material designs reviewed here represent possible approach to harness and converting photon energy in the sunlight into the thermal energy needed in the power cycle. Currently cermets has the most feasibility in that its ﬂexibility in design and performance as well as low production cost play an important part of the overall system implementation feasibility. However, photonic crystals have recently shown tremendous potential in going beyond commonly agreed upon theoretical efﬁciency limits [265], because of their unique ability to have optimized photon density of states that can result in complete suppression of thermal emission in all directions to allow thermal exchange with only the sun. This is particularly important because high thermal-to-electric conversion efﬁciencies are achieved at high operating temperature where radiative heat losses have strong effects. 3.5. Environmental impacts and commercial viability Environmentalists have recently criticized the world's largest CSP plant-the Ivanpah solar power facility in the U.S. – for inﬂuencing wildlife such as birds. It has been noted that birds are burnt

Fig. 12. SEM and optical images of a silicon nanocone-based 2D photonic crystal and its optical response under polychromatic exposure. (a) Reﬂectivity spectrum of straight silicon nanowires and that of silicon nanocones with the same length and base diameter as the straight wires. (b) Reﬂectivity spectra of silicon nanocone samples with similar geometry and dimensions but with different doping levels of phosphorous.

up in the sky and falling down continuously due to the high temperature heat beams focused towards the solar tower. The exact number of birds being killed at Ivanpah is still debated. Bright Source Energy, one partner invested on this CSP plant, estimated that 321 birds found dead in the ﬁrst six months operation, while some observers have argued the annual bird death number can be as high as 28,000 [288]. However, this number is still much lower compared to the hundreds of millions to billions bird death caused by collision with windows, vehicles and power lines [289]. Besides the effect to wildlife, the glare coming from the solar tower due to the concentrating solar beams will also cause visual effects on humans and it could interfere with aircraft operations, if reﬂected light beams become misdirected into aircraft pathways. CSP systems employ several hazardous materials such as organics, thermal oils, molten-salts, hydraulic ﬂuids, coolants and lubricants, which may pose spill risks. Proper planning and good maintenance practices must be followed in order to minimize the environmental impacts from these hazardous materials. Especially the organic Biphenyl/Diphenyl oxide pair used in CSP systems is highly toxic, which has potential to catch ﬁre and also can

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contaminate soils leading to environmental problems [290]. Furthermore, use of Solar Salt as HTF and/or storage medium leads to emissions of nitrous oxide (N2O). This is not negligible since N2O is 300 times stronger than CO2 as a greenhouse gas [290]. However, the amount of emission is roughly 500–1000 times smaller than the CO2 emissions in a similar coal power plant. The other important issue with the CSP systems is the commercial viability. In 2009 the capital cost of a CSP plant is typically about 12–18 C\ t\\vskip\ tˈ per kW h [7]. The cost is expected to reduce by at least half in the near future due to technology improvement in heliostat mirrors [291]. The European Academics Science Advisory Council estimated the LCOE-which includes the initial capital, discount rate, as well as the costs of continuous operation, fuel and maintenance-of different technologies in 2010 [290]. LCOE of 100 MW CSP without heat storage in Phoenix, Arizona (DNI¼ 2500 kW h/m2/year) were reported to be 23 C\ t\\vskip\ tˈ/kW h. Lower LCOE was expected in MENA area because the DNI is about 5% higher. As comparisons the LCOE of 150 MW PV (Arizona), 100 MW onshore wind and 400 MW offshore wind were reported to be 28, 11 and 20 C\ t\\vskip\ tˈ/kW h, respectively. However, studies also showed that the cost was expected to reduce by around 60% in future due to mass production and technology innovations in HTFs, high-temperature storage and thermodynamic cycles [292]. The cost of CSP is predicted to achieve 50% reduction between 2021 and 2031, which suggests cost competitiveness of CSP with fossil-ﬁred generation in 10–20 years [15]. The SunShot Initiative of the U.S. DOE aims to accelerate research, development and large scale deployment of solar technologies in the US in order to make sure the solar power is commercially viable and economical for the energy needs of the country. The ultimate goal of the SunShot Initiative program is to reduce the cost of CSP electricity by 75% at the end of this decade, aiming to have baseload energy rates to be 6 C\ t\\vskip\ tˈ/kW h without subsidies [293]. This cost reduction will pave the way for large scale adoption of solar electricity across the United States.

4. Conclusions The CSP systems and their components are being developed with a focus on performance, reliability and cost as evident from thousands of research publications through sustained, long-term investments by various agencies like US DOE's SunShot program along with industry partners. Even though four different CSP technologies (PTC, LFR, SPT and PDS) are being explored, the solar power tower based systems are gaining major attention as evident from the world's largest utility scale Ivanpah CSP systems (392 MW) commissioned in the USA in 2014. The projection is clear in identifying the sites with relatively high direct normal irradiance for large scale CSP systems and accordingly the Middle East, North Africa, Australia, Southwestern of the United States, Spain, Southwestern of China and China/Mongolia border and India have good potential. The challenging components identiﬁed are water requirement, heat transfer ﬂuid, thermal energy storage subsystems for developing highly reliable CSP systems with operating temperatures above 800 °C. In addition, there are also issues related to sustaining the CSP performance due to soiling which is similar to the large scale PV systems and technologies are being developed to keep the mirrors clean with minimum use of water in the desert locations. The water scarcity problem in arid region can possibly be solved by dry cooling or CSP-desalination cogeneration technologies. Molten-salt mixtures are the most promising high temperature HTF candidates so far due to their high thermal stability temperatures and properties similar to steam at high temperatures. TES is already in the commercial

application stage and LHSS is expected to dominate in future. Environmental impacts of the CSP systems are minor and the commercial viability is promising. By developing and deploying more efﬁcient CSP systems, the sun's free and clean energy can be harnessed to power homes, businesses, and communities across the country with reduction in harmful carbon pollution for keeping the air and water cleaner for the future generation.

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Prospects and problems of concentrating solar power technologies for power generation in the desert regions

Prospects and problems of concentrating solar power technologies for power generation in the desert regions

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