A review of concentrated solar power hybrid technologies

A review of concentrated solar power hybrid technologies

Accepted Manuscript A review of concentrated solar power hybrid technologies Santanu Pramanik, R.V. Ravikrishna PII: DOI: Reference: S1359-4311(17)32...

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Accepted Manuscript A review of concentrated solar power hybrid technologies Santanu Pramanik, R.V. Ravikrishna PII: DOI: Reference:

S1359-4311(17)32268-8 http://dx.doi.org/10.1016/j.applthermaleng.2017.08.038 ATE 10920

To appear in:

Applied Thermal Engineering

Received Date: Revised Date: Accepted Date:

5 April 2017 6 August 2017 7 August 2017

Please cite this article as: S. Pramanik, R.V. Ravikrishna, A review of concentrated solar power hybrid technologies, Applied Thermal Engineering (2017), doi: http://dx.doi.org/10.1016/j.applthermaleng.2017.08.038

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1 A review of concentrated solar power hybrid technologies Santanu Pramanik, R V Ravikrishna* Department of Mechanical Engineering, Indian Institute of Science, Bangalore, India Abstract This paper reviews the hybrid power generation technologies of concentrated solar power (CSP) and other renewable and non-renewable resources such as biomass, wind, geothermal, coal, and natural gas. The technologies have been categorized into high, medium, and low-renewable hybrids based on their renewable energy component. The high-renewable hybrids report the least specific CO2 emissions (< 100 kg/MWh), followed by the medium (< 200 kg/MWh) and low-renewable hybrids (> 200 kg/MWh). The hybrids have been compared based on their plant characteristics and performance metrics using data from the literature and of actual hybrid power plants. The low-renewable hybrids such as ISCC, solar-Brayton, and solar-aided coal Rankine power systems are technologically mature and offer superior performance over the high and medium-renewable hybrids. The medium renewable hybrids such as solar plants with natural gas backup offer high solar share but suffer mostly from low efficiency and high cost that hinders their market penetration. The high-renewable hybrids such as CSP-wind, CSP-biomass, and CSP-geothermal have minimum negative impact on the environment. However, several parameters such as energy efficiency, solar-to-electricity efficiency, capacity factor, and cost effectiveness need to improve for these systems to be competitive. Keywords: Concentrated solar power, hybrid, biomass, wind, geothermal, coal, natural gas

* Corresponding author: [email protected]

2 1. Introduction Solar radiation is the most promising renewable energy source that can displace fossil fuels and meet our future energy demands. The massive use of fossil fuels in the past century has led to an unprecedented rise in greenhouse gases, resulting in global warming and climate change [1]. Apart from climate change, burning of fossil fuels has added costs associated with human and ecosystem toxicity, acidification of land, particulate formation and freshwater eutrophication [2]. The Paris Climate Agreement [3] that has recently come into force is a major step in the direction of mitigating these effects. Hence, countries are increasingly looking towards renewable sources to meet their energy requirements and to reduce their carbon footprint. Powering the world by renewable sources such as solar, wind, and water by the year 2050 is feasible, but requires large-scale expansion of the transmission infrastructure, sensible policy deployment, and major changes in the social and political landscape [4][5]. The interconnection of these resources at the grid level will reduce fluctuations in the supply. An alternate scenario, in which the renewable energy technologies are hybridized at the power plant level, can overcome several outstanding challenges while providing a boost to distributed power generation, energy autonomy and faster realization of energy sustainability. The optimal path to realizing this transformation to renewable energy resources may finally be a combination of both the strategies: integrating geographically dispersed variable energy resources through expansion of the transmission grid while hybridizing co-located renewable resources at the power plant level to improve efficiency, cost-effectiveness and ensure energy autonomy. In this context, research and development of hybrid solar energy technologies have assumed more significance than ever. This paper is an attempt to review the major hybrid technologies involving concentrated solar power (CSP),

their

current

state-of-the-art,

their

comparative strengths

recommendations for future research.

* Corresponding author: [email protected]

and

weaknesses,

and

3

Figure 1: Map of the yearly averaged downward surface solar radiation reaching the surface (W/m 2) [4].

Solar energy can be harnessed in most parts of the world due to its distributed nature (Figure 1). The working of a CSP plant is similar to conventional power plants in terms of usage of a power cycle, working fluid, turbines, etc., where the fossil fuel is replaced by solar energy. A CSP system can provide power similar to a conventional plant [6], although the intermittency of solar radiation (Figure 2 and Figure 3) presents several challenges. This intermittency results in low plant capacity factor (~ 23-50%) [7] and efficiency (~ 15-30%) [8] for standalone CSP plants, thereby increasing the investment and cost of electricity. With technological advancements, such as the addition of thermal energy storage systems and hybridization, it is estimated that CSP can become costcompetitive with natural gas around the year 2020 and with coal-based power by around 2025 [9]. The Gemasolar solar plant with 15 hours of energy storage and 15% hybridization with natural gas can operate at 74% capacity factor [10], close to that of conventional power plants. Hybridization will also enable CSP plants to be established in regions with moderate direct normal irradiation (DNI ≥ 1700 kWh/m2/year), thereby moving it away from dry arid regions and closer to load centers [6]. In a future where CSP plants become a key supplier of dispatchable energy, hybridization seems inevitable. Hence, the purpose of the present work is to review the most important CSP hybrid technologies currently available.

* Corresponding author: [email protected]

4

21st March

21st June 1200

900

DNI (W/m 2)

DNI (W/m 2)

1200 Daggett

600 300

Sevilla

900

600 300 0

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12 H our

18

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21st Sept.

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21st Dec.

Ahmadabad

900

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1200

12 H our

600 300

900

Antofagasta

600 300 0

0

0

6

12 H our

18

0

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12 H our

Figure 2: Hourly variation of DNI (W/m2) on four different dates at representative locations of four different continents, namely, Daggett in the USA, Sevilla in Spain, Ahmadabad in India, and Antofagasta in Chile. The profiles have been obtained from the Solar Advisor Model (SAM), NREL [11]. 500

DNI (W/m 2)

Daggett 400

Sevilla

300 200 Antofagasta

100

Ahmadabad 0 0

2000

4000

6000

8000

10000

H ours

Figure 3: Variation of monthly averaged DNI (W/m2) at representative locations of four different continents, namely, Daggett in the USA, Sevilla in Spain, Ahmadabad in India, and Antofagasta in Chile. The profiles have been obtained from the Solar Advisor Model (SAM), NREL [11].

Hybrid plant configurations involving CSP that simultaneously use solar energy and fossil fuel have been reviewed by Sheu et al. [8]. The authors have classified the solar-fossil fuel hybrids into three broad categories such as the solarized gas turbines, combined cycles, and solar reforming. The authors have also proposed a linear combination metric for comparison of the hybrid plants with the currently operational power plants. Behar et al. [12] have reviewed integrated solar combined cycle (ISCC) systems that use parabolic trough (PT) technology. This work reports the current status of such systems in terms of performance, configuration, and future directions of research and development. * Corresponding author: [email protected]

5 The authors have reported that direct steam generation parabolic trough (DSG-PT) technology offers better performance compared to the best heat-transfer-fluid parabolic trough (HTF-PT) technology in terms of efficiency, electricity cost and greenhouse gas (GHG) emissions. They also state that the ISCC plants would become competitive with conventional combined cycle power plants with a gradual increase in the price of the fossil fuels. Jamel et al. [13] have reviewed the integration of solar energy with conventional (combined cycles, steam Rankine cycles, and gas Brayton cycles) and nonconventional power plants (geothermal). The authors concluded that the ISCC plants offer technical and economic advantages over other hybrid configurations. Peterseim et al. [6] have tried to determine the most promising CSP technology for hybridization with Rankine cycle power plants using fuels such as coal, natural gas, biomass, and waste materials. The authors report that Fresnel reflectors perform best in the low-temperature category (< 400 °C) due to low land usage and cleaning water consumption.

This is followed by parabolic trough technology. In the high-temperature

category (> 450 °C), solar towers offer the best performance. In another study, Peterseim et al. [14] have analyzed the hybridization of CSP with coal, natural gas, biomass, geothermal and wind for Australian conditions. They have categorized the systems into light, medium and strong hybrids depending on the level of integration and synergy between the technologies. The authors report that the cost of a hybrid plant can be 50% lower in comparison to standalone CSP plants. However, there are no studies currently that review and compare all CSP hybrid technologies present in the literature and the present work attempts to address this gap. The present study performs an in-depth assessment of CSP hybridization with other energy sources such as coal, natural gas, biomass, geothermal, and wind. Among the CSP technologies, parabolic trough, linear Fresnel, and solar tower technologies have been considered. In the following sections, the individual hybrid technologies will be reviewed and their performance characteristics will be explored. This will be followed by a comparison of the hybrid systems based on system characteristics and performance metrics such as specific CO2 emissions, capacity, capacity factor, specific investment, cost of electricity (COE), solar share, energy efficiency, exergy efficiency, and

* Corresponding author: [email protected]

6 solar-to-electricity efficiency (S-E η) [8]. Finally, the insights obtained from the comparative analysis will be used to make recommendations for future research in these areas. 2. Hybrid technology categories Since the primary objective for using renewable technologies such as CSP is sustainability and pollution reduction, the hybrids have been classified based on the renewable component of the generated power. While hybrids of CSP with wind, biomass and geothermal are expected to have the least environmental impact, the impact of non-renewable hybrids on the environment will depend on its solar share. Hence, the hybrids have been categorized into three broad divisions based on their renewable energy component: (a) High – hybrids of CSP with wind, biomass, and geothermal energy resources. This category has the highest potential in decelerating global warming and climate change. (b) Medium – this category includes solar plants that use supplementary firing of fossil fuels such as natural gas to enhance the plant output and capacity factor. Examples of this category include SEGS II-IX in Mojave Desert, California [15] that uses natural gas backup for evaporation and superheating. The use of backup fossil fuel in such plants is limited to 12-15% in Spain, and to 25% in the US [10]. (c) Low – this category represents conventional fossil fuel plants that incorporate solar energy for auxiliary functions such as preheating, evaporation, etc. This category includes ISCC plants, solaraided coal power plants, and solar Brayton cycles. The solar share in such plants is usually less than 20%. 3. Review of hybrid technologies This section will review the existing literature on the various CSP-hybrid technologies suitable for power generation. The application of such hybrids for other purposes such as heating and cooling, polygeneration, etc. will be reviewed only briefly.

* Corresponding author: [email protected]

7 3.1. High renewable hybrids As discussed in the previous section, these hybrids are formed by integrating CSP with other renewable sources of energy. 3.1.1. CSP-biomass hybrid Biomass provides a promising renewable extension to CSP plants for continuous operation. Several regions in the world have biomass and solar resources suitable for hybridization (Figure 4). The potential number of locations for CSP-biomass hybridization is improved if multiple feedstocks are considered, although the initial investment is higher. Although CSP-biomass hybridization is in the nascent stages, a number of feasibility and technology assessment studies have been conducted for countries such as India [16], Brazil [17][18], Indonesia [18], Australia [14][19][20] and Europe [21]. The global warming potential (GWP) of such a hybrid can be up to 10 times lower than that of CSP plants with non-biomass extensions [18]. Also, it can provide greater penetration to both CSP and biomass-generated power into the market compared to standalone CSP and biomass plants.

Figure 4: Potential regions for CSP-biomass hybrid plants worldwide [22].

Combinations of CSP and biomass technologies Various hybrid combinations of CSP and biomass technologies offer distinct advantages in terms of efficiency and cost. Several hybrid systems (Table 1) have been studied by Peterseim et al. [23]. The maximum energy efficiency of 33.2% is obtained for solar tower and gasification, whereas Fresnel

* Corresponding author: [email protected]

8 and fluidized bed offer the lowest specific investment ($/MWe). The efficiency difference between the 17 combinations is 13%, while the difference in the specific investments is 31%. Table 1: Comparison of various CSP-biomass hybridization schemes [23]. Exchange rate: 1 AU$ = 0.74 US$

CSP technology

CSP working fluid

Biomass technology

Peak net efficiency

Specific investment

(%)

(m$/MWe)

Parabolic trough

Thermal oil

Grate

29.3

4.96

Parabolic trough

Thermal oil

Fluidised bed

29.5

4.88

Parabolic trough

DSG

Fluidised bed

30.3

4.74

Fresnel

DSG

Fluidised bed

30.4

3.55

Parabolic trough

DSG

Fluidised bed

31.5

4.59

Fresnel

DSG

Fluidised bed

31.5

3.4

Solar tower

DSG

Fluidised bed

31.5

3.85

Parabolic trough

Molten salt

Fluidised bed

32.2

4.59

Fresnel

DSG

Fluidised bed

32.5

3.33

Solar tower

DSG

Fluidised bed

32.5

3.77

Solar tower

Molten salt

Fluidised bed

32.3

3.85

Parabolic trough

Molten salt

Fluidised bed

32.7

4.59

Solar tower

DSG

Fluidised bed

33.0

3.7

Solar tower

Molten salt

Fluidised bed

32.8

3.85

Parabolic trough

Molten salt

Gasification

32.8

4.59

Solar tower

DSG

Gasification

33.2

3.7

Solar tower

Molten salt

Gasification

32.9

3.85

Plant capacity The selection of capacity for CSP-biomass hybrids is critical as the scaling of cost with plant size follow reverse trends for standalone CSP and biomass plants [18]. A capacity of at least 50 MWe is recommended for CSP plants as they incur high initial investment. Contrarily, the capacity of biomass plants is restricted below 50 MWe due to the increased logistical costs of biomass transportation. A small size plant receives a continuous supply of biomass, although at the expense of a reduction in efficiency (Figure 5). A minimum capacity of 5 MWe is recommended for biomass plants to obtain economy of scale benefits [14]. Peterseim et al. [19] report that several locations in Australia can * Corresponding author: [email protected]

9 support 5-25 MWe hybrid plants, while some others can support 50 MWe and higher capacity plants. A similar case study for a 30 MWe hybrid plant combining biomass with molten salt solar tower system and 3 hours of storage has been reported for Griffith, Australia [20]. The first operating commercial CSP-biomass hybrid plant, the Termosolar Borges, has a capacity of 22.5 MWe. However, lower capacity plants in the range of 2-10 MWe are possible in the case of trigeneration systems. Nixon et al. [16] recommend trigeneration as an efficient choice for CSP-biomass hybrids under Indian conditions.

Efficiency (%)

36

32 Forestry residues Bagasse Urban wood waste Refuse derived fuels Stubble

28 24 20

0

10

20 Power (MWe)

30

40

Figure 5: Variation of net cycle thermal efficiency of solar-biomass hybrids with power output for different biomass feedstocks [19].

Installation cost The installation cost for CSP-biomass hybrids is lower than standalone CSP with similar power output. Also, the specific investment decreases with an increase in the plant capacity (Figure 6). Significant cost reduction of the order of 50% is possible with CSP-biomass hybridization [14]. Other authors have reported a 43% and 69% reduction in investment compared to a standalone CSP system [20][23]. In comparison to a biomass-only plant, hybridization reduces the biomass demand and consequently decreases land usage by 14 – 29% [16]. But, the decreased demand for biomass and land could not offset the increased initial investment due to the high cost of CSP. The investment can be reduced significantly by local production of CSP components and through advancements in technology. Currently, the installation cost of CSP-biomass hybrids is greater than biomass-only

* Corresponding author: [email protected]

10 plants but less than standalone CSP, which makes the hybrid systems commercially viable. Hybridization also provides an affordable way to dispatch CSP in locations where the electricity price is traditionally low due to large fossil fuel reserves [20].

Specific investment (m$/MWe)

6

Forestry residues Bagasse Urban wood waste Refuse derived fuels Stubble

5.5 5

4.5 4

3.5 3

0

20

40

60

80

Power (MWe)

Figure 6: Variation of specific investment of solar-biomass hybrids with power output for different biomass feedstocks [19]. The regions selected receive DNI > 21-24 MJ/m2/day. Exchange rate: 1AU$ = 0.74 US$.

Cost of electricity The cost of electricity (COE) of CSP-biomass hybrids in India is currently greater than that of a commercial CSP by a factor of two and coal-fired power plant by a factor of four [16]. The COE is also higher in comparison to standalone biomass plants. However, the COE may be comparable if the price of biomass increases by 1.2 – 3.2 times or the cost of solar technology decreases by 47.7 – 98.5% [16]. A scenario such as this is likely in the future owing to the rising biomass prices and advancements in CSP technologies. For Indian conditions, the cost of grid expansion is higher than the establishment of CSP-biomass hybrids. Local outsourcing of biomass can significantly reduce the logistical costs and reduce the COE in comparison to a centralized system that charges higher for distant locations due to transmission and distribution losses. Novel schemes for hybridization Various novel schemes have also been proposed in the literature for CSP-biomass hybridization. Tanaka et al. [24] have analyzed the performance of a combined cycle consisting of a bubbling

* Corresponding author: [email protected]

11 fluidized-bed gasifier and a solar-tower system. The gasifier supplies to the topping gas turbine cycle whereas the solar tower and the gas turbine exhaust supplies to the bottoming Rankine cycle. A peak thermal efficiency of 36.7% has been obtained for the system. Peterseim et al. [20] have analyzed the performance of a 30 MWe hybrid plant with a solar tower and biomass boiler (vibrating grate), each with a capacity of 15 MWe. The maximum cycle efficiency obtained at peak load is 33.4%, while the efficiency with only the biomass boiler was 30.2%. A hybrid power plant combining parabolic trough and biomass boiler supplying to a steam turbine has been studied by Srinivas et al. [25]. The addition of solar energy increases the plant fuel efficiency (which is the ratio of the work output to the fuel energy input, in this case, biomass) from 15% to 32% while decreasing the thermal efficiency from 15% to 11% due to the low efficiency of the solar reflectors [25]. A couple of recent studies [26][27] have proposed a novel solar cycle incorporating a biomass gasifier, a solar tower system, and a supercritical CO2 Brayton cycle. A maximum cycle thermal efficiency of 40.8% is estimated in this hybridization scheme. An exergetic analysis reveals that maximum exergy destruction occurred in the gasifier, followed by the combustion system (Figure 7). Peterseim et al. [22] have investigated the concept of using biomass for superheating the steam generated from a 50 MWe parabolic trough system with 7.5 hours of thermal energy storage. The concept is also feasible in regions with small biomass resources and would provide higher conversion efficiencies compared to the installation of small-scale standalone biomass plants. The superheating increases the overall hybrid plant efficiency that can lead to the decrease in CSP cost by upto 23.5%. Liu et al. [28] have analyzed two hybrid combined cycles where the solar energy is utilized either for gasification of biomass or preheating of the compressed air. The solar gasification system offers better performance in terms of energy (ηI = 29.4%) and solar-to-electricity efficiency (S-E η = 18.5%) in comparison to the air preheating configuration (ηI = 28% and S-E η = 15.1%). The scope of CSP-biomass hybrids for polygeneration under Indian conditions has been analyzed by Sahoo et al. [29]. Thermodynamic and economic analysis of a solar aided sugarcane bagasse cogeneration plant has been performed by Burin et al. [30][31]. The hybridization led to an increase of annual electricity production in the range of 1.319.8%.

* Corresponding author: [email protected]

12

Percentage of input exerg y

30

25 20 15 10 5 0

Figure 7: Exergy destroyed in individual components as a fraction of the input exergy. The exergy lost in the exhaust is 8.72% of the input exergy. The gasifier is operated at Tg = 1073 K with biomass containing 20% moisture [26].

Challenges Several challenges need to be addressed before CSP-biomass hybrid plants are implemented extensively. Most of the CSP plants around the world are located in areas with DNI > 20 MJ/m2/day. The number of locations that simultaneously have large biomass resources suitable for hybridization is less. The use of cultivable land for the growth of high energy crops for utilization as biomass has given rise to the food versus fuel debate. Recent developments in the use of cellulosic biomass for energy production have alleviated some concerns. Increasing climate change concerns have also created uncertainty in the production and supply of biomass. For the construction of any biomass/hybrid plant, a steady supply of fuel for an average plant lifespan of 25 years needs to be ensured. Finally, with the current technological capability, only 30% of the electricity is produced by solar energy in a CSP-biomass hybrid for a rated steam flow rate (tonnes/h) [23]. A higher storage capacity (7 hours considered in the analysis) can increase the solar share above 30%. Operational plant Inspite of these challenges, the first and the only commercial CSP-biomass plant has been operational in Spain since 2012 [32][33][34]. It has a capacity of 22.5 MWe and is supplied by 2 × 22 MW thermal biomass units operating on waste forest biomass and energy crops. The operational

* Corresponding author: [email protected]

13 experience obtained from this plant will be valuable in the development of newer CSP-biomass hybridization strategies. The details of the plant are shown in Table 2 and Figure 8. Table 2: Details of the Termosolar Borges plant [32][33].

Background Technology

Parabolic trough-biomass

Status

Operational

Country

Spain

Power

22.5 MWe

Land area

96 hectares

Electricity generation

98000 MWh/year (estimated)

Cost (approx.)

153 million euros

Start date

December 2012

Receiver type

Evacuated tube parabolic trough

Heat transfer fluid (HTF)

Dowtherm A

Technology

HTF inlet temperature

C

HTF outlet temperature

C

Power cycle

Steam Rankine

Turbine efficiency

37% at full load

Backup type

Biomass (2 x 22 MWt)

Storage

None

Summary In summary, we observe that several combinations of CSP and biomass technologies can be hybridized that offer distinct cost and efficiency advantages. The capacity of these plants is restricted between 5-50 MWe due to the considerations of cost and the steady supply of biomass. Currently, the cost of these hybrids lies in between standalone biomass and CSP plants. The cost of electricity is also higher compared to standalone systems, which can change with an increase in the cost of biomass or a decrease in the cost of CSP components. Several novel schemes are being proposed in the literature that can overcome some of the current challenges and make this hybridization economically feasible.

* Corresponding author: [email protected]

14 A summary of the key parameters and performance metrics of selected studies on CSP-biomass hybrids is presented in Table A1 in the Appendix.

Solar field Turbine

Superheater Vaporizer

Condensor

H TF

Biomass Boiler

Cooling tower

Preheater

Figure 8: Termosolar Borges power plant in Spain [32][34][35][36].

3.1.2. CSP-geothermal hybrids Geothermal energy is another renewable resource that holds promise for hybridization with CSP. Geothermal plants use the thermal energy beneath the earth’s surface to generate electricity. Depending on the temperature and type of the geothermal resource, several modes of utilization are possible. Geothermal wells that produce dry steam can be used directly in a turbine to generate power. Flash systems use hot water at high pressure to generate steam in a flash chamber that can drive the turbine. Flash geothermal systems are the most common type of geothermal power plants. The third type of plants uses the low-temperature geothermal resource to generate vapors of an organic fluid with a low boiling point. Such systems are referred to as binary geothermal plants and run on an organic Rankine cycle (Figure 9). Data corresponding to operational and planned geothermal plants worldwide have been compiled elsewhere [37][38].

* Corresponding author: [email protected]

15 Geothermal plants operate at base load with high capacity factors due to the continuous supply of energy. However, the low temperature of the resource (~ 150 °C – 200 °C) results in reduced power plant efficiency (~12%) [37] that increases the specific installation cost. The output from a geothermal plant also decreases with increase in the ambient temperature (Figure 9). The gradual depletion of a geothermal well reduces the power output of the plant over time. Hybridization with CSP (≥ 380 °C) can overcome some of the challenges currently faced by standalone geothermal and CSP plants.

(a)

T ( C)

Net power (MW)

(b)

S (kJ/kgK)

Tamb ( C)

Figure 9: (a) T-s diagram of an organic Rankine cycle with recuperation showing the various state points and operating conditions [39], (b) Reduction in power output from a geothermal plant with an increase in ambient temperature [39].

Integration schemes Several integration schemes have been reported for the hybridization of CSP with geothermal energy (Figure 10). The two most common integration schemes are, (a) preheating of the geothermal brine using solar energy, and, (b) superheating of the steam by solar energy before entering the turbine. The preheating configuration is the simplest in terms of retrofitting to an existing geothermal power plant [40]. No significant modifications in the operation and control of the plant are necessary as the CSP raises the brine temperature close to the design point of operation. This also addresses the issue of the decline in geothermal-well productivity with time. However, the utilization of solar energy at a lower temperature in this configuration leads to exergy destruction and reduces the solar-to-electricity efficiency of the plant. The superheating configuration offers higher solar-to-electricity efficiency due to high-temperature solar energy input into the working fluid before the turbine. This also raises the

* Corresponding author: [email protected]

16 overall plant energy and exergy efficiency. The retrofit cost in such a configuration is significantly higher due to substantial changes in the power block operating conditions and control strategies. Preheating

Superheating

Figure 10: Integration schemes for CSP-geothermal hybridization [40].

Output characteristics The integration of solar energy modifies the output characteristics of a geothermal plant. Several such results have been reported in a study by Turchi et al. [40][41] which has analyzed the integration of parabolic trough collectors into a binary geothermal plant. The hourly output of a standalone geothermal plant decreases as the ambient temperature increases with the progress of the day. However, the daily electricity demand curve shows the opposite trend. The addition of CSP can address this issue as its output increases with a rise in the ambient temperature (Figure 11a). The monthly power output of a hybrid system is also higher and smoother compared to a standalone geothermal plant (Figure 11b). The annual decline in power output due to a decrease in the temperature of the geothermal well is suitably modified by hybridization (Figure 11c). The authors have also reported that the solar-to-electricity efficiency of the plant increases with a decrease in both the geothermal well temperature and the ambient temperature for a constant solar heat input (Figure 11d). The increase in the plant thermal efficiency is attributed to the operation of the plant closer to the design point due to hybridization.

* Corresponding author: [email protected]

17

(a)

(b)

(c)

(d)

Figure 11: (a) Hourly comparison of power output from a standalone geothermal plant and a hybrid plant [40], (b) Effect of geothermal resource temperature decline on the base and hybrid plant monthly power generation [40], (c) Effect of geothermal resource temperature decline on the base and hybrid plant annual power generation [40], (d) Variation of the solar to electricity efficiency of the hybrid plant as a function of the geothermal well temperature and the ambient temperature [40]. The solar energy input is 25% of the geothermal plant design input.

Solar field size The selection of the solar field size is critical in determining the hybrid plant performance. The influence of the solar field size on the performance of the hybrid plant has been reported by Zhou et al. [42][43][44] under the climatic conditions of Australia and New Zealand. In these studies, the parabolic trough system is used to superheat the working fluid before entering the turbine. The results show that the solar fraction in the system increases with increase in the collector area, but decreases with increase in the geothermal temperature (Figure 12a). This can be attributed to the reduction in usage of geothermal energy as the temperature of the well decreases, which is compensated by a higher solar fraction. Again, at a constant geothermal temperature, a rise in the solar fraction increases the net power output of the plant (Figure 12b). The type of operation strategy also has a significant influence on the power output. Overall, a net exergy efficiency of 12.4% was reported by the authors. The annual output of the hybrid plant was 73.6% higher than that of the standalone geothermal plant. * Corresponding author: [email protected]

18

(b)

Solar energy fraction

Net electrical power output (kW)

(a)

Solar aperture area (m2)

Solar energy fraction

Figure 12: (a) Determination of the solar energy fraction as a function of solar aperture area at various geothermal reservoir temperatures (Tair = 31 °C; design-point solar DNI = 1000 W/m2) [43], (b) Net electrical power output as a function of the solar share for various operation strategies [43].

Cost of electricity The cost of electricity (COE) is highly sensitive to the capital cost of the solar field (Figure 13). At low prices of the solar field, a higher solar share reduces the cost of electricity. The opposite trend is observed when the specific cost of the solar field is high. A low solar share is recommended in such cases to make the COE competitive with the base plant. Zhou et al. [43] have reported that the COE for a hybrid plant (171$/MWh) was 23% less than that of the standalone geothermal plant (225$/MWh). Thus, a properly designed hybrid plant can become economically superior to that of two standalone plants. Escobar et al. [45] have also reported a reduction in COE (56.89$/MWh) due to hybridization. However, Manente et al. [46] have reported that the COE of a hybrid system (180190 $/MWh) is much greater than that of a standalone geothermal only plant. Similar observations have been made by Ghasemi et al. [47]. This shows that the COE is highly sensitive to the location and the availability of resources.

* Corresponding author: [email protected]

19

Figure 13: Cost of electricity as a function of the solar field capital cost [40].

Novel schemes and other studies Several other studies have been conducted on CSP-geothermal hybridization for power generation. A brief analysis of the feasibility of CSP-geothermal hybrids in Australia has been reported by Peterseim et al. [14]. The analysis showed that the power output of the standalone geothermal plant increased from 6.3 MWe to 8.4 MWe for parabolic trough hybrid and 9.9 MWe for solar tower hybrid. The plant thermal efficiency also increased to 12.5% and 14.1% from 10.2%, for a parabolic trough hybrid and solar tower hybrid, respectively. However, thermal storage systems or supplementary fuel firing are required at night for superheating. Lentz et al. [48][49] have analyzed three hybrid configurations using parabolic troughs for the Cierro Prieto geothermal plant located in Mexico. The authors report that the hybrid system can enhance the power output by augmenting the steam flow rate. Astolfi et al. [50] have studied the integration of parabolic trough collectors with a supercritical binary plant for four different locations. The maximum annual average solar-toelectricity efficiency, solar share and capacity factor of 9.4%, 27.9%, and 71.1% were obtained at San Diego, Imperial, and Pisa, respectively. The economic analysis revealed that hybridization could lead to a 50% cost reduction compared to standalone solar plants. Improvement in power output and efficiency due to hybridization has also been reported by Ghasemi et al. [39][51]. Escobar et al. [45][52] have studied two integration configurations for CSP-geothermal hybridization under Chilean conditions and reported that the double flash hybrid configuration offered the best performance.

* Corresponding author: [email protected]

20 Greenhut et al. [53] also reported that the flash hybrid configuration performed better in comparison to the superheat configuration in terms of power output, energy, and exergy efficiency. Zhou [54] has compared the performance of subcritical and supercritical organic Rankine cycle in a hybrid CSPgeothermal power plant. In comparison to the subcritical plant, the supercritical plant produces 4-17% more electricity and reduced the solar capital cost by 6-24% and solar to electricity cost by 4-19%. The maximum energy efficiency is reported for the subcritical condition while the exergy efficiency is higher for the supercritical condition. However, Boghossian [55] found no synergy between a Kalina hybrid cycle operating on geothermal brine and a parabolic trough CSP system. The author reported a 29% reduction in power output compared to the standalone plants. Changes such as regeneration, reheat, different working fluids, and incorporating the solar energy at other locations in the cycle can improve the system thermodynamic performance. Operational plant The Stillwater triple hybrid power plant (Figure 14) is the first hybrid solar-geothermal plant located in Nevada, USA [56]. It consists of a 33.1 MWe geothermal binary plant that was commissioned in 2009. Later in 2012, a 26.4 MWe PV unit was added to enhance the output during the hot summers. The system capacity was further augmented by 2 MWe due to the addition of parabolic trough (PT) collectors that preheat the incoming geothermal brine. The PT adds around 17 MW of solar thermal energy into the system. The plant acts as an excellent case study for understanding the hybridization of multiple renewable energy sources. The combined plant is expected to produce around 200 GWh/year of electricity. The capital investment for the installation of the parabolic trough system was estimated at $15 million in 2013. Summary CSP-geothermal hybridization can overcome several challenges faced by standalone geothermal plants such as cost, low efficiency, and reduction in output over time. CSP can be incorporated in the geothermal plant both in the preheating or the superheating configuration. Such integrations lead to more favourable plant output characteristics compared to standalone systems. However, the capacity * Corresponding author: [email protected]

21 of the solar field significantly influences the plant output and the cost of electricity. Several new configurations with thermal storage or supplementary fuel firing are being proposed to improve the performance of these systems. CSP-geothermal hybrids have also been studied for applications such as polygeneration, heating of greenhouses, desalination, cooling, etc. A tabulated summary of selected studies on CSP-geothermal hybrids is presented in Table A2 in the Appendix.

Figure 14: Aerial view of the Stillwater triple hybrid power plant [57].

3.1.3. CSP-wind hybrids Wind energy is currently the lowest cost renewable energy and is widely available throughout the world (Figure 15). Hybridization of CSP with wind energy is an area that has not been explored widely. This is predominantly because wind and CSP do not have wide synergy in terms of sharing of infrastructure (Figure 16), unlike other thermal energy sources such as biomass and geothermal. Hence, CSP-wind integration has been referred to as a light hybrid [14]. However, solar energy naturally complements wind energy in generating power more uniformly as wind speed is lower during the day and summer compared to nights and winter.

* Corresponding author: [email protected]

22

Figure 15: Map of the yearly averaged world wind speed (m/s) at 100 m above sea level [4].

Feasibility studies Feasibility studies for CSP-wind hybrids have been conducted for several locations such as Ontario [58], Iberian Peninsula [59], India [60], Italy [61] and Arabian peninsula [62]. Chen et al. [63] have proposed a model for selection of a suitable CSP-wind power generation project by considering the associated benefits, opportunities, costs and risks. A study by Kost et al. [64] has suggested that a CSP-wind portfolio of energy production is economically viable compared to standalone CSP in North Africa. Sioshansi et al. [65] have analyzed several configurations for co-locating solar and wind power plants in Texas, USA. Their analysis suggests that deployment of hybrid plants with upto 67% CSP can yield a positive return on investments. However, the results are sensitive to CSP and transmission costs. Peterseim et al. [14] have reported that CSP-wind hybrids have potential in Australia as several wind farms and CSP plants are co-located. A number of locations in South Australia are particularly promising as they have wind speeds > 7 m/s and DNI > 19.1 MJ/m2/day. The authors also suggest that the excess electricity produced at night by the wind farm can be utilized to charge the thermal energy storage system of the CSP plant. However, a 260% difference in the day and night time electricity prices is necessary to make this integration economically feasible. SantosAlamillos et al. [66] have also analyzed the hybridization of CSP with wind farms to produce stable renewable power in the region of Andalusia in Spain. Their analysis shows that optimal location of wind and CSP plants can overcome the spatiotemporal variability in standalone CSP and wind plants

* Corresponding author: [email protected]

23 and provide stable base-load power. The addition of thermal storage to CSP plants enhanced the performance of the hybrids.

Figure 16: Schematic of a CSP-wind hybrid plant [67].

Hybrid system performance The performance of a CSP-wind hybrid plant at Texas Panhandle has been analyzed by Vick et al. [68]. The objective was to determine the suitability of CSP-wind hybrids to match the utility electrical load in comparison to a standalone wind farm. The standalone wind farm generation is the highest at night when the utility electricity load is the minimum and vice versa (Figure 17a). A standalone 100 MWe CSP plant with 6 hours of thermal storage performed best to match the peak utility loads in July and August. Overall, a 67 MWe wind farm and a 33 MWe CSP plant with 6 hours of thermal storage were found to be the best match for the utility electricity load (Figure 17b). However, the COE of the hybrid plant was much higher ($108-129/MWh) in comparison to that of the wind farm ($64/MWh). Reichling et al. [69] have analyzed the hybridization of an 800 MWe wind farm with a 705 MWe parabolic trough solar field in Southern Minnesota. The hybridization led to a more favorable power output curve that matched the load demand curve. Also, the specific CO 2 emissions (10.8 g/kWh) are slightly higher than those associated with wind (10.2 g/kWh), but lower than those for electricity generated from a parabolic trough solar field (13.4 g/kWh). However, the cost of electricity (COE) of the hybrid plant (123 $/MWh) is higher than that of standalone wind plant (67.8 $/MWh). A reduction in capital cost for solar technology by 75% could bring the COE of the hybrid plant to within 7% of * Corresponding author: [email protected]

24 the COE of the wind plant. Petrakopoulou et al. [70] have analyzed the hybridization of CSP with wind for energy autonomy on the Greek island Skyros. The solar plant has a capacity of 10 MWe, while each wind turbine is rated at 3.3 MWe. A total of two wind turbines has been used, thereby taking the total capacity to 16.6 MWe. The mean annual efficiency of the plant is 19.2% that lies between the reported efficiencies of CSP and wind plants. The cost of electricity is 400 €/MWh. The hybrid plant was reported to have lower land use requirement and higher exergetic efficiency, thus making it a promising option for energy autonomy of remote locations such as islands. (a)

(b)

Figure 17: (a) Comparison of electricity load and wind farm capacity factor [68], (b) Annual utility loading compared to different ratios of the wind farm to CSP rated generation (2004) [68].

Summary Thus, CSP-wind hybrids can generate power that matches favourably with the load demand curve as compared to standalone plants. However, the high capital cost of the CSP component as compared to the wind farm increases the cost of electricity and makes the hybrid plant economically unattractive. Further research is necessary on the addition of storage and/or backup fuel-firing, site selection and cost reduction of CSP to make the hybrid scheme feasible. A tabulated summary of selected studies on CSP-wind hybrids has been presented in Table A3 in the Appendix. Currently, there are no CSPwind hybrid plants operational in the world.

* Corresponding author: [email protected]

25 3.2. Medium-renewable hybrids Standalone solar plants suffer from low capacity factor that necessitates the use of thermal energy storage systems. The size of the storage system required to produce power as a base load plant is two orders of magnitude higher (~ 1000 h) than the current storage systems (~ 10 h) [71]. For current storage systems, the solar fraction (fraction of the output power generated by solar energy) ranges from 0.4-0.5 that reduces to 0.2 with no storage. Hence, several standalone solar plants use fossil fuel (Figure 18), preferably natural gas, as a backup to keep the plant operational during low insolation periods. There are, however, restrictions in some countries on the maximum usage of fossil fuels as a backup. In Spain, fossil fuels can contribute to 12-15% of the total power output in a solar plant, while in the USA the value is limited to 25% [10]. This type of hybrid plants has been categorized as medium-renewable hybrids in the current work. The renewable energy fraction in their power output is approximately 70%, which is lesser than high-renewable hybrids (~ 100%), but higher than low renewable hybrids (< 20%). Solar insolation Steam generator

Receiver

Turbine

Burner

Solar concentrator Cold storage

H ot storage

Condenser

Figure 18: Plant configurations using solar concentrators with both thermal energy storage (TES) system and supplementary fossil fuel burner (adapted from [72]).

Size of the solar field The effect of the size of the solar field (solar multiple) on the performance metrics of a mediumrenewable hybrid plant (Figure 19) has been analyzed by Montes et al. [73]. The solar multiple is the ratio of the actual solar field aperture area to the area required to deliver the rated thermal input to the turbine. The solar multiple for a CSP plant is usually greater than 1. Montes et al. [73] have performed * Corresponding author: [email protected]

26 the analysis for a 50 MWe parabolic trough power plant, with thermal energy storage and auxiliary natural gas-fired boiler. The storage system and natural gas boiler are operated to maintain a constant power output. It was observed that the annual efficiency decreases with increase in the solar multiple as more of the electricity is produced from the solar collectors that have lower efficiency. The contribution of the fossil fuel in the output electricity also decreases with increase in the solar multiple. The thermal energy storage size increases to accommodate the greater amount solar energy surplus. The higher investment owing to the larger solar multiple causes an increase in the cost of electricity (COE).

Performance metric

140

120 100

Annual efficiency (%)

80

Fossil fuel (%)

60

Size of TES x 10 (hours) COE ($/MWh)

40

20 0

1

1.25 1.5 1.75 Solar multiple

2

Figure 19: Variation of annual efficiency, fossil backup percentage, the size of thermal energy storage (TES) and cost of electricity (COE) as a function of the solar multiple [73]. Exchange rate: 1 € = 1.13 $.

Impact on the environment A few studies report the impact of fossil fuel backup on the environment using life cycle analysis of medium-renewable hybrid systems. Klein et al. [74] have evaluated the performance of a 100 MWe solar plant using parabolic trough with three backup technologies and two cooling technologies. The performance was compared in terms of life cycle greenhouse gas emissions, water consumption, and onsite land usage. The life cycle CO2 emission of plants without backup is 35 kg/MWh, which is 1.53 times lower than with storage (60-73 kg/MWh). For plants with natural gas backup, the emission (127-317 kg/MWh) is 4-9 times higher than without backup. A similar analysis for a 50 MWe parabolic trough CSP plant with 7.5-hour storage has been performed by Corona et al. [2]. Fossil fuels

* Corresponding author: [email protected]

27 such as coal, natural gas, fuel oil, and biofuels such as wheat straw, wood pellets, and biogas have been used for backup. With 12% of the output energy being supplied by the backup, the maximum CO2 emission was obtained for coal (187 kg/MWh) and the minimum for wheat straw (34 kg/MWh). The solar-only plant reported an emission of 26.9 kg/MWh. In another study, Corona et al. [75] have analyzed the impact of fossil backup percentage on the environment. While CO2 emission increased with increase in natural gas backup, the effects on the environment decreased slightly (Figure 20) due

Environmental impact

to higher electricity outputs. 400

CO2 (kg eq./MWh)

300

Terrestrial acidification (g SO2 eq.)

200

Human toxicity x 10 (kg 1.4-DB eq./MWh) Freswater eutrophication x 10 (g P eq.) Marine ecotoxicity (g 1.4-DB eq.)

100 0

0

10 20 30 Natural gas backup (%)

40

Figure 20: Variation of impact on the environment with natural gas backup percentage [75].

Performance comparison Several authors have compared the performance of medium renewable hybrids with standalone solar plants. Price et al. [76] reported an improvement in the performance metrics of parabolic trough hybrid plant with auxiliary natural gas firing in comparison to the standalone plant. The solar-toelectricity efficiency, capacity factor and cost of electricity (COE) for the 30 MWe solar-only plant were 10.6%, 22.2%, and 170 $/MWh, respectively. For the hybrid plant with 25% backup, the values were 10.7%, 30.4%, and 141 $/MWh. Similar results were obtained by Malagueta et al. [77][78] who reported 50-70% decrease in COE and 100% increase in capacity factor due to natural gas backup. The impact of storage systems on standalone and hybrid plants has been analyzed by Wagner et al. [79]. Their analysis shows that for small backup capacities (1-4 h), the COE for plants with storage was lower as compared to that of natural gas. For higher backup capacities (5-12 h), the COE of * Corresponding author: [email protected]

28 plants with storage had slightly higher. However, Dersch et al. [80] reported that a solar plant with natural gas backup but without storage offers higher efficiency. The effect of the heat transfer fluid on the standalone and hybrid plant performance has been analyzed by Boukelia et al. [81]. The highest energy efficiency (18.5%) and lowest COE (75.9 $/MWh) was obtained for the molten salt plant with both storage and natural gas backup. The thermic-oil plant with both storage and natural gas backup had the highest exergy efficiency (21.8%), capacity factor (38.2%) and annual power generation (165.8 GWh). Other studies Other studies on medium hybrids include that of Larrain et al. [82], who have analyzed the performance of a 100 MWe direct steam generation (DSG) parabolic trough (PT) solar power plant in Chile with fossil fuel backup. A model was developed to estimate the solar fraction and fossil fuel backup requirements for the plant at four different locations. All the locations required fuel backup in the range of 40-80%, and the location with the least backup requirement was determined to be the most suitable for construction of CSP plants. In another study, Larrain et al. [83] developed a lifecycle model for a 100 MWe hybrid natural gas-CSP plant to determine the most suitable locations for the construction of such plants in the Chilean Atacama Desert. Such a model is useful in determining the locations at which a CSP plant becomes a net energy source. Boukelia et al. [84] have optimized two parabolic trough plants using molten salt and Therminol VP-1 as the heat transfer fluid for Algerian conditions. The results have also been compared with the Andasol-1 plant. The molten salt plant was shown to be the best technology in terms of capacity factor, power generation, water usage, investment cost, and cost of electricity. Poghosyan et al. [85] tried to determine the size of thermal energy storage system that would be required by the Shams-I PT plant at Madinat-Zayed, UnitedArab-Emirates to replace the natural gas heater. Their analysis showed that storage cannot completely replace the heat transfer fluid heater within a reasonable size (solar multiple of two, storage for 16 hours).

* Corresponding author: [email protected]

29 Table 3: Characteristics of SEGS I-IX [15]. (Acronym: HTF - heat transfer fluid)

SEGS

First year of

Net output

Solar field

Solar field

Annual output

Plant

operation

(MWe)

outlet

area (m2)

(MWh)

Backup

temperature (°C) I

1985

13.8

307

82960

30100

Thermal storage (3 hours)

II

1986

30

316

190338

80500

Gas-fired superheater

III

1987

30

349

230300

92780

Gas-fired HTF boiler

IV

1987

30

349

230300

92780

Gas-fired HTF boiler

V

1988

30

349

250500

91820

Gas-fired HTF boiler

VI

1989

30

390

188000

90850

Gas-fired HTF boiler

VII

1989

30

390

194280

92646

Gas-fired HTF boiler

VIII

1990

80

390

464340

252750

Gas-fired HTF heater

IX

1991

80

390

483960

256125

Gas-fired HTF heater

Operational plants and challenges Several operating solar plants use auxiliary natural gas burners for heating purposes. Price et al. [15] have reviewed the nine Solar Electric Generating Systems (SEGS) (Table 3) located in the Mojave Desert, California. It was reported that 8 of these 9 plants have natural gas backup for evaporation and superheating. The authors predict that advanced parabolic trough plants in the future would have the cost of electricity (COE) in the range of 50-60 $/MWh that would directly compete with conventional fossil fuel power plants. However, these systems report low solar-to-electricity efficiency owing to the higher solar share. This increases the capital investment and cost of electricity. More studies should focus on the use natural gas backup in solar tower systems that can offer greater solar-to-electricity and thermal efficiencies due to higher operating temperatures. Transient energy and exergy analysis (over a day/ month/ year) of these hybrids will also be useful in optimizing the hourly fuel consumption and plant performance parameters while determining the sources of exergy destruction. Figure 21 shows parts of two SEGS plants using solar tower and parabolic troughs with fossil fuel backup.

* Corresponding author: [email protected]

30

a

b

Figure 21: (a) 19.9 MWe Gemasolar plant [86] located in Seville, Spain using solar tower with 15% natural gas backup; (b) Part of the 354 MWe SEGS plant in northern San Bernardino County, California using parabolic troughs with natural gas backup [87].

Summary Medium renewable hybrids are the most common solar plants as they can operate continuously. The trade-off between the solar field size (solar multiple) and percentage of fossil fuel backup determines the cost of electricity, efficiency, and CO 2 emissions. The plants with higher fossil fuel backup report higher efficiency and lower cost of electricity compared to standalone solar plants, although they have a higher negative impact on the environment. Restrictions on the maximum usage of fossil fuel have resulted in low solar-to-electricity for these systems. Also, currently they are not competitive with conventional power plants or with photovoltaics. A tabulated summary of selected studies on medium renewable hybrids has been presented in Table A4 in the Appendix. All existing, under construction and planned SEGS plants with fossil fuel backup have been summarized in Table A5 in the Appendix.

3.3. Low renewable hybrids

* Corresponding author: [email protected]

31 Low renewable hybrids are fossil fuel power plants with the integration of solar energy for auxiliary purposes such as preheating. The solar share in low renewable hybrids is usually less than 20%. 3.3.1. Solar-Brayton cycles Solar energy is used in Brayton cycles either to preheat the compressed air before entering the combustion chamber or to generate steam that is injected into the combustion chamber as the working fluid. In both the cases, the increased inlet temperature to the combustion chamber reduces the fuel consumption rate while increasing the cycle efficiency. The higher working fluid temperature in a Brayton cycle increases the solar-to-electricity efficiency in such plants. This mode of integration enables continuous plant operation even in the absence of solar energy.

to stack air intake Compressor

Recuperator

Turbine

Combustor

Pressurized receiver Solar concentrator

Figure 22: Solarized gas turbine plant schematic: recuperated Brayton cycle [88].

Solar preheating of compressed air Solar preheating of compressed air in a Brayton cycle has been investigated by several authors. In such a configuration, the combustion chamber provides the additional enthalpy required to reach the turbine inlet temperature (~ 950-1300 °C) from the receiver outlet temperature (~ 800-1000 °C). Numerical modeling of such recuperated solar Brayton cycles (Figure 22) in the power range of 1.4 4.2 MWe has been performed by Schwarzbozl et al. [88]. The performance was tested using three * Corresponding author: [email protected]

32 different turbines at two different locations, namely Sevilla in Spain and Daggett in the US. The analysis showed that the annual plant capacity factor decreased with an increase in the solar share. A maximum solar share reported at 100% capacity factor was 18.1%. However, the power production cost being higher than that of conventional fossil fuel plants, the authors recommended the introduction of these plants into distributed markets (< 10 MWe) along with cogeneration until the technology matures. A similar study has been performed by Barigozzi et al. [89] in which they have modeled the performance of a 36 MWe solar-hybrid gas turbine system under the climatic conditions of Palermo, Italy. The analysis revealed that such systems can achieve a solar thermal share (Qsolar/Qin) of the order of 60-70% during the peak sunny hours of the day in all seasons except winter. Kalathakis et al. [90] have analyzed the performance of a CSP-Brayton system for various spool arrangements of a 5 MWe gas turbine. The single shaft recuperated turbine was the best choice for performance, simplicity and cost considerations. The effect of storage in a CSP-Brayton plant has been analyzed by Spelling et al. [91]. Under constant power operation, the addition of storage increased the solar share while reducing the water consumption. Olivenza-León et al. [92] have developed an analytical model for a CSP-Brayton cycle considering the irreversibilities associated with a real plant. Their model could satisfactorily predict the performance of real plants.

Figure 23: Layout of the solar hybrid steam injection gas turbine (STIG) cycle [93].

Solarized steam injection gas turbines Several studies on solarized steam injection gas turbine (STIG) systems have been performed by Kribus et al. [93][94][95][96][97]. In these systems (Figure 23), steam generated using low-

* Corresponding author: [email protected]

33 temperature solar energy is injected into the combustor to increase the power output and efficiency. The exhaust from the turbine is recuperated by superheating the solar-derived steam and preheating the water. The authors have performed energy, exergy and economic analysis for a wide range of operating parameters under the climatic conditions of India and Israel. The addition of 4h storage to the STIG cycle [97] increases the capacity factor beyond 50% while adding stability to the power output. Other studies on solar steam injection gas turbines with carbon capture have been performed by Kosugi et al. [98][99][100]. A novel steam injection gas turbine system with carbon capture and storage has been proposed by Gou et al. [101]. The saturated steam generated from the solar collectors is superheated by burning natural gas with pure oxygen before injection into the gas turbine. Under design conditions, the system offers high solar-to-electricity efficiency (30.8%) and solar share (59.85%) at an average collector temperature of 272.8 °C. Zhang et al. [102] have proposed a 361 MWe recuperated gas turbine system in which solar energy is used to produce steam for the upgrading of methane to syngas. The system offered superior performance in comparison to a gas turbine system without a solar assist. The solar-to-electricity efficiency varies in the range of 25-30%

40

Temperature (°C) DNI (W/m 2)

1000 DNI

Receiver outlet temp.

800

30

600 20 400

Wind speed

Receiver inlet temp.

Receiver pressure

200 Electric power

0 6:00

10:00

Mass flow

14:00 Time (h)

18:00

10

0 22:00

Receiver inlet gauge pressure (bar) Mass flow (kg/s) Wind speed (km/h) Electric power (MWe)

and reduces CO2 emission by around 20%. The COE of the system is around 59 $/MWh.

Figure 24: Full-time operation characteristics of the Solugas project [103].

* Corresponding author: [email protected]

34 Summary The first prototype of a solar-powered gas turbine system was tested under the SOLGATE project (Figure 25) in the CESA-1 tower at Plataforma Solar de Almería (PSA) in Spain [104][105][106]. The primary objective of the project was to develop a pressurized volumetric receiver that could heat the air above 1000 °C for direct use in a gas turbine. In the hybrid operation, a net power of 227 kWe was produced with a net efficiency of 18.2% and a solar share of 60%. The high-temperature receiver is promising and the authors expect that the system can operate with a minimum fuel usage of 5%. This was followed by the SOLHYCO (Solar Hybrid Power and Cogeneration Plants) project [107][108] that was aimed at developing a 100 KWe prototype solar-hybrid microturbine system for cogeneration. Kerosene, used in the SOLGATE project was replaced by biodiesel to make the operation fully sustainable. At megawatt scales, the first pilot solarized gas turbine plant with a capacity of 4.6 MWe was operated under the Solugas project [103][109] at Sanlucar la Mayor, Sevilla, Spain. Figure 24 shows that the power output of the turbine in the Solugas project can be maintained constant irrespective of the varying weather conditions. A similar 1.4 MWe hybrid solargas turbine system was tested at the Thermis site, Targasonne, France under the PEGASE project [110][111]. However, there are currently no operational CSP-Brayton hybrid plants in the world. A tabulated summary of selected studies on solar Brayton cycles has been presented in Table A6 in the Appendix.

* Corresponding author: [email protected]

35

CESA-1 (SOLGATE)

SOLUGAS

Solar 1000 °C

290 °C LT Bypass

MT

HT 290 °C

Schematic (SOLGATE)

Blow-off tube 800 °C Combustion

Air intake

Receiver (SOLGATE)

Exhaust

Figure 25: SOLGATE [106][112] and SOLUGAS projects [103]. (Acronyms:

LT – low temperature, MT –

medium temperature, HT: high temperature).

3.3.2. Solar-aided coal power plants Solar-aided coal-fired power plants utilize solar energy for preheating and boiling. Often, the solar energy replaces the bled-off steam used for feed water heating in a regenerative Rankine cycle. The retrofitting a solar field to a fully depreciated Rankine cycle power plant is reported to be much more profitable compared to the integration of carbon capture technologies [113]. (a)

(b)

Figure 26: Configurations of solar-aided Rankine cycle power plants in which the bled-off steam in the (a) low pressure and (b) high-pressure feedwater heaters are replaced by solar energy [114].

* Corresponding author: [email protected]

36 Configurations for integration The configuration for integration of solar energy into the steam power plant (Figure 26) is critical in determining the performance of the hybrid plant. Odeh et al. [115] have analyzed three such configurations in which the solar energy is utilized for boiling, preheating, and both boiling and preheating. The study suggests that boiling is the best configuration to reduce fuel consumption. In a similar study, Yang et al. [116][117] has investigated several strategies for the integration of direct steam generation (DSG) and heat-transfer-fluid (HTF) technologies to a 300 MWe coal-fired power plant. The authors have reported a peak solar-to-electricity efficiency (S-E η) of 27%. The integration of solar energy into a steam power plant for feedwater preheating has been the focus of several studies. In one such study, Yan et al. [118] analyzed the performance of several plants ranging from 200 to 1000 MWe. The performance was observed to be sensitive to the size of the plant and the position of integration. The performance improved with an increase in the power plant capacity for the same level of integrated solar power. The S-E η also improved with an increase in the temperature of integration. For a 200 MWe coal-fired power plant, Yang et al. [119] reported S-E η of 25.5% and 36.6% at integration temperatures of 215 °C and 260 °C, respectively. Similar studies on the utilization of solar energy for feedwater preheating has been performed by several authors [120] [121] [122] [123] [124] [125] [126]. All these studies report a higher S-E η compared to standalone solar plants. Effect of CSP technology The type of CSP technology used for hybridization has a significant influence on the hybrid plant performance. A comparison of direct steam generation (DSG) and heat-transfer-fluid (HTF) parabolic trough technologies applied to coal-fired subcritical (550 MWe) and supercritical (660 MWe) steam power plants has been conducted by Suresh et al. [127]. The DSG technology was observed to be more cost effective as compared to the HTF technology. Also, the hybrid supercritical plant is reported to have performed better than the subcritical plant in terms of thermal efficiency (45.5% and 41.8%, respectively). The specific CO2 emission for the subcritical and supercritical plants was 790 kg/MWh and 760 kg/MWh, respectively. The use of solar energy for feed water heating was

* Corresponding author: [email protected]

37 exergetically more efficient and led to a reduction in coal consumption by 14-19%. Integration of parabolic trough (PT) collectors into a 300 MWe lignite-fired power plant has also been simulated by Bakos et al. [128]. The plant efficiency increased from 33% to 37.6% with the addition of the solar field. Popov [129] studied the integration of linear Fresnel reflectors into a 130 MWe coal-fired power plant. The studies showed that the replacement of high-pressure feedwater heaters with solar energy was the most advantageous in terms of solar share, fossil fuel saving, and plant efficiency. A similar study using linear Fresnel reflectors has been performed by Reddy et al. [130]. The study reported 20% increase in instantaneous power output by replacing the turbine bleed streams with solar feed water heating. Effect of solar field size The variation of plant output characteristics with an increase in the solar field size (Figure 27) has been discussed by Wu et al. [131] and Hong-juan et al. [132]. The increase in solar field area enhances the annual plant output while operating in the power boosting mode. In the fuel saving mode, this causes a decrease in the annual coal consumption. The increase in aperture area increases the solar-to-electric efficiency as it replaces the bled-off steam for preheating. However, beyond an optimal area, the additional solar contribution is wasted as all of the bled-off steam has already been replaced by solar energy. The higher solar field size incurs additional costs and hence the cost of electricity (COE) increases beyond the optimum value. This can be observed in Figure 27 (c) and (d) where the solar-to-electricity efficiency is maximized and the COE is minimized for an optimal aperture area. This optimal area depends on the total capacity (MWe) of the plant and hence poses a limit on the maximum solar share in these systems. It is, therefore, necessary to determine uses of solar generated steam in a coal fired plant other than the replacement of bled-off steam. Power cycles in which the solar generated steam is directly used in the turbine will be a favourable development and very few studies have addressed this issue, such as [133]. Solar towers may be particularly attractive to generate the high-temperature steam. Critical issues such as mode of operation (power boost or fuel saving) and sizing of the components have to be addressed. Finally, we note that the cost of electricity for a solar aided coal-fired power plant (98 $/MWh) is lower than that of a CSP-natural * Corresponding author: [email protected]

38 gas system (140 $/MWh) [116][117]. Peng et al. [134][135] have also reported the potential of hybrid plants to reduce the COE by 20-30% in comparison to a standalone solar plant. (a)

(b)

(c)

(d)

Figure 27: Annual performance parameters with solar field area and storage capacity at 100% load [131].

Novel schemes and other studies Several other studies have been performed on solar-aided coal-fired hybrid plants. Camporeale et al. [136] performed thermodynamic analysis on the repowering of an existing 364 MWe steam power plant with solar energy. They obtained a reduction in fuel consumption by 8% at the maximum solar irradiance. Wang et al. [114] have analyzed a 300 MWe subcritical coal-fired power plant integrated with solar collectors and post-combustion carbon capture. Among the various configurations studied, they found that the integration of medium temperature solar energy to replace the high-pressure feedwater heaters provided the highest solar-to-electricity efficiency of around 24%. Gupta et al. [137] have compared the performance of a 50 kWe solar thermal power plant to that of a 220 MWe hybrid plant using direct steam generation (DSG) technology and reported a higher efficiency for the hybrid system. Zhai et al. [138] have optimized the solar contribution in a 660 MWe solar-aided plant under different load conditions and direct normal irradiation (DNI) levels. They proposed a model that

* Corresponding author: [email protected]

39 calculated the solar contribution in the solar-aided coal fired power plant at various load conditions. In another study [139], the authors have analyzed the performance of a 1000 MWe plant and concluded that hybridization facilitates solar power generation at large capacities while reducing emissions from coal-fired power plants. The addition of storage systems to such hybrid plants also improves the performance [140]. Zhu et al. [141] have performed exergy analysis of a 1000 MWe coal-fired power plant fitted with solar towers. It was observed that maximum exergy loss occurs in the boiler (53.5%), followed by the solar field (26%). An exergy based method for determining the solar contribution in a solar-aided coal-fired power plant has been developed by Hou et al. [142]. They have then used this method to study a 600 MWe coal power plant in which the steam extracted in the first stage is completely replaced by solar energy. The method proposed provides a theoretical reference in determining the solar contribution and thereby help policymakers in granting subsidies. Power plants The Lidell power station at New South Wales, Australia is the first solar aided coal-fired power plant [143][144]. It uses compact linear Fresnel reflectors to generate solar steam for feedwater heating. The solar capacity is around 3 MWe while the plant capacity is 2000 MWe. Another hybrid plant using parabolic trough collectors is the Colorado Integrated Solar Project located in Colorado, USA. The solar field produces around 2 MWe of electricity [143]. However, both the above-mentioned plants are currently non-operational. Figure 28 shows selected images of the two hybrid plants. (a)

(b)

(c)

* Corresponding author: [email protected]

40 Figure 28: Images of (a) Lidell solar thermal station [145], (b) Fresnel reflectors at Lidell power plant [145], (c) parabolic trough solar field at the Integrated Solar Project in Colorado [146].

Summary Solar energy forms a small fraction of the total output in solar-aided coal power plants. The solar field can be used for boiling, preheating, or both boiling and preheating. Both direct steam generation (DSG) and heat-transfer-fluid (HTF) technologies can be used, although the DSG technology is reported to be more cost effective. There also exists an optimal solar field size for a given coal power plant that uses solar energy to replace the bled-off steam. Beyond this optimum size, an increase in the solar field incurs additional costs that result in higher cost of electricity. Finally, the cost of electricity from these hybrid plants is lower than that from CSP-natural gas systems. A tabulated summary of selected studies on solar-aided coal-fired power plants has been presented in Table A7 in the Appendix.

3.3.3. Integrated solar combined cycles (ISCC) Integrated solar combined cycle (ISCC) refer to combined cycle systems with solar energy integration in the topping or the bottoming cycle. Integration of solar energy into a combined cycle is attractive as they offer higher efficiency in comparison to Brayton and Rankine cycle power plants. Several ISCC plants are currently operational or under construction around the world (Table 4). Table 4: Summary of existing ISCC plants [143][147].

Project name

Location

Technology

Total output

Solar contribution

(MWe)

(MWe)

Status

Agua Prieta II

Mexico

Parabolic trough

478

14

Under construction

Ain Beni Mathar

Morocco

Parabolic trough

470

30

Operational

Archimede

Italy

Parabolic trough

765

5

Operational

ISCC Duba 1

Saudi Arabia

Parabolic trough

600

43

Under construction

ISCC Hassi R'mel

Algeria

Parabolic trough

150

20

Operational

ISCC Kuraymat

Egypt

Parabolic trough

140

20

Operational

* Corresponding author: [email protected]

41 Martin

US

Parabolic trough

1150

75

Operational

Palmdale

US

Parabolic trough

570

50

Under development

Victorville 2

US

Parabolic trough

563

50

Under development

Ningxia

China

Parabolic trough

92.5

92.5

Under development

The type of solar integration in a combined cycle plant has been investigated by several authors. Integration can be performed with the topping cycle (similar to solar-Brayton plants), the bottoming cycle (similar to solar-aided coal-fired plant), or both. Oda et al. [148] has analyzed all the three configurations (Figure 29) and reported that solar integration to the bottoming cycle provides higher overall efficiency (Table 5). Integration in the topping cycle is also promising due to the higher efficiency of the solar component [8]. Similar observations have been made by Barigozzi et al. [149], who have compared the performance of a combined cycle with solar integration in the topping and bottoming cycles. The analysis suggests that higher incremental solar efficiency is obtained by solar integration in the topping cycle. However, integration in the bottoming cycle boosts power output. Buck et al. [150] have compared the performance of a 30 MWe plant with solar heat integrated into the topping cycle with that of a 310 MWe plant with solar heat integrated into the bottoming cycle. The topping cycle integration is reported to offer several advantages over the bottoming cycle integration. Table 5: Results for integration of solar energy to the topping and bottoming cycles of a combined cycle plant [8][148].

Plant

Integration method

ηI (%)

ηII (%)

A

Both supplemental heat to the topping and bottoming cycle

26.2

27.1

B

Supplemental heat to the bottoming cycle only

29.8

30.9

C

Supplemental heat to the topping cycle only

27.5

28.3

* Corresponding author: [email protected]

42 Solar insolation Receiver

Fuel

Solar insolation

Reformer Water

Solar concentrator C

GT

HE

PT

Air H RSG

ST

Figure 29: Possible configurations for solar energy integration into a combined cycle (adapted from [8]). (Acronyms: C compressor, GT - gas turbine, HE - heat exchanger, HRSG - heat recovery steam generator, ST - steam turbine, PT parabolic trough).

3.3.3.1. Combined cycle with solar integration in the topping cycle Solar integration in the topping cycle (Figure 30) is similar to the CSP-Brayton plant, where the gas turbine exhaust is used to generate steam for the bottoming cycle in a heat recovery steam generator (HRSG). Earlier studies on this configuration include SMUD Kokhala [151], Kribus et al. [152], Segal and Epstein [153]. While solar towers are the predominant choice [154], Amelio et al. [155] reported the use of air-linear parabolic trough collectors for air-preheating in such systems. Lowtemperature parabolic troughs (PT) can also be integrated into the topping cycle by generating steam for injection into the combustion chamber (STIG, [93]). One such steam injection combined cycle system (46.6 MWe) has been proposed by Kakaras et al. [156]. The efficiency of the proposed system (57.6%) was higher than conventional combined cycle systems. A novel configuration of heat transfer fluid (HTF)-ISCC employing inlet air cooling of the gas turbine has been proposed by Popov [157]. The inlet air cooling is achieved either by a PV module or by an absorption chiller powered by a direct steam generation (DSG) linear Fresnel solar field. These configurations improve the overall thermal efficiency of the plant by 1.2% in comparison to HTF-ISCC. The authors also concluded that the inclusion of the solar energy in the Brayton cycle is much more advantageous than its integration

* Corresponding author: [email protected]

43 into the steam cycle. Another novel ISCC with a topping steam turbine plant supplied by a parabolic trough system and a bottoming organic Rankine cycle has been proposed by Al-Sulaiman [158]. Solar insolation HS

Receiver

Burner

H RSG Solar concentrator

ST

HE CS C

GT

Air

Figure 30: Schematic diagram of an ISCC with integration in the topping cycle (adapted from [72]). (Acronyms: HS - hot storage, CS - cold storage, HE - heat exchanger, C - compressor, GT - gas turbine, ST - steam turbine, HRSG - heat recovery steam generator).

Solar reforming Solar reforming has also been studied by several authors for integration of solar energy into the topping cycle (Figure 31). Solar reforming is used to upgrade the fuel so that it can be utilized during periods of low solar insolation. The process is used to convert high-temperature solar energy into chemical energy by thermochemical processes such as methane steam reforming (CH 4 + H2O = CO + 3H2), the water-gas shift reaction (CO + H2O = CO2 + H2) and steam or CO2 gasification of coal. The fuel produced by this thermochemical process is a mixture of H 2 and CO, also known as syngas. Low and mid-temperature solar energy [470-570 K] can also be used for methanol reforming to generate syngas [159] that is oxidized in the combustion chamber of the topping cycle. The system can reach a solar-to-electricity efficiency of up to 35%. An advanced direct steam generation (DSG)-ISCC system with solar thermochemical fuel conversion of methane has been studied by Li et al. [160]. The energy and exergy efficiencies of the hybrid plant are higher than that of combined cycle with carbon capture and storage. The authors reported a solar thermal share of 28.2% and the net solar-toelectricity efficiency of 36.4%. A model for performance evaluation and optimization of a combined cycle with hybrid solar reforming of methane has been developed by Sheu et al. [161]. Pilot-scale

* Corresponding author: [email protected]

44 studies of solar reforming have been performed under the SOLASYS project in which a 250 kWe liquid-fuelled turbine was modified to operate on syngas [162]. CSP Solar heat

Syngas Superheater Fuel Preheater

Burner

Evaporator

Economizer

C

Air Water

GT

Steam cycle

Figure 31: Schematic of solar syngas fired power plant (adapted from [163]). (Acronyms: C - compressor, GT - gas turbine).

Size of solar field The performance of a hybrid plant as a function of the solar field capacity (Figure 32) has been analyzed by Saghafifar et al. [164]. The authors have optimized the heliostat field and thermoeconomic parameters for a 50 MWe ISCC plant located in the UAE. A solar tower system is integrated with the topping cycle for air-preheating. The hybrid plant reported an annual plant thermal efficiency of 47.16% with a solar share of 8.87%. The specific CO 2 emission decreased while the COE increased with increase in the heliostat field capacity. The authors have also concluded that establishment of a new hybrid plant is more economical compared to hybridization of an existing combined cycle plant. The operating temperature of the receiver and the low efficiency of the solar collector were determined to be the key bottlenecks for hybridization. Similar thermo-economic optimization studies have been performed by Spelling et al. [165] in which they have developed a dynamic model for a combined cycle system using solar towers. The authors reported a cost of electricity (COE) in the range of 120-240 $/MWh with solar-to-electricity efficiencies ranging from 18-24%. However, at larger plant capacities, the auxiliary power consumption is expected to reduce

* Corresponding author: [email protected]

45 the plant performance. In another study, Spelling et al. [166] have performed optimization of an advanced ISCC plant with thermal storage.

a

b

Figure 32: Variation of (a) annual fuel consumption, specific CO2 emission, (b) COE and payback period with heliostat field capacity [164].

Currently, there are no operational ISCC plants with solar integration in the topping cycle as the technology for high-temperature high-pressure solar receivers is not well developed. 3.3.3.2. Combined cycle with solar integration in the bottoming cycle Solar integration in the bottoming cycle (Figure 33) is similar to solar-aided coal-fired plants. However, instead of using coal, the exhaust of the topping gas turbine is used to generate steam for the bottoming cycle. All ISCC plants (Table 4) currently incorporate solar energy in the bottoming cycle. This type of integration is technologically mature and offers high reliability and low financial risk [167] compared to the topping cycle integration.

* Corresponding author: [email protected]

46

Figure 33: Schematic of ISCC plant with solar integration in the bottoming cycle [168].

Effect of climate on plant feasibility The feasibility of ISCC plants in specific climatic conditions has been analyzed in several studies. Baghernejad et al. [169][170] have performed the energy and exergy analysis of the ISCC power plant located in Yazd, Iran with a view to optimize the investment cost, exergy destruction and electricity cost using genetic algorithm. The exergy analysis reveals that maximum exergy is lost in the combustor (29.62%), followed by the solar field (9%) and the exhaust (7.78%). The major sources of energy losses are the condenser (35.94%) and the stack (10.15%). A similar study under Iranian conditions has been performed by Hosseinia et al. [171] who have concluded that the cost of electricity (COE) of ISCC is lower than that of the combined cycle and gas turbine systems by 10% and 33%, respectively if environmental costs are considered. Allani et al. [172] have studied the integration of solar energy in a combined cycle under the climatic conditions of Tunisia. They have concluded that the maximum power strategy of operation is better at CO 2 mitigation as compared to maximum efficiency operation. Several authors have performed thermodynamic analysis of the Hassi R’Mel ISCC power plant in Algeria. Khaldi et al. [173] have found that the gas turbine combustor and the solar field are the major sources of energy and exergy losses, whereas the turbine and the

* Corresponding author: [email protected]

47 compressor exhibit high efficiencies. The solar energy share is around 14% whereas the solar exergy share is 12%. The energy and exergy efficiencies at the design point are reported to be 56% and 53%, respectively. A study by Derbal-Mokrane et al. [174] has shown that the ISCC plant at Hassi R’Mel can produce 150 MWe at 52% efficiency, with a solar share of 20%. Behar et al. [175] have calculated that the design point efficiency of the heat transfer fluid (HTF)-ISCC power plant is better than that of the combined cycle. The feasibility of ISCC plants in southern Greece has been analyzed by Bakos et al. [176]. El-Sayed [177] has studied the performance of a direct steam generation (DSG)-ISCC at Kuraymat, Egypt and concluded that the power boosting mode is more economical compared to the fuel saving mode. Brakmann et al. [178] have provided the design and technical details of Kuraymat ISCC, located in Egypt. Elsaket [179] has proposed the modification of the existing 4 x 51 MWe Brayton cycles into an ISCC with DSG technology under Libyan climatic conditions. Such a modification would increase the plant capacity to 286.12 MWe at the design point, thereby saving 151260 t of fossil fuel annually and avoiding 468910 t of CO 2 per year. Li et al. [180] have studied the performance of a two-stage solar input DSG-ISCC under the climatic conditions of Yulin city, China. Type of solar collector The type of solar collector influences the performance of the hybrid cycle. However, the optimum choice for collectors depends on several factors such as local climatic conditions, plant operating conditions, etc. Franchini et al. [181] have compared the performance of solar tower central receiver system with that of parabolic troughs for the location of Seville, Spain. The hourly transient analysis performed by them reveals that parabolic troughs offer better performance as compared to towers in the summer months with thermal efficiencies upto 60%. However, the yearly performance analysis shows that the tower technology provides more energy at a higher efficiency as compared to the parabolic troughs. Horn et al. [182] have compared parabolic trough heat transfer fluid (HTF)-ISCC with air-tower ISCC and concluded that the solar levellized cost of electricity for the trough is lower as compared to that for the tower. However, the cost of electricity (COE) is same for both the parabolic trough (PT) and solar tower (ST) systems (31 $/MWh), which is higher than that of the * Corresponding author: [email protected]

48 reference combined cycle plant (24 $/MWh). Manente et al. [183] have analyzed and compared the performance of several ISCC plant configurations using solar collectors such as parabolic trough, solar tower, and linear Fresnel reflectors. The configuration using parabolic trough offered the best performance with solar-to-electricity efficiency reaching 30%. Also, Rovira et al. [184] have reported that direct steam generation (DSG) offers better performance as compared to the heat transfer fluid

DNI

Electricity ISCC

Temperature

Almería

Electricity ISCC

Electricity CCGT Temperature

Time (h)

Temperature ( °C)

DNI

Direct normal irradiation (W/m 2)

Electricity production (MWe)

Time (h)

Temperature ( °C)

Electricity CCGT

Direct normal irradiation (W/m 2)

Electricity production (MWe)

(HTF) system.

Las Vegas

Figure 34: Comparison of electricity production from a CCGT and an ISCC plant at Almería, Spain (top) and Las Vegas, US (bottom) [185].

Performance comparison Several studies have compared the performance of ISCC with that of solar electric generating systems (SEGS or CSP-natural gas hybrid) and combined cycle gas turbine (CCGT) systems. Montes et al. [185] have compared the performance of a CCGT power plant with that of a natural gas-ISCC power plant using direct steam generation (DSG) technology at Almería and Las Vegas (Figure 34). In terms of cost of electricity (COE), the CCGT performed better than the ISCC plant at Almería, * Corresponding author: [email protected]

49 whereas the ISCC plant performed better in Las Vegas. The hot and dry climate of Las Vegas enhanced the performance of the ISCC. The global efficiency of the ISCC is better at Las Vegas (52.2%) compared to 51.9% for Almería. A comparison of CCGT and ISCC plants from energy and exergy considerations have been performed by Reddy et al. [186]. The analysis revealed that major energy losses took place in the condenser and heat recovery steam generator (HRSG), whereas major exergy losses took place in the combustion chamber followed by the HRSG. The energy and exergy efficiencies of the combined cycle (53.9% and 54.5%) are higher than that of the ISCC (41.7% and 49.7%). A comparative study of ISCC, SEGS, and CCGT has been performed by Dersch et al. [80]. The study suggests that ISCC has the highest efficiency of 68.6% in comparison to 34.7% for a SEGS. However, the SEGS offers lower GHG emissions. Nezammahalleh et al. [187] have compared various configurations of DSG-ISCC, HTF-ISCC with HTF-SEGS and concluded that DSG-ISCC is the best configuration offering superior performance. Kolb [133] performed an economic comparison of several hybrids and standalone solar plants that use solar towers both in the power boost and fuel saving modes. The study showed that hybrid plants were more economical compared to solar only plants. Giuliano et al. [72] compare the performance of 5 different ISCC configurations with storage to that of a combined cycle plant. They have concluded that higher cost of fossil fuels and carbon trading can make ISCC competitive with CCGT plants in terms of COE. Turchi et al. [188] have compared the performance of HTF-ISCC hybrid with and without storage to that of SEGS and concluded that the COE is lower for ISCC without storage than with storage.

Figure 35: Trade-off between solar-to-electricity efficiency and solar share [189].

* Corresponding author: [email protected]

50 Novel schemes and other studies Several novel schemes for ISCC with solar integration in the bottoming cycle have also been proposed in the literature. Gunasekaran et al. [189] have proposed an advanced zero emission power (AZEP) cycle with carbon capture and storage whose solar-to-electricity efficiency is comparable with other technologies. They have also shown a negative correlation between solar-to-electricity efficiency and solar share (Figure 35). Similar observations have been made by Kelly et al. [190]. With increasing solar contributions, the solar energy displaced some of the sensible heat transfer in the heat recovery steam generator, leading to a decrease in the solar-to-electricity efficiency. Cau et al. [191] have proposed a novel ISCC concept using CO2 as the heat transfer fluid (HTF). Currently, the system cost is higher compared to combined cycle gas turbine (CCGT) plants but holds promise for the future. Li et al. [192] have proposed a novel cascade integrated solar combined cycle that uses both parabolic trough collectors and evacuated tube collectors. The system provided superior performance compared to one-stage ISCC and CCGT systems. Bonadies et al. [193] studied the retrofit of a solar tower and thermal storage system with a combined cycle plant to make the plant operate for 17 hours a day. The study showed that the integration led to a lower running time for the gas turbine unit compared to that of a regular ISCC plant. Manente [168] developed a model to predict the performance of a 390 MWe CCGT plant that was later used for hybridization with solar energy. The analysis suggests that an addition of 50 MWe solar power requires significant changes to the original plant in terms of equipment and their capacities. Kane et al. [194] have studied the optimization of the HRSG and HSSG to increase the exergy efficiency of an ISCC plant. The results show that the cost of electricity with 15-20% solar share is higher than similar capacity combined cycle plants by 20-30%. However, the cost may decrease with a reduction in the cost of solar collectors and implementation of carbon credits. Gülen [195] has developed a system of equations based on Second Law to optimize the performance of ISCC plants.

* Corresponding author: [email protected]

51

a

b

c

d

Figure 36: Images of ISCC plants (a) Ain Beni Mathar, Morocco [196] (b) Martin, US [197] (c) Kuraymat, Egypt [198] (d) Hassi R'Mel, Algeria [199].

Summary Several ISCC plants are currently operational or planned around the world. Figure 36 shows selected images of four ISCC plants located in several countries. There are currently no plants with solar integration in the topping cycle, although they promise higher efficiency due to operation at higher temperatures and pressures. Solar reforming is also promising as the fuel can be stored and used in a period with low solar insolation. For bottoming cycle integration, all types of solar concentrators such as solar towers, parabolic troughs, and Fresnel reflectors can be used. However, the performance depends on parameters such as local climatic conditions, plant operating conditions, etc. Comparative studies of ISCC plants with CCGT and SEGS systems suggest that ISCC offers the highest efficiency. Several novel schemes for ISCC systems have also been reported in the literature. A tabulated summary of selected studies on ISCC plants has been presented in Table A8 in the Appendix.

* Corresponding author: [email protected]

52 4. Comparison of the hybrid technologies The data reported in the literature along with that of actual power plants (Tables A1-A8) have been compiled for comparison of the CSP-hybrids reviewed in this paper. The mean, minimum and maximum of all the data reported is represented in figures as described in the next few sections. CO2 emissions Figure 37 represents the specific CO2 emissions from the various CSP-hybrids. As can be observed, the high-renewable hybrids have the lowest specific CO2 emissions (< 100 kg/MWh), followed by the medium (< 200 kg/MWh) and low renewable hybrids (> 200 kg/MWh). The lowest CO2 emission is reported for CSP-wind hybrids, while the highest is reported for solar-aided coal-fired power plants. The values were in the range of emissions reported for standalone plants [200][201]. While both CSPnatural gas and ISCC use natural gas, the emission of the former is lower due to the higher solar share. Thus, hybridization of CSP with conventional power plants such as natural gas combined cycle and coal-fired Rankine cycle does not offer a significant reduction in their specific CO2 emissions.

CO2 (kg/MWh)

1000

H igh hybrids

Medium hybrids

Low hybrids

800 600

400 200 0

Figure 37: Mean specific CO2 emissions from the CSP-hybrid technologies (bullets). The lines represent the range of emissions reported in the literature. (Acronyms: NG – natural gas, SEGS - solar electric generating system, ISCC - integrated solar combined cycle).

No data for CO2 emissions from CSP-geothermal hybrid power plant was available in the literature. However, CO2 emissions for a hybrid geothermal combined heat and power (CHP) plant using * Corresponding author: [email protected]

53 evacuated tube collectors was reported in the range of 29.2 - 38 kg/MWh [202]. This value has been presented in Figure 37. The global warming potential reported for standalone geothermal binary plant and parabolic trough CSP plants is approximately 50 kg/MWh [203] and 14 kg/MWh [200], respectively. Using this data, an estimate (using a linear combination) of CO2 emissions from a CSPgeothermal hybrid plant with 15% solar share is 44.6 kg/ MWh. This is of the same order as reported for the hybrid CHP plant [202]. However, the CO 2 content of the geothermal brine is high and can lead to high CO2 emissions in flash and dry steam geothermal plants. The emission can vary from 4 – 740 kg/MWh, with a weighted average of 122 kg/MWh [204]. This weighted average is still of the same order as medium hybrid CSP-natural gas plants. The geothermal fluid in a binary plant circulates through a closed loop and hence emits less CO2 compared to flash and dry steam plants. Rule et al. [205] reports a value of 40 kg/MWh Wairakei binary geothermal plant in New Zealand. Solar share The solar share in various CSP-hybrids is presented in Figure 38. The highest solar share is reported for SEGS plants that use natural gas of the order of 10-25% for backup. CSP-biomass hybrid systems using biomass for backup also report high solar share comparable to CSP-natural gas systems. The configurations in which both biomass boiler and CSP field operate in parallel to supply steam to the turbine report low solar shares. CSP-geothermal hybrids use the geothermal brine for base power output and have a low solar share. The low hybrids mostly use solar energy for preheating and hence have a low solar contribution. This also corroborates with the high CO2 emission reported from such systems (Figure 37). It can also be observed from the data that the systems with thermal energy storage have a higher solar share.

* Corresponding author: [email protected]

54 120

Solar share (%)

100 80 60

40 20 0

Figure 38: Solar share in the power produced from various CSP-hybrids. The lines represent the range of emissions reported in the literature. (Acronyms: NG – natural gas, SEGS - solar electric generating system, ISCC - integrated solar combined cycle).

Capacity The various CSP-hybrid systems are suitable only in some limited range of output capacities. CSPbiomass hybrids are restricted below 50 MWe [19] to ensure a continuous supply of biomass and to reduce logistical costs. The capacity of standalone geothermal plants can vary from 0.2-68 MWe for binary systems to 4-330 MWe for flash systems [37]. The average capacity of 8.3 MW (Figure 39) for CSP-geothermal hybrids is obtained as more hybridization studies have been performed for binary plants. Hybridization studies for flash hybrids of capacity 20 MWe have also been reported [45]. Depending on the solar resource, larger CSP-geothermal hybrid plants can also be constructed. The capacity of wind farms can be upto several hundred megawatts (Roscoe wind farm, 781.5 MWe) with each turbine upto 10 MWe [206]. Thus, CSP-wind hybrids can vary in capacity from ~ 10 MWe to several 100 MWe as observed in Figure 39. Also, the wind farm does not constrain the capacity of the CSP system as they share the power block only. The CSP-natural gas plants can vary in capacity from ~ 10-500 MWe [143]. However, the average is lower (68.5 MWe) as several CSP-natural gas plants of 50 MWe are currently operational in Spain and other locations. The solar-aided coal-fired power plants are typically of capacities ranging from 100-1000 MWe. The solar-Brayton plants are limited in capacity due to the requirement of high-temperature and high-pressure solar receivers that are currently unavailable. ISCC plants with solar integration in the topping cycle are also of smaller * Corresponding author: [email protected]

55 capacities due to the same reason. ISCC plants with solar integration in the bottoming Rankine cycle can vary in capacity from 50-1000 MWe. 1600

Capacity (MW)

1400 1200 1000 800 600 400 200

24.4

8.3

68.5

37

0

Figure 39: Capacity of various CSP-hybrid systems. The mean capacities of some of the CSP-hybrid systems have been shown in the plot. The lines represent the range of emissions reported in the literature. (Acronyms: NG – natural gas, SEGS solar electric generating system, ISCC - integrated solar combined cycle).

Solar-to-electricity efficiency (S-E η) For CSP-wind hybrids, the solar-to-electricity efficiency is same as that for standalone CSP plants (~ 14%) [69] as they share only the power block (Figure 40). This value will change as other modes of integration are proposed in which CSP and wind share some common infrastructure. CSP-biomass systems can reach higher efficiencies (27.5% peak [22]) due to the attainment of higher temperature from biomass combustion. The low temperature of the geothermal resource (~ 250 °C) limits the maximum plant operating temperature, thereby reducing the solar-to-electricity efficiency. CSPnatural gas systems reach mean S-E η in the range of 10-20% with a maximum of 28.7 reported for the Ivanpah plant [143]. For ISCC and solar-aided coal Rankine plants, the mean lies between 20-30 % with the maximum reaching in the range of 40-50%. The CSP-Brayton plants also report a higher mean S-E η due to the incorporation of solar energy at elevated temperatures in the gas turbine. Thus, the S-E η of low-renewable hybrids is higher than the other categories. CSP-biomass systems can potentially attain such high S-E η due to biomass combustion.

* Corresponding author: [email protected]

56

Solar-to-elec. η (%)

50 40 30 20

10 0 -10

Figure 40: Solar-to-electricity efficiency of various CSP-hybrid systems. The lines represent the range of emissions reported in the literature. (Acronyms: NG – natural gas, SEGS - solar electric generating system, ISCC - integrated solar combined cycle).

Overall energy and exergy efficiency For wind, no data was available on the overall thermal efficiency of the hybrid plant. The exergy efficiency of such a plant was reported to be 19.2% in [70]. However, if we assume the CSP plant efficiency to be 15%, wind turbine efficiency of 32% [70], and solar share to be 48% [70], the overall thermal efficiency obtained is 20.73%

. This has been shown in Figure 41. The

thermal efficiency of CSP-biomass hybrids is also high (> 30%) as the plants are able to operate near the design conditions by burning biomass. The CSP-geothermal hybrids report the lowest efficiency (~ 13%) due to the low temperature of the geothermal source. The CSP-natural gas systems have a high solar share and hence report a low overall efficiency. The increase in the backup percentage from natural gas can increase the overall efficiency, although at the expense of higher CO2 emissions. The ISCC plants report the highest overall efficiency, followed by the solar-Brayton and solar-aided coal fired plants. These plants also have the lowest solar share (Figure 38) and are able to operate at the design conditions continuously. The solar-Brayton reports slightly higher efficiency than the coalfired plants due to the higher temperature of operation. The ISCC plants report the highest efficiency due to the dual cycle configuration.

* Corresponding author: [email protected]

57 The exergy efficiency reports similar trend as that of the energy efficiency. The ISCC system reports the highest exergy efficiency of 60.9%, although the mean is higher for the solar-Brayton system as

Net thermal efficiency (%)

only one data point is available in [114]. 70 60 50 40

30 20 10 0

Net exerg y efficiency (%)

70 60 50 40

30 20 10 0

Figure 41: Overall energy (top) and exergy (bottom) efficiency of various CSP-hybrid systems. The lines represent the range of data reported in the literature. (Acronyms: NG – natural gas, SEGS - solar electric generating system, ISCC integrated solar combined cycle).

Capacity factor The capacity factor of CSP-wind hybrids is the lowest due to the intermittent nature of both the resources (Figure 42). CSP-biomass hybrids have reported a maximum capacity factor of 51.4% [17] but can reach higher values due to the stability offered by the combustion of biomass. Geothermal plants can operate as a base load plant due to the steady supply of geothermal brine and thus offer high capacity factor (60-70%). The CSP-natural gas plants with storage can reach capacity factors up * Corresponding author: [email protected]

58 to 74% (Gemasolar [10]), although at a higher investment. The mean capacity factor of such systems is in the range of 40-50%. The mean capacity factor of ISCC and solar-aided coal plants is high (> 80%) due to the low solar share in such systems. It is interesting to note that solar-Brayton plants report a wide range of capacity factors, from 30-100%. The highest capacity factors have been reported for the recuperated gas turbines (~ 100%) while the capacity factors for steam injection gas turbines (STIG) are in the range of 30-50%. For the STIG cycle analyzed in [94], the capacity factor is limited due to the operation of the system only during peak sunshine hours. It can be increased by the addition of storage [97] (capacity factor of 51.5%) or extended to 100% by the continuous burning of fuel. This also implies that systems with higher capacity factors have a low solar share.

Capacity factor (%)

100 80 60 40 20 0

Figure 42: Capacity factor of various CSP-hybrid systems. The lines represent the range of emissions reported in the literature. (Acronyms: NG – natural gas, SEGS - solar electric generating system, ISCC - integrated solar combined cycle).

Investment The cost of CSP technologies is significantly higher (~ 6000 $/kWe) as compared to other conventional power production technologies. The CSP systems with storage such as Andasol I in Spain cost 8700 $/kWe [207]. Thus, a CSP-hybrid system with large solar share, such as the medium hybrids, is expected to incur high initial investments (Figure 43). The highest investment (~1200018000 $/kWe) has been reported for CSP-geothermal hybrids [14][43]. These reported values are significantly higher than those of standalone CSP (~ 6000 $/kWe) and standalone geothermal plants (1711 $/kWe in [5]). One possible reason for such high specific investment is the assumptions made

* Corresponding author: [email protected]

59 in the calculation. For example, the authors in [43] assume a specific investment of 20000 $/kWe for an enhanced geothermal system. This is clearly higher than the values reported in [5][208], which is less than 4000 $/kWe. The other renewable hybrids such as wind and biomass cost around 4000 $/kWe. The solar-aided plants require the lowest investment (< 1000 $/kWe) due to the maturity of the technology and widespread usage.

Investment ($/kWe)

20000 16000 12000 8000 4000 0

Figure 43: Specific investment for various CSP-hybrid systems. The lines represent the range of emissions reported in the literature. (Acronyms: NG – natural gas, SEGS - solar electric generating system, ISCC - integrated solar combined cycle).

Cost of electricity (COE) The cost of electricity is higher for the high and medium hybrids as compared to the low hybrids (Figure 44). The low-renewable hybrids such as ISCC, solar-Brayton and solar-aided coal plants have a low solar share (Figure 38) and require significantly less investment (Figure 43). For high and medium hybrids the mean values are close to 20 c/kWh, which is almost twice as that of the low hybrids. However, there is significant variability in the reported COE as it depends on the local conditions, their tariff structure, subsidies, etc. For example, the COE for a CSP-biomass hybrid at an archipelago in Indonesia has been reported to be 60 c/kWh [18]. Similarly, the COE for a CSP-wind hybrid in the Skyros island of Greece has been reported to be 45.2 c/kWh [70]. Such locations are away from the national grid and have poor accessibility, leading to increase in the COE. However, the lowest COE values reported for the high and medium hybrids are close to that of the mean of the low hybrids. While the COE of the high and medium hybrids are expected to decrease with time due to the

* Corresponding author: [email protected]

60 advancement of technology, the COE of the low hybrids is expected to rise due to increase in the price of fossil fuels driven by scarcity. 60

COE (c/kWh)

50 40 30

20 10 0

Figure 44: Cost of electricity for various CSP-hybrid systems. The lines represent the range of emissions reported in the literature. (Acronyms: NG – natural gas, SEGS - solar electric generating system, ISCC - integrated solar combined cycle).

5. Summary In this work, literature pertaining to various CSP-hybrids has been reviewed in detail. The hybrids have been categorized into high, medium and low based on their renewable energy component. Hybrids of CSP with wind, biomass, and geothermal energy have been categorized as high-renewable hybrids. The medium-renewable hybrids refer to solar plants with natural gas backup. The lowrenewable hybrids encompass ISCC, solar-Brayton, and solar-aided coal Rankine plants that use solar energy for auxiliary purposes such as preheating and evaporation. The high-renewable hybrids report the least specific CO2 emissions (< 100 kg/MWh), followed by the medium (< 200 kg/MWh) and low hybrids (> 200 kg/MWh). A comparative analysis of the hybrids has also been performed based on their plant characteristics and performance metrics such as capacity, solar share, solar-to-electricity efficiency, capacity factor, specific investment and cost of electricity. An extensive pool of literature exists for the low-renewable hybrids such as ISCC, solar-Brayton, and solar-aided coal Rankine power systems. For solar-Brayton with compressed air preheating, the key

* Corresponding author: [email protected]

61 challenge is the development and operation of high-temperature high-pressure receivers. A similar challenge is faced by ISCC systems with topping cycle integration. For solar-aided coal Rankine plants and ISCC with bottoming cycle integration, the future studies should focus on methods of increasing the solar share to reduce CO2 emissions. In terms of other thermo-economic parameters such as capacity factor, solar-to-electricity efficiency, investment, and cost of electricity, these systems offer superior performance over medium and high-renewable hybrids. The medium renewable hybrids (CSP-natural gas) are also well understood because of the operational experience gained from several such power plants. Such hybrids report moderate specific CO 2 emission due to high solar share. The capacity of such plants can range from 20-500 MWe and is suitable both for distributed and centralized power systems. The capacity factor of these systems can be greater than 70% with natural gas backup and thermal storage. However, these systems report low solar-to-electricity efficiency that increases the investment and cost of electricity. Currently, efficiency and cost are the primary constraints that prevent further penetration of these systems into the market and should be the focus of future research. Partial replacement of the backup natural gas by renewable fuels such as syngas obtained from gasification of local biomass can also reduce the CO2 emissions of these systems. The high-renewable hybrids such as CSP-wind, CSP-biomass, and CSP-geothermal have minimum negative impact on the environment. This category is the least explored and presents tremendous potential for future research. However, such plants will be restricted to selected locations due to the requirement of two renewable energy resources. While CSP-biomass hybrids are suitable for capacities less than 50 MWe, CSP-wind, and CSP-geothermal hybrids can reach capacities greater than 100 MWe. CSP-wind systems suffer from low capacity factor due to the inherent fluctuation is wind and solar resource. The investment for high-renewable hybrids is moderately high due to medium solar share. The COE is highly variable depending on the resource, location, tariff structure, etc. Further research is necessary to address several issues pertaining to this class of hybrids. For CSP-biomass systems, the primary challenge lies in the steady supply of biomass to locations with high DNI. Location-specific optimization of logistics, development of burners for use of multiple * Corresponding author: [email protected]

62 feedstocks, use of gasified biomass (syngas) to reduce logistical costs, and hybridization with other novel solar cycles such as the supercritical CO2 Brayton cycle can be areas of focus for future research. For CSP-geothermal systems, the idea of replenishing the geothermal well using solar energy can be explored. These systems along with medium-renewable hybrids require favorable policies to compete with the low-renewable hybrids and attain technological maturity. 6. Appendix Table A1: Summary of selected CSP-biomass hybrid plants reviewed in the present study. (Acronyms: PT – parabolic trough, ST – solar tower, ηI – net thermal efficiency, ηII – net exergy efficiency, S-E η - solar-to-electricity efficiency, COE cost of electricity)

Technology

ηI

ηII

S-E η

PT +

CO2(kg

COE

Investment

Capacity

Capacity

Solar

/MWh)

(c/kWh)

($/kWe)

(MWe)

factor (%)

share (%)

Comments

34.2

50

88

7.5 h TES

37.5

50

88

7.5 h TES

TES+wheat straw[2] PT + TES+wood pellets[2] Biomass+PT

11.3

30

51.4

53.6

[17] SolComBio

29.6

23

4371

20

Brazil

[18]

24.8

60

8193.8

20

Indonesia

3108-5624*

5-60

*1AU$ = 0.74$

4144*

30

50

Biomass+PT

22.6-

[19]

34.1

Biomass+ST

33.4

11.5

23.9

*1AU$ = 0.74$

[20] PT+biomass

25.6-

4514-

[22]

27.5*

5476**

Various hybrids

29.3-

[23]

33.2

b-IGCC+PT in

36.7

3330-4958*

bottoming [24]

**1AU$ = 0.74$ 17.3-19.5

70 MWth (gasifier) +100 MWth

* Corresponding author: [email protected]

*Peak

*1AU$ = 0.74$

63 CSP IGSCC [26]

40.8

36

SGCC [28]

32.4

34.9

21.25

19

51.7

On-design condition

SHCC [28]

30.9

33.3

17.28

20

49.3

On-design condition

PT + bagasse

19.7

4692

100

37.1

30.5*

7684*

22.5

43

Table 13

[77] Borges

*1 euro = 1.13$

Termosolar [143]

Table A2: Summary of selected studies on CSP-geothermal hybrids reviewed in the present study. (Acronyms: PT – parabolic trough, ST – solar tower, ETC – evacuated tube collector, ηI – net thermal efficiency, ηII – net exergy efficiency, SE η - solar-to-electricity efficiency, COE - cost of electricity)

Technology

ηI

ηII

S-E

CO2

COE

Investment

Capacity

Capacity

Solar

η

(kg/kWh)

(c/kWh)

($/kWe)

(MWe)

factor (%)

share (%)

Comments

Flash+PT [14]

12.5

16354*

8.4

For Australia

Flash+ST [14]

14.1

12432*

9.9

1 AU$ = 0.74 $

Binary+PT [50]

Binary+PT [43]

Binary+PT [54]

Binary+PT [53]

Binary+PT [55] Flash+PT [45]

8.6

16.5

61.8

27.9

Annual average

9.4

19.8

62.2

22.8

quantities

9.1

26

68.3

18.3

8.8

31.3

71.1

14.8

12.4

8-11.8

11.6-

6.6-

14.1

13.7

9.2-

8.9-

-3.8–

10.8

14.7

14.4

10.8-

12.7-

1.4

13.1

17.4-

12.2-

18

12.7

17.2

16950

17.1

16750

17.7

18480 1.4-5

Subcritical

1-5.4

Supercritical

11-11.4

For superheat

11.6-12.1

14.5

For flash hybrid

9.6

Uses Kalina cycle

6.5

17.5

Single flash

5.7

20.2

Double flash

* Corresponding author: [email protected]

64 Binary+PT [39]

17.9

Binary+ETC

29.2 - 38

Evacuated tube

[202]

collector

Table A3: Summary of selected studies on CSP-wind hybrids reviewed in the present study. (Acronyms: WF – wind farm, PT – parabolic trough, TES – thermal energy storage, ηI – net thermal efficiency, ηII – net exergy efficiency, S-E η - solar-toelectricity efficiency, COE - cost of electricity)

Technology

ηI

ηII

S-E

CO2

COE

Investment

Capacity

Capacity

Solar

η

(g/kWh)

(c/kWh)

($/kWe)

(MWe)

factor (%)

share (%)

10.8-12.9

3733

100

38

33

WF+PT [68] WF + PT [69]

10.8

12.3

1508

20

Comments

800 MW wind + 708 MW PT (equivalent to 200 MW wind)

WF + PT +TES

19.2

45.2*

16.6**

48

[70]

*1 euro = 1.13 $ **1 CSP+2 wind turbines

Table A4: Summary of selected studies on medium hybrids reviewed in the present study. (Acronyms: DSG – direct steam generation, PT – parabolic trough, NG – natural gas, ST – solar tower, TES – thermal energy storage, ηI – net thermal efficiency, ηII – net exergy efficiency, S-E η - solar-to-electricity efficiency, COE - cost of electricity) Technology

ηI

ηII

S-E

CO2

COE

Investment

Capacity

Capacity

Solar

η

(kg/MWh)

(c/kWh)

($/kWe)

(MWe)

factor (%)

share (%)

DSG PT + NG

100

40-80% backup of

[82]

natural gas

SEGS VI [76]

11

19.4

30

33

70

SEGS VIII [76]

10

16.4

80

28

70

SEGS [15]

10.7

14.1

30

30.4

75

SEGS [15]

14.1

9.6

50

39.6

75

27

8.9*

50

70.8

25.6

9.6*

50

80.6

24.8

10.4*

50

84.8

23.9

11.3*

50

88.2

22.9

12.5*

50

91.4

DSG PT+NG [73]

PT+NG[74]

Comments

127-317

* Corresponding author: [email protected]

100

50

*1 euro = 1.13$

6 h NG

65 PT + TES+NG[2]

125

50

88

7.5 h TES

PT + TES + NG

17.6

21.7

169.4

7.9

4703

50

32.4

Configuration 3

[81]

17.7

21.8

184

9.1

6904

50

38.2

Configuration 4

18.3

21.1

169.4

7.7

4003

50

29

Configuration 7

18.5

21.7

184

7.6

4752

50

34

Configuration 8

PT + TES + NG

14.4

19.4

184

12.7

50

36.1

Batna

[84]

14.3

19.3

184

12.9

50

35.6

Setif

15.2

20.1

184

10.8

50

42.6

Djelfa

14.4

20.7

184

10.4

50

44.3

Ghardaia

14.7

20.8

184

9.6

50

48

Hassi R’mel

16.2

20.9

183.9

9.1

50

51.6

Adrar

16.4

21.4

183.9

8.5

50

54.6

Bechar

17

21.4

184

7.6

50

61.5

Tamanrasset

16.9

21.1

184

8.5

50

54.3

Amenas

16.6

20.8

184

8.1

50

57.4

Salah

100

41.3

PT + NG[77] PT+NG [80]

21.6

4638.5

47

34.7

50

Without TES

32.6

50

TES

PT+NG+TES [75]

67.2

50

95

108

50

90

148

50

85

189

50

80

230

50

75

270

50

70

311

50

65

Table A5: Summary of all SEGS plants (operational/under construction/planned) with fossil fuel backup [143]. (Acronyms ηI – net thermal efficiency, ηII – net exergy efficiency, S-E η - solar-to-electricity efficiency, COE - cost of electricity) Technology

ηI

ηII

S-E

CO2(kg/

COE

Investment

Capacity

Capacity

Solar

η

MWh)

(c/kWh)

($/kWe)

(MWe)

factor (%)

share (%)

Andasol-1

16

30.51

49.9

88

Andasol-2

16

30.51

49.9

88

50

85

49.9

88

Andasol-3 Andasol-4 Arcosol 50

7119 16

30.51 6114.2

* Corresponding author: [email protected]

49.9

Comments

66 Arenales

30.51

50

88

Aste 1A

15

30.51

50

88

Aste 1B

15

30.51

49.9

88

Astexol II

15

30.51

50

Bokpoort

11300

50

Caceres

30.51

50

88

Casablanca

30.51

50

88

36.386

50

Dahan

13.7

EL REBOSO II

17

EL REBOSO III

17

Enerstar

50 30.51

50

88

Extresol-1

16

30.51

Extresol-2

16

30.51

49.9

88

Extresol-3

16

30.51

50

88

Gemasolar [10]

88

13060.3

Genesis

19.9

74

85

250

Guzmán

30.51

50

Helioenergy 1

30.51

50

Helioenergy 2

30.51

50

Helios I

30.51

50

85

Helios II

30.51

50

85

Ibersol Ivanpah

28.7

La Africana

30.51

88

4520

50

5835.5

377

8746.2

50

85

La Dehesa

13.8

49.9

88

La Florida

13.8

50

88

La Risca

30.51

50

88

Lebrija 1

30.51

50

88

Manchasol-1

16

30.51

49.9

88

Manchasol-2

16

30.51

50

88

Mojave Solar Morón

30.51

Nevada Solar One

6400

250

6667

50

3694.4

72

98

NOOR I

43.74

7359.1

160

Olivenza 1

30.51

6418.4

50

88

500

98

Palen SEGS

* Corresponding author: [email protected]

1 Dirhams = 0.27 $

67 Pedro de Valdivia

7250

360

Planta Solar 10

30.64424

11

Planta Solar 20

30.64424

20

Shams 1

6000

100

Solaben 1

30.51

50

Solaben 2

30.51

50

Solaben 3

30.51

50

Solaben 6

30.51

50

Solacor 1

30.51

50

Solacor 2

30.51

50

Solana

8000

250

SEGS II

30

SEGS III

30

SEGS IV

30

SEGS V

30

SEGS VII

30

SEGS IX

80

Solnova 1

50

Solnova 3

50

Solnova 4

50

Termesol 50

6114.2

49.9

Termosol 1

50

Termosol 2

50

Table A6: Summary of selected studies on solar-Brayton cycles reviewed in the present study. (Acronyms: GT – gas turbine, ηI – net thermal efficiency, ηII – net exergy efficiency, S-E η - solar-to-electricity efficiency, COE - cost of electricity) Technology

ηI

ηII

S-E η

CO2

COE

Investment

Capacity

Capacity

Solar

(kg/M

(c/kWh)

($/kWe)

(MWe)

factor (%)

share

Wh)

Comments

(%)

Recuperated GT

40.4

15.4

21.6*

1.4

100

15

[88]

38.4

14.5

22.5*

1.4

100

18.1

35.9

14.2

11.3*

4.2

100

7.5

35.9

14.6

11.2*

4.2

100

8.8

Brayton +

456

10.5

1897

37

17.8

storage [91]

451

13.7

3011

38.2

37.6

* Corresponding author: [email protected]

* 1 euro = 1.13 $

68 STIG [94]

STIG+storage

39.1

36.9

17.6

37.9

39.1

35.9

17.6

41.7

39

37.9

17.6

36.7

39

37.7

17.6

38

39.5

38.4

17.6

34.3

39.9

39.2

17.6

35.7

39.8

40.9

17.6

30.9

40.2

42.1

17.6

30.7

39.2

37

17.6

51.5

Constant power

Variable power

Table 6, ref: RGT, real

[97]

storage

STIG [100] SOLRGT [102]

45.9

52.3

29.1

75.2

3.82

343

5.9

22.4 736

361

20.3

Table A7: Summary of selected studies on solar-aided coal fired power plants reviewed in the present study. (Acronyms: PT – parabolic trough, CR - Coal Rankine, LFR – linear Fresnel reflector, ST – solar tower, ηI – net thermal efficiency, ηII – net exergy efficiency, S-E η - solar-to-electricity efficiency, COE - cost of electricity)

Technology

ηI

ηII

S-E η

CO2

COE

Investment

Capacity

Capacity

Solar

(kg/M

(c/kWh)

($/kWe)

(MWe)

factor (%)

share

Wh) PT+CR

27

Comments

(%) 9.8

300

[116][117] PT+CR [119]

36.6

PT+CR [131]

21*

6.3

330

*annual, Fig 8a

PT+CR [134]

21

12*

349

* 1 Yuan = 0.15 $

PT+SubcR

200

41.8

38.2

790

3.62*

789*

500

85

14.4

45.5

41.6

760

3.67*

843*

660

85

18.9

*INR 1 = 0.015 $

[127] PT+SupcR [127] CR [120]

30.12

500

PT+CR [121]

45.9

200

33.1

17.3

104

6.5

For case B

35.4

34

116

9.9

For case C

35.7

39.2

117

22.8

For case D

LFR+CR [129]

LFR+CR [130]

38.4

41.3

9.4

636

3.7

LPH

35.8

41.7

20.6

738

17

LPH and HPH

* Corresponding author: [email protected]

69 PT+CR [118]

36.6

219

10.3

subcritical

36.24

334

8.53

subcritical

40.26

653

8.23

subcritical

41.22

655

7.91

supercritical

35.61

646

8.31

ultra-supercritical

PT+CR [142]

24.1

600

4.3

PT+CR [122]

24.2

225

10.6

PT+CR [124]

23.6

100

25

125

25.6

200

24.6

330

25.3

600

27.9

1000

PT+CR [125]

36

300

PT+CR [126]

3.4-18

600

PT+CR [128]

8.6*

11.5

275

Fuel saving *1 euro = 1.13 $

34.9

285

2.2

Power boost

35.2

290

4

*1 euro = 1.13 $

36

296

6.1

302

7.9

36.7 PT+CR [139]

8.5*

42.5

13.6

4.2

637.5

1000

5.8

Fuel saving

42.9

13.5

4

601.6

1058

5.4

Power boost

26.2

7.1

358

12.5

Configuration 1

PT+CR [132]

1 Yuan = 0.15 $ ST+CR [133]

8.7

450

Power boost low capacity factor

7.8

450

Power boost high capacity factor

2.9 PT+CR [209]

45.3-

5.1-

48

28.5

350

Fuel saver base loaded

600

Table A8: Summary of selected studies on ISCC power plants reviewed in the present study. (Acronym: CC – combined cycle, ST – solar tower, GT – gas turbine, PT – parabolic trough, R – Rankine, ηI – net thermal efficiency, ηII – net exergy efficiency, S-E η - solar-to-electricity efficiency, COE - cost of electricity)

* Corresponding author: [email protected]

70 Technology

ηI

ηII

S-E η

CO2

COE

Investment

Capacity

Capacity

Solar

(kg/MW

(c/kWh)

($/kWe)

(MWe)

factor (%)

share

h) CC+ST [148]

26.2

(%)

27.1

86.5

Both topping and bottoming

CC+ST GT

29.8

30.9

86.5

Bottoming

27.5

28.3

86.5

Topping

56.3

29.3

66.5

9.8

Topping cycle integration

28.7

10.8

66.5

4.7

Bottoming cycle

[149] CC+PT R [149]

integration CC+ST GT

47.2

371.9

7.8

50

100

8.9

[164] CC+ST GT

19.6

4.8

30

21

Daggett

[151]

19.3

4.9

30

15

Sacramento

CC+ST GT

21.3

6-7

2588

34

[152] CC+GT [156]

57.6

46.6

CC+PT R [157]

49.9

469

ISCC

CC+PT abs. ch

51.7

469

Turbine air cooling using

[157] CC+ST GT

solar 43.1

32.3

5.1

30

11.3

REFOS

CC+PT R [150]

53.5

30.9

3.7

310

4.1

ISCC

CC+PT GT

47.4

[150]

Ta = 25 °C, ηg2

367

[155] CC+ST GT [88]

CC+ST

44.9

18.3

7.1*

16.1

100

11.6

43.4

19.3

7.2*

16.1

100

16.2

43.9

19

7.8*

16.1

100

27.8

47.6

26.1

386

* 1 euro = 1.13 $

5.4

reforming [161] CC+PT R [167]

ISCC [183]

15.7

17.6

140

16.1

17.5

140

29.7

317.4

1270

440

PT

29.2

317.7

1275

440

PT

28.2

317.4

1291

440

PT

27.5

317.4

1411

440

ST

* Corresponding author: [email protected]

71

CC+PT R [172]

26.6

317.8

1206

440

LFR

26.8

317.6

1204

440

LFR

60.2

350.6

7

67.1

314.4

9

60.3

350

7.8

20.3

68.9

306.1

10.5

31.2

57

367

6.6

13.4

62.4

338.3

8.6

57.3

368.6

7.3

15.1

63

334.7

10

24

362.1

4.8

1900

100

66

50.9

2.2

506

407

79.3

51.6

2

564

444

73.7

50.9

2.3

573

444

76

CC+PT R [194] CC+PT R [171]

CC + PT R

46.2

18 2303

26

2310

45.6

20

14

467

[169] CC + PT R

46.8

5.3

400

[170] CC + PT R

56

53

160

12

52

150

20

67

157

15

[210] CC + PT R [174] CC + PT R [175] CC + PT R

5.2

883.2

54.5

Power boost mode

[176]

5.4

1127.8

59

1 Euro = 1.13 $

5.7

1346.7

63.8

6

1542.8

68.5

6.2

1717.9

73.1

6.5

1881.1

78

5.1

924.5

50

Fuel saving mode

5.4

1249.2

50

1 Euro = 1.13 $

5.6

1582.7

50

5.9

1931.6

50

6.1

2287.5

50

6.4

2640.3

50

CC + PT R

48.8

18

* Corresponding author: [email protected]

89.1

Annual average parameters

72 [181] CC + ST R

50.5

21.8

89.3

Annual average parameters

[181] CC+PT R [191]

23.6

7.8*

553.6*

278.1

9.2

Configuration 1 *1 Euro = 1.13 $

24.8

7.8*

554.5*

279.4

9.6

Configuration 2 *1 Euro = 1.13 $

CC+PT R [185]

52.2

21.5

9.2*

220

1.2

Almería *1 Euro = 1.13 $

51.9

27.3

9.1*

220

2.4

Las Vegas *1 Euro = 1.13 $

CC+PT R [177]

CC+PT R [180]

50.9

117

8.4

Power boosting mode

87

9.1

Fuel saver mode

590

73.6

Annual performance

CC+PT R [182]

410

3.1

894

127

79.8

9

PT

CC+ST R [182]

409

3.1

902

127

80

8.2

ST

CC+PT R [188]

CC+LFR R

46.4

16.1

13.6

3330.9

138

Hybrid without TES

48.3

16.2

15.4

4049.3

138

Hybrid with 3 h TES

47.7

16

12.9

3553.5

88

Hybrid with 4 h TES

41.7

49.7

13.1

325

9.7

[186] CC+PT R [80]

68.6

310

ISCC

68.1

310

ISCC with TES

CC+PT R [187]

CC+PT R [184]

CC+ST R [133]

474

7.5

451.5

73.1

14.8

DSG

486

7.6

444.8

73.5

15.1

HTF

50.1

44.6

130.2

HTFev

47.7

32.2

124

HTFph-ev

50.1

44.6

130.2

HTFev-sh

48

33.6

124.7

HTFph-ev-sh

50.1

44.6

130.2

DSGev

47.2

29.8

122.8

DSGph-ev

50.1

44.6

130.2

DSGev-sh

48.3

35.1

125.5

DSGph-ev-sh

450

Power boost low capacity

8.7

factor 7.8

450

Power boost high capacity factor

* Corresponding author: [email protected]

73 3.2 6

350 816

594

Fuel saver CC

CC+PT+ET R

53.4

60.9

30.8

77.4

Cascade ISCC

[192]

54.1

58.4

28.6

569

CC+PT R [168]

54.6

26.1

440

49.6

24.2

440

Power boost 2

51.4

28.9

440

Power boost 3

27.1-

440

Fuel saving 1

24.9

440

Fuel saving 2

15.6

765

One-stage ISCC ~1

Power boost 1

27.6

Archimede

0.65

[143][147] Agua Prieta II

478

2.9

Mathar

470

6.4

ISCC Duba 1

600

7.2

R'mel

150

13.3

ISCC Kuraymat

140

14.3

Martin

1150

6.5

Palmdale

570

8.8

Victorville 2

563

8.9

Ain Beni

ISCC Hassi

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* Corresponding author: [email protected]

89 List of Tables Table 1: Comparison of various CSP-biomass hybridization schemes [23]. Exchange rate: 1 AU$ = 0.74 US$ Table 2: Details of the Termosolar Borges plant [32][33]. Table 3: Characteristics of SEGS I-IX [15]. (Acronym: HTF – heat transfer fluid) Table 4: Summary of existing ISCC plants [143][147]. Table 5: Results for integration of solar energy to the topping and bottoming cycles of a combined cycle plant [8][148]. Table A1: Summary of selected CSP-biomass hybrid plants reviewed in the present study. (Acronyms: PT – parabolic trough, ST – solar tower, ηI – net thermal efficiency, ηII – net exergy efficiency, S-E η - solar-to-electricity efficiency, COE - cost of electricity). Table A2: Summary of selected studies on CSP-geothermal hybrids reviewed in the present study. (Acronyms: PT – parabolic trough, ST – solar tower, ETC – evacuated tube collector, ηI – net thermal efficiency, ηII – net exergy efficiency, S-E η - solar-to-electricity efficiency, COE - cost of electricity). Table A3: Summary of selected studies on CSP-wind hybrids reviewed in the present study. (Acronyms: WF – wind farm, PT – parabolic trough, TES – thermal energy storage, ηI – net thermal efficiency, ηII – net exergy efficiency, S-E η - solar-to-electricity efficiency, COE - cost of electricity). Table A4: Summary of selected studies on medium hybrids reviewed in the present study. (Acronyms: DSG – direct steam generation, PT – parabolic trough, NG – natural gas, ST – solar tower, TES – thermal energy storage, ηI – net thermal efficiency, ηII – net exergy efficiency, S-E η - solar-toelectricity efficiency, COE - cost of electricity). Table A5: Summary of all SEGS plants (operational/under construction/planned) with fossil fuel backup [143]. (Acronyms - ηI – net thermal efficiency, ηII – net exergy efficiency, S-E η - solar-toelectricity efficiency, COE - cost of electricity). * Corresponding author: [email protected]

90 Table A6: Summary of selected studies on solar-Brayton cycles reviewed in the present study. (Acronyms: GT – gas turbine, ηI – net thermal efficiency, ηII – net exergy efficiency, S-E η - solar-toelectricity efficiency, COE - cost of electricity). Table A7: Summary of selected studies on solar-aided coal fired power plants reviewed in the present study. (Acronyms: PT – parabolic trough, CR - Coal Rankine, LFR – linear Fresnel reflector, ST – solar tower, ηI – net thermal efficiency, ηII – net exergy efficiency, S-E η - solar-to-electricity efficiency, COE - cost of electricity) Table A8: Summary of selected studies on ISCC power plants reviewed in the present study. (Acronym: CC – combined cycle, ST – solar tower, GT – gas turbine, PT – parabolic trough, R – Ran ine, ηI – net thermal efficiency, ηII – net exergy efficiency, S-E η - solar-to-electricity efficiency, COE - cost of electricity)

* Corresponding author: [email protected]

91 List of Figures Figure 1: Map of the yearly averaged downward surface solar radiation reaching the surface (W/m2) [4]. Figure 2: Hourly variation of DNI (W/m2) on four different dates at representative locations of four different continents, namely, Daggett in USA, Sevilla in Spain, Ahmadabad in India, and Antofagasta in Chile. The profiles have been obtained from the Solar Advisor Model (SAM), NREL [11]. Figure 3: Variation of monthly averaged DNI (W/m2) at representative locations of four different continents, namely, Daggett in USA, Sevilla in Spain, Ahmadabad in India, and Antofagasta in Chile. The profiles have been obtained from the Solar Advisor Model (SAM), NREL [11]. Figure 4: Potential regions for CSP-biomass hybrid plants worldwide [22]. Figure 5: Variation of net cycle thermal efficiency of solar-biomass hybrids with power output for different biomass feedstocks [19]. Figure 6: Variation of specific investment of solar-biomass hybrids with power output for different biomass feedstocks [19]. The regions selected receive DNI > 21-24 MJ/m2/day. Exchange rate: 1AU$ = 0.74 US$. Figure 7: Exergy destroyed in individual components as a fraction of the input exergy. The exergy lost in the exhaust is 8.72% of the input exergy. The gasifier is operated at T g = 1073 K with biomass containing 20% moisture [26]. Figure 8: Termosolar Borges power plant in Spain [32][34][35][36]. Figure 9: (a) T-s diagram of an organic Rankine cycle with recuperation showing the various state points and operating conditions [39], (b) Reduction in power output from a geothermal plant with an increase in ambient temperature [39]. Figure 10: Integration schemes for CSP-geothermal hybridization [40].

* Corresponding author: [email protected]

92 Figure 11: (a) Hourly comparison of power output from a standalone geothermal plant and a hybrid plant [40], (b) Effect of geothermal resource temperature decline on the base and hybrid plant monthly power generation [40], (c) Effect of geothermal resource temperature decline on the base and hybrid plant annual power generation [40], (d) Variation of the solar to electricity efficiency of the hybrid plant as a function of the geothermal well temperature and the ambient temperature [40]. The solar energy input is 25% of the geothermal plant design input. Figure 12: (a) Determination of the solar energy fraction as a function of solar aperture area at various geothermal reservoir temperatures (Tair = 31 °C; design-point solar DNI = 1000 W/m2) [43], (b) Net electrical power output as a function of the solar share for various operation strategies [43]. Figure 13: Cost of electricity as a function of the solar field capital cost [40]. Figure 14: Aerial view of the Stillwater triple hybrid power plant [57]. Figure 15: Map of the yearly averaged world wind speed (m/s) at 100 m above sea level [4]. Figure 16: Schematic of a CSP-wind hybrid plant [67]. Figure 17: (a) Comparison of electricity load and wind farm capacity factor [68], (b) Annual utility loading compared to different ratios of the wind farm to CSP rated generation (2004) [68]. Figure 18: Plant configurations using solar concentrators with both thermal energy storage (TES) system and supplementary fossil fuel burner (adapted from [72]). Figure 19: Variation of annual efficiency, fossil backup percentage, the size of thermal energy storage and cost of electricity as a function of the solar multiple [73]. Exchange rate: 1 euro = 1.13 $. Figure 20: Variation of impact on the environment with natural gas backup percentage [75]. Figure 21: (a) 19.9 MW Gemasolar plant [86] located in Seville, Spain using solar tower with 15% natural gas backup; (b) Part of the 354 MW SEGS plant in northern San Bernardino County, California using parabolic troughs with natural gas backup [87].

* Corresponding author: [email protected]

93 Figure 22: Solarized gas turbine plant schematic: recuperated Brayton cycle [88]. Figure 23: Layout of the solar hybrid steam injection gas turbine (STIG) cycle [93]. Figure 24: Full-time operation characteristics of the Solugas project [103]. Figure 25: SOLGATE [106][112] and SOLUGAS projects [103]. (Acronyms: LT – low temperature, MT – medium temperature, HT: high temperature). Figure 26: Configurations of solar-aided Rankine cycle power plants in which the bled-off steam in the (a) low pressure and (b) high-pressure feedwater heaters are replaced by solar energy [114]. Figure 27: Annual performance parameters with solar field area and storage capacity at 100% load [131]. Figure 28: Images of (a) Lidell solar thermal station [145], (b) Fresnel reflectors at Lidell power plant [145], (c) parabolic trough solar field at the Integrated Solar Project in Colorado [146]. Figure 29: Possible configurations for solar energy integration into a combined cycle (adapted from [8]). (Acronyms: C - compressor, GT - gas turbine, HE - heat exchanger, HRSG - heat recovery steam generator, ST - steam turbine, PT - parabolic trough). Figure 30: Schematic diagram of an ISCC with integration in the topping cycle (adapted from [72]). (Acronyms: HS - hot storage, CS - cold storage, HE - heat exchanger, C - compressor, GT - gas turbine, ST - steam turbine, HRSG - heat recovery steam generator). Figure 31: Schematic of solar syngas fired power plant (adapted from [163]). (Acronyms: C compressor, GT - gas turbine). Figure 32: Variation of (a) annual fuel consumption, specific CO2 emission, (b) COE and payback period with heliostat field capacity [164]. Figure 33: Schematic of ISCC plant with solar integration in the bottoming cycle [168].

* Corresponding author: [email protected]

94 Figure 34: Comparison of electricity production from a CCGT and an ISCC plant at Almería, Spain (top) and Las Vegas, US (bottom) [185]. Figure 35: Trade-off between solar-to-electricity efficiency and solar share [189]. Figure 36: Images of ISCC plants (a) Ain Beni Mathar, Morocco [196] (b) Martin, US [197] (c) Kuraymat, Egypt [198] (d) Hassi R'Mel, Algeria [199]. Figure 37: Mean specific CO2 emissions from the CSP-hybrid technologies (bullets). The lines represent the range of emissions reported in the literature. (Acronyms: NG – natural gas, SEGS - solar electric generating system, ISCC - integrated solar combined cycle). Figure 38: Solar share in the power produced from various CSP-hybrids. The lines represent the range of emissions reported in the literature. (Acronyms: NG – natural gas, SEGS - solar electric generating system, ISCC - integrated solar combined cycle). Figure 39: Capacity of various CSP-hybrid systems. The mean capacities of some of the CSP-hybrid systems have been shown in the plot. The lines represent the range of emissions reported in the literature. (Acronyms: NG – natural gas, SEGS - solar electric generating system, ISCC - integrated solar combined cycle). Figure 40: Solar-to-electricity efficiency of various CSP-hybrid systems. The lines represent the range of emissions reported in the literature. (Acronyms: NG – natural gas, SEGS - solar electric generating system, ISCC - integrated solar combined cycle). Figure 41: Overall energy (top) and exergy (bottom) efficiency of various CSP-hybrid systems. The lines represent the range of data reported in the literature. (Acronyms: NG – natural gas, SEGS - solar electric generating system, ISCC - integrated solar combined cycle). Figure 42: Capacity factor of various CSP-hybrid systems. The lines represent the range of emissions reported in the literature. (Acronyms: NG – natural gas, SEGS - solar electric generating system, ISCC - integrated solar combined cycle).

* Corresponding author: [email protected]

95 Figure 43: Specific investment for various CSP-hybrid systems. The lines represent the range of emissions reported in the literature. (Acronyms: NG – natural gas, SEGS - solar electric generating system, ISCC - integrated solar combined cycle). Figure 44: Cost of electricity for various CSP-hybrid systems. The lines represent the range of emissions reported in the literature. (Acronyms: NG – natural gas, SEGS - solar electric generating system, ISCC - integrated solar combined cycle).

* Corresponding author: [email protected]

96

Highlights 

This paper reviews hybrids of CSP with coal, natural gas, biomass, wind, geothermal



Technologies have been categorized into high, medium, and low-renewable hybrids



CO2 emissions highest for low-renewable hybrids, followed by medium and high



Low-renewable hybrids offer higher efficiency and capacity factor at lower cost

* Corresponding author: [email protected]