Concentrated solar thermal. Concentrated solar thermal

Techno-economic performances of future concentrating solar power plants in Australia

The prediction of the techno-economic performances of future concentrated solar power (CSP) solar tower (ST) with thermal energy storage (TES) plants is challenging. Nevertheless, this information is fundamental to energy policymakers. This work aims to fill the knowledge gap regarding estimations of costs, amount, and quality of electricity produced by these plants over their lifetime. Every estimate should be based on real-world data of actual costs incurred to build and maintain constructed plants, and their actual electricity production, sampled with high frequency, to be reliable. Here we discuss as the available information is insufficient. There has been so far very limited transparency on the real cost and performance of CSP plants built and operated worldwide, and in the very few cases where data has been made public, for example, Crescent Dunes in the United States, costs have been much higher than expected, while annual average capacity factors have been much less. Important statistical parameters such as the standard deviation of the capacity factor with high-frequency sampling have never been provided. We conclude as the techno-economic performances of these plants are therefore unpredictable with accuracy until a significant number of plants will be built and operated, their costs and operating parameters will be shared, and their delivered techno-economic performances will be compared to the modeled values, finally permitting validation of the techno-economic analysis tools.

Introduction

Concentrated solar energy in Australia has been the subject of few works (Baig et al., 2015; Clifton and Boruff, 2010; Dawson and Schlyter, 2012; Peterseim et al., 2014; Ghadi et al., 2019; Middelhoff et al., 2022; Narimani et al., 2016), with however practically no plant built and operated so far. Worth mentioning there is only a small 9 MW Fresnel section added to a coal-fired power plant to pre-heat the feedwater, which does not qualify as a concentrated solar power (CSP) plant. Hybrid plants concentrated solar energy plus biomass are becoming popular in the literature (Middelhoff et al., 2022), while hybrid plants concentrated solar energy plus coal were more favored until recently in the academic works (Ghadi et al., 2019), despite it is acknowledged also locally as the dispatchability of CSP plants with thermal energy storage (TES) makes this opportunity extremely attractive (Narimani et al., 2016). The last few years have seen a dramatic increment of installed capacity of wind and solar facilities, with these latter facilities in the case of Australia limited to large and roof-top photovoltaic (PV) only. No facility has been built yet or is being built, featuring concentrated solar power (CSP). This anomaly needs an explanation, that is not available in the current literature. Also uncovered in the current literature are the potentials of the CSP technology in Australia, despite the debacles suffered so far.

As shown in Fig. 1, data from the Department of the Environment and Energy (2019), in the last fiscal year of the statistic (2017–2018), the contribution of the variable and unpredictable wind and variable, unpredictable and intermittent solar PV was 5.74 and 3.80%, with worth to mention also a reliable and dispatchable hydro contribution of 6.07%. Since the end of the 1980s, when the renewable energy contribution was about 10% hydro, and 0% solar photovoltaic and wind, there has been therefore a dramatic increment of wind and solar, but a reduction of hydro. Biomass was 0.5% at the end of the 1980s and it is 1.5% now. Geothermal was, and it is, negligible. The growth of wind and solar is partially balanced by the reduction of hydro. This reduction is simply the result of the wholesale pricing of electricity in Australia.

The National Electricity Market (NEM) grid, covering only part of South Australia, Tasmania, Victoria, Australian Capital Territory, New South Wales, and Queensland, is presently fed with a growing amount of wind and solar PV energy, that is balanced by the combustion of fossil fuels, and the hydroelectric production, to cover the demand.

The NEM grids stretch for about 5000 km from Port Douglas, tropical north Queensland, to Port Lincoln, South Australia, also serving Tasmania across the Bass Strait. As the NEM market is a wholesale market where “retailers” buy and “generators” sell electricity, with the peak wholesale spot about 14 AU/kWh compared to an average of about 10 c AU/kWh, hydro generation is run for maximum profit and not maximum production.

Figure 2 (from Aneroid Energy, 2019) presents a sample grid average production of electricity of wind and large solar PV over a sample month, July 2019. Being the wind energy production proportional to the wind energy resource, individual wind farms have capacity factors ε, the ratio of generating power to nominal capacity, variable from zero to 100%, with averages of about 30–35% over a year. In terms of grid average ε, despite the exceptionally long grid, grid averages ε may go down to even below 5% or above 60%. Even worse variability is provided by solar PV, with everyday production going to zero during the night, and up to a maximum during the daytime that differs day-by-day and season-by-season, reaching sometimes 100%. Variability is still substantial also at the grid average level.

Owing to this irregularity, wind or solar facilities of total power X need balancing facilities, either conventional combustion fuels or hydro-gravity, of about the same total power X. This is the reason why the cost of electricity for consumers has increased from about 10 AUc/kWh up to 2007 when there was no wind nor solar, to the already 25 AUc/kWh of 2013 (Parkinson, 2013), up to the present above 40 AUc/kWh. To support a larger uptake of wind and solar, energy storage is needed, and this will introduce additional costs, apart from technological challenges.

Pumped hydroelectric energy storage (PHES) is the easiest way to supply electric energy storage (Rehman et al., 2015). Unfortunately, PHES has round-trip efficiencies of 70 to 80%, less than the 95% round-trip efficiency of Li-ion batteries. While traditional hydro-gravity plants are being upgraded to PHES by adding a pumping facility, and the largest energy storage facility of Australia, the 1800 MW Tumut 3, is PHES, as these plants were already providing on-demand production of electricity, their support is limited.

The further expansion of PHES in Australia should progress along the coast, where cliffs may provide the required head. However, salt-water PHES is everything but an established technology. A single pilot plant has been built, briefly operated, and then dismantled all over the world.

Added to PHES, battery energy storage (BES) is the other promising technology, with the largest Lithium-ion battery, the 150 MW/194MWh MW Hornsdale facility, located nearby the Hornsdale wind energy facilities to help to balance the output. The latest 50 MW/64 MWh phase 2 of 2019 had a cost of 71 mAU (50 m US). Coupled for example to solar PV of daily cyclic variability, if we take daily cycles 30 to 80% state-of-charge, over a 15 years’ life span, this is an additional cost of storing/releasing the energy of US 28 c/kWh. If the life span increases to 30 years, that is fairly optimistic, this is still US 14 c/kWh. Thus, even if we produce electricity with solar PV at the optimistic cost of 4 c/kWh, the cost for having solar PV electricity all day will be (4 4 14)/2 = 11 to (4 4 28)/2 = 18 c/kWh (day and night are on average 12 h a day).

Thus, there is the opportunity to benefit from the construction of CSP ST with TES in Australia, as this is the only solar technology that permits some sort of dispatchability without the need for external energy storage. CSP with TES has the advantage of dispatchability without external energy storage. Hence, these facilities may deliver an output much closer to power on-demand or constant power than wind and traditional solar PV can do.

CSP ST, according to Kuravi et al. (2013), Liu et al. (2016), and IRENA (2012) are expected to quickly take over CSP PT, because of the alleged advantages of higher efficiency in converting sun energy to electricity. CSP needs significant direct normal radiation (DNI), and electricity production in concentrated solar power falls dramatically with Cloud coverage. CSP is not competitive in cost with PV, which also suffers much less Cloud coverage.

The advantage of CSP is the opportunity to store energy in the molten-salt TES, as shown in Yang and Garimella (2010), Herrmann et al. (2004). TES allows in principle to fully decouple electricity production from the availability of solar energy. This opportunity is developed more, the larger is the number of hours of the TES design. CSP, as a dispatchable form of solar energy, has a significant added value vs. PV.

The work aims to explain why Australia has an expanding capacity of wind and solar PV power plants but has not built yet a single CSP plant, and why this situation is going to change shortly aiming at a renewable energy-only grid.

Methods

Summary of recent CSP projects in Australia and the rest of the world, with estimated levelised cost of electricity compared to wind and solar PV. Inclusion of energy storage for dispatchability in the costs comparison.

Results

The first CSP plant supposed to be built in Australia was the Aurora power plant, featuring about the same of the technology of Crescent Dunes in the United States, CSP ST with molten-salt TES. This technology generates solar power concentrating sunlight onto a small area (Boerema et al., 2013; Müller-Steinhagen and Trieb, 2004). The solar field is a large array of many dual-axis heliostats concentrating sunlight onto the central receiver atop the tower. The concentrated light warms up the molten salt to the hot tank. Steam is then produced in a heat exchanger between the molten-salt hot and cold tank. The steam expands in a turbine to generate electricity (Law et al., 2014; Law et al., 2016). The condenser is air-cooled and sometimes evaporative or hybrid.

The signature of the power purchased agreement (PPA) for Aurora was wrongly assumed as proof that fully dispatchable solar energy was possible at 6 c US/kWh in Australia. This claim was neglecting the additional source of revenues from the large-scale-generation-certificates (LGCs), and the no-interest loan provided to the developer, and even more than that, the extremely poor performance of the already built Crescent Dunes plant featuring the same design in the United States, delivering about ¼ of the expected electricity subjected to many failures.

From a very subjective view of the PPA for Aurora, the 150 MW rated power, 135 MW under normal operating conditions, the plant was claimed to have an alleged cost of only AU 650 million (US 457 million), and the ability to deliver 495 GWh of fully dispatchable electricity annually over 20 years. The subjective claim that fully dispatchable solar electricity could, therefore, be produced at US 0.061 with the specific technology circulated in the press (smh.com.au, 2018; reneweconomy.com.au, 2018; ABC News, 2017), as well as the peer review (Pitz-Paal, 2017; Lilliestam et al., 2017; Lilliestam and Pitz-Paal, 2018; Feldman and Margolis, 2018). Murphy et al. (2019) moved even further, to forecast costs of US 0.05 per kWh by 2030 of this specific technology based on the PPA for Aurora.

The actual costs were larger. The LGCs were valued at around AU 80/MWh, which was already more than double the cost. A low-interest loan of 110 million AU was also provided to the developer. Then, from the consumers’ perspective, there were to factor indirect costs of the larger share of unreliable electricity production in a state, South Australia, where peak power were already up to AU 14,000/MWh after the closure of the state coal-fired power plants.

The single plant of the same technology as Aurora built in the world by the same developer, Crescent Dunes, Tonopah, Nevada, USA, of 110 MW capacity net, and 10 h of molten-salt TES, had a cost of 975 million US in 2015 values, corresponding to 1046 million US at 2019 values. However, while the planned electricity generation was 500,000 MWh/year (ε = 51.89%), the actual electricity produced in the best year up to the time the PPA was signed was only 127,308 MWh/year (ε = 13.21%).

As discussed in Boretti (2019a), to expect roughly six times better electricity production per invested (slightly less than three times better electricity production at slightly less than half the cost) of what was built and operated, in a worse site for what concerns the direct normal irradiance (DNI), 2382 kWh/m 2 /yr. vs. 2671 kWh/m 2 /yr., and with slightly less promising plant details, 2 h shorter TES, and dry, rather than the hybrid cooling condenser, was contemptibly optimistic. No investor, therefore, decided to risk on this project, which was canceled, ABC News (2019).

Unfortunately, the failure of the Aurora project, as well as the premature closure of the Crescent Dunes plant in the United States, and the cancellation of the other similar projects in the world by the same developer, has dramatically reduced the chances that CSP could grow in Australia as well as the rest of the world.

The failure is due to the surpassed design and the use of substandard components to pursue the impossible goal to compete price-wise with solar PV without accounting for the dispatchability. If dispatchability is not valued, then CSP with TES cannot compete with solar PV. While trying to make CSP ST with TES for 6 c/kWh in 2019 was impossible, just a few c/kWh more for a better design could have provided a cost-effective solution (again, when BES is factored, costs of solar PV are 11 to 18 c/kWh).

Forecasting of cost and production of plants CSP with TES has been done so far (NREL, 2018) adopting surveys by expert panels not based on real-world plant utility-scale built and operational. NREL proposes “consensus trends” for ε and Levelized costs of electricity (LCOE) that are not based on any reliable statistic. They only consider CSP ST with TES and neglect the much more reliable and widespread PT technology. The cost and performance prediction by IRENA (2012), the starting point for the NREL predictions, was similarly made without any plant utility-scale (100 MW) built. No real-world experience was included in the projections.

Remarkable, after the Crescent Dunes plant was finally built and operated featuring the reference technology, but delivering worse performances despite the higher costs, the forecasted cost and production were revised by NREL in the wrong direction by taking into consideration instead the power purchase agreement (PPA) signed for Aurora (Boretti, 2019a).

Analyses of the performance of utility-scale solar thermal power projects, in which actual performance and cost are compared to the predicted performance and the projected cost in which PT technology is compared to ST technology have been recently added to the literature (Boretti, 2018a, 2018b; Boretti et al., 2018). Projections of costs and performances by NREL have not yet reflected these real-world experiences.

Apart from Australia, which provides real-world production data of every power station with 3 min sampling frequency, and the United States, which provides data every month, the information about the real-world operation of renewable energy facilities is mostly unavailable. Unfortunately, Australia never had a CSP plant.

The number of CSP plants operational worldwide is limited, as shown in Table S.1 in the Supplementary. Most of these plants have been completed only recently, for none of these plants the information of electricity production with a high sampling rate is available. Only for the stations within the US, there is enough information with monthly data available since completion, but no high-frequency sampling.

Regarding the power stations of Morocco, there is no data on electricity production, apart from data of the year 2017 leaked by a student doing an internship in Noor 1.

Similarly missing are the data of the electricity production from the plants of China, South Africa, and India.

For the power stations in Spain, sometimes the figures for annual electricity production have been circulated. However, the data are not public domain as it is in the United States.

Regarding the power station in the UAE, it was reported (Sills and Daya, 2010), that because of substantial atmospheric dust, solar radiation received by Shams’ solar collectors was less than expected and more collectors would be required. Information about other difficulties operating in the harsh environment of the Gulf is not provided. Since 2013, no electricity production has been published. The figure presented in Table S.1 for electricity production from the listed source is unclear if predicted or delivered, and it is of uncertain origin. From Table S.1, it appears that only the PT technologies can be considered mature, with TES or without TES. The number of plants built and operated so far with also data available permits the definition of a small, but still, significant statistical sample, to be used for forecasting. Opposite, the information about the ST technologies is less, as there is in practice only one example to consider without TES (Ivanpah), plus only one example with TES (Crescent Dunes). From Table S.1, the only two plants 100 MW featuring ST presently operational in the world with data available are the 110 MW net Crescent Dunes, of 2019 actualized cost of 9509 US/kW, and the 377 MW net Ivanpah Solar Electric Generating System (ISEGS), Ivanpah, California, USA, of 2019 actualized cost 6260 US/kW. ISEGS has a distinctive design, boosting production of the ST without TES burning natural gas to ramp up (and support) production.

Completed in 2015, the 110 MW CSP ST with molten-salt TES of Crescent Dunes, of 2019 actualized cost of 9509 US/kW, has delivered annual ε of 13.03% in 2016, 4.42% in 2017, and 21.49% in 2018. It is 5.39% in 2019 after the plant was shut down in April, still better than the 2017 result. The planned ε of Crescent Dunes was much better than the delivered, 51.89%.

Better ε are delivered by recent CSP PT installations, solar only with no TES, such as the 2014 250 MW net Genesis, of 2019 actualized cost of 5360 US/kW or the 2014 250 MW net Mojave, of 2019 actualized cost of 6880 US/kW. Solar only with TES plants, such as the 2013 250 MW net Solana, of 2019 actualized cost 8720 US/kW, are also working better.

Completed in 2014, Genesis has delivered annual ε of 28.51% in 2016, 28.61% in 2017, 28.46% in 2018, and 28.14% in 2019. The planned ε of Genesis was less than the delivered, 26.48%.

Also completed in 2014, Mojave has delivered an annual ε of 28.53% in 2016, 27.12% in 2017, 27.12% in 2018, and 23.42% in 2019. The planned ε of Mojave was about the delivery of the first year, 28.17%. The performance of Mojave is now deteriorating.

Completed in 2013, Solana has delivered ε of 29.37% in 2016, 33.08% in 2017, 35.43% in 2018 and 36.04% in 2019. The planned ε of Solana was better than the delivered, 43.11%.

Completed in 2014, the ε of Ivanpah, are marginally above 20% despite the considerable boost by natural gas combustion 19.78% in 2015, 21.35% in 2016, 21.75% in 2017, 24.11% in 2018, and 23.31% in 2019. The planned ε of Ivanpah was also much better than the delivered, 32.68%, with negligible combustion of natural gas.

While the performance of Genesis is stable, and the performance of Mojave is deteriorating after only a few years, the performance of Solana is further improving even if minimally over the last 12 months.

Also, CSP PT installations completed in the 1980s and still operational, such as 7 of the 9 Solar Energy Generating Systems (SEGS) plants, work better than Crescent Dunes and Ivanpah.

At about 80 MW each, the complex was producing 354 MW of total power. SEGS IX has delivered a 2019 annual average ε of 19.99%, but with only a small contribution by natural gas combustion.

The data of electricity production and natural gas combustion used is provided by a reliable source, the United States Energy Information Administration (EIA), and it is in the public domain (EIA, 2019).

Figure 3 presents a comparison of the monthly ε that a CSP with TES should deliver to achieve an annual average ε of 51.89% as expected for Crescent Dunes, plus the actual ε of Crescent Dunes, Genesis, Mojave, Solana, ISEGS, and SEGS IX over the last four years and during the year 2018.

The figure also presents the data of the SEGS IX plant since 2001 (this is the year the EIA statistic starts, but this plant is operational since 1990) showing the relatively stable production of this design. Since 2001, this plant has operated with an annual ε maximum of 33.11%, a minimum of 19.70%, and an average of 24.61%, with minimum support from the combustion of natural gas.

When there is a boost by natural gas combustion, the EIA differentiates between the sun and natural gas heat supply. As discussed in Boretti (2018a, 2018b), this attribution is incorrect for two reasons. First, natural gas would be better used in a combined cycle gas turbine plant at twice the thermal efficiency of the power cycle. Second, without this boost, the solar-only plant is not able to deliver what is indicated as solar only.

The Figure also shows the data of the seven plants SEGS III to SEGS IX since 2001 for the solar production depurated of the natural gas boost as it is proposed by the EIA.

Worth of consideration, the life span of 30 years, which is above the 25 years typically optimistically used in the PPA for solar PV and wind, plus the relative stability of the sun output. A minimal decrement in the SEGS facilities ε sun only is an artifact of reducing the natural gas boost in recent years, improperly accounted for in the EIA statistic.

For what concerns ISEGS and SEGS IX, the total electricity production is obtained by also burning natural gas. The boost by natural gas combustion is limited for SEGS IX and extreme for ISEGS.

According to the predictions of the 2012 report by (IRENA, 2012), Table 1, CSP ST plants with molten-salt TES should have had a cost between 2010 US 6300 and 2010 US 10,500/kW of installed power (capacity), with TES between 6 and 15 h, and achieve ε from 40 to 80%, for electricity generation costs of about 2010 US/kWh 0.17 to 0.29. By considering the inflation, this translates a cost between 2019 US/kW 7371 and 12,285, for electricity generation costs of about 2019 US/kWh 0.20 to 0.34.

In the 2018 ATB, The CAPEX graph shows 8000 US/kW as the 2016 value, and it suggests a Rapid reduction of the CAPEX up to the time of the ATB and behind. Crescent Dunes, the only member of the population for this specific technology, had in 2015 a larger cost of 8863 US/kW. There were also added costs needed to put the plant back in operation after the failure of the molten-salt TES system also known at the time of the ATB, similarly ignored. A design such as Crescent Dunes does not have a CAPEX of 6600 US/kW in 2021.

The ε graph differentiates between fair, good, and excellent resources. A fair resource is Abilene, TX, 5.59 kWh/m 2 /day. Here, according to NREL, the ε was 42% in 2016. A good resource is Las Vegas, NV, 7.1 kWh/m 2 /day. Here, according to NREL, the ε was 56% in 2016. Finally, an excellent resource is Daggett, CA, 7.46 kWh/m 2 /day. Here, according to NREL, the ε was 59% in 2016. Crescent Dunes, the only member of the population for this specific technology, in a site of excellent resource, Tonopah, NV, 7.36 kWh/m 2 /day, commissioned in 2015, had in 2015 an ε of 0.37% in the three months it was run, then an ε of 13.20% in 2016. The ε of 2017 and 2018 has been 4.33% and 20.29%.

Regarding the Levelized cost of electricity, starting from an underrated present, the ATB then proposes an optimistic evolution, based on expectations of future technological improvements and cost reductions. Crescent Dunes was not delivering electricity at 120 US/MWh in 2016, and unlikely about the same design will allow electricity production at 100 US/MWh in 2021.

Moving from the 2018 ATB to the 2019 ATB, the only additional real-world information that could have motivated revised data is the further troublesome operation of Crescent Dunes. What we learn from Fig. 4 is that the CAPEX of 2017 is slightly less than the CAPEX of 2016, but the new CAPEX of 2050 is otherwise much less, 3950 US vs. 4800 US (mild trend). However, ε has dramatically increased from 60 to 65% (excellent resources). The LCOE moves down accordingly.

Based on a subjective interpretation of the signature of the PPA of Aurora, but not the cancellation of this project the same as the other projects by the same developer, these predictions have been made even more unrealistic. (Murphy et al., 2019) assumes a present cost of only 61 US/MWh and proposes a cost even lower to 50 US/MWh by 2030.

Discussion

In power generation, for other technologies, there are many power plants built and operated featuring the specific technology. Thus, cost and electricity production can be forecasted based on real-world information such as the construction cost, the costs to operate the plant, and the electricity production expected. If the technology is evolving, a reliable estimation of what can be expected soon in absence of a breakthrough may then be obtained by using one forecasting method. None will produce definitive answers, as nobody can see the future. Commonly used are moving averages, Exponential Smoothing (ETS), linear regression, parabolic regression. This procedure cannot apply for CSP, in the specific ST technology with TES.

Reality has been far from the predictions by NREL (2018) or NREL (2019), as shown in Boretti (2018a, 2018b), and Boretti et al. (2018), with much larger costs per unit of energy produced, because of the much smaller ε, and the much larger construction costs, of the ST plants, that have been so far inferior to the PT design.

High-frequency generation data every minute or less are unavailable for CSP. This data is, however, essential to understanding if the models are really helpful. There is no data on electricity production from CSP with better than monthly resolution, which is definitively not enough to appreciate the variability, or also to validate models.

Without accounting for the variability of the electricity supply, CSP makes no sense, as solar PV and wind are much cheaper. As a stable grid needs a stable supply matching the demand instantaneously, the key turn point in renewable energy is to quantify and price variability. A kWh of electricity available only during daylight time, or when the wind blows, has a different value from a dispatchable kWh of electricity. Thus, a variability parameter must be added the sooner the better in the technology forecasting.

Data of resource, weather, as well as of plant components as well as plant output, should be collected simultaneously over a full year with high-frequency sampling to permit a proper validation of the models and their components. Dramatic differences between expected and delivered performances are an indication that the design is made by assuming the operation of components and systems that are excessively optimistic. This poses the issue of substandard components, for example, a heat exchanger not providing the expected reliability, under transient loads, and failing, or heliostats losing track.

The largest CSP ST with monthly electricity production data and construction cost information is the previously mentioned Ivanpah completed in January 2014. The plant has performed so far well below the expectations, despite burning a much larger than planned amount of natural gas to boost combustion. There have been so far several failures. Performance degradation is unknown. The costs for repairs and the costs of using natural gas are unclear. The cost per kWh is difficult to be assessed. Construction costs were 2.2 billion US in 2014. The life span of the much simpler and more reliable CSP PT is 30 years. The life span of the more complex ST is not expected to be that long, especially without major maintenance works. From January 2014 to September 2019 included (69 months) Ivanpah has produced 3,899,050 MWh of electricity. Over the same time frame, Ivanpah has also burned 5,790,918 million Btu of natural gas, with however data for 7 months of the 69 missing not available or not reported. If we take optimistically a life span of 25 years or 300 months, Ivanpah will deliver a cost per kWh of roughly 0.13 US/kWh neglecting the repairs and the cost of the natural gas. Considering the cost of natural gas is presently very low, natural gas combustion does not increase too much the cost of electricity. The about 2.8·10 7 million Btu of natural gas that is expected to be burned by Ivanpah translates into a CO2 emission of 1.49·10 9 kg (1 million Btu of natural gas has an associated emission of 53.07 kg of CO2).

The only other CSP ST with monthly electricity production data and construction cost information is the previously mentioned Crescent Dunes completed in October 2015. Up to November 2019, Crescent Dunes, which had a cost of 0.975 billion US in 2015, has only produced 418,849 MWh of electricity over 50 months of irregular production, with many interruptions, with the last electricity produced in April 2019. This is only 2,513,094 MWh over 25 years or 0.39 /kWh. As reported by Deign (2020), the developer, Solar Reserve appears to have ceased operations.

With only these two CSP ST power plants in the database of costs and electricity production above 100 MW of installed capacity, it is certainly impossible to conclude what this specific technology can deliver in terms of dispatchable solar electricity and at which costs.

Having a statistically significant population of facilities, for what concerns the cost, if CAPEXi,j is the cost per unit nominal power, Pi,j is this nominal power, and εi,j is the annual capacity factor of the facility i, completed in the year j, then the average CAPEXj over all the n facilities completed in the year j is:

This number should be then corrected for the energy storage allowance.

Similarly, the LCOEj is obtained as the generation averaged of the LCOEi,j.

Also looking at the generation average values for what concerns performance, at least two parameters should be considered. One parameter is the annual average εj, and one additional parameter introduced to represent the variability about the annual average value is the standard deviation of the capacity factor δj.

The ε of the different facilities in the statistical sample considered for the year j are also weighed on the electricity generated:

Finally, forecasting techniques should be applied to the CAPEXj, LCOEj εj or δj, j = 1,…, m, where m is the time level, to infer the time trends.

Regarding CSP PT, even at 8720 US/kW, an ε of 36%, OM costs of 66 US/kW/year, a plant such as Solana may permit an LCOE of 11.3 c US/kWh working 30 years. Similarly, at 5360 US/kW, an ε of 28%, OM costs of 50 US/kW/year (OM with TES are significantly larger) a plant such as Genesis may permit an LCOE of 9.3 c US/kWh working 30 years. By further refining this design and mass-producing the components, this cost can be dramatically reduced, possibly to get much closer to the 6 c US/kWh incorrectly attributed to the ST with TES technology of Crescent Dunes.

CSP PT works much better than CSP ST. With no TES, PT work even better than the modeled expectations. With TES, they work slightly less than the modeled expectations.

Technology forecasting for CSP should also include PT, not only ST.

As an added remark, the present LCOE does not account for the variability of the power of electricity generation vs. the registered capacity.

In a system of wholesale spot prices, failure to deliver below 80% of the registered capacity has huge consequences. These consequences are presently voided for wind and solar power generation facilities, but cannot be avoided forever. With spot prices, up to 14 AU/kWh vs. averages of 10 c AU/kWh, and harsh penalties for failing to provide the promised outputs for other generations, is not reasonable to discuss LCOE of unpredictable electricity.

Every facility producing unpredictable electricity needs a back-up predictable facility, or dedicated energy storage to be accepted in the grid, where demand and supply are always balanced. While every facility does not have to be balanced individually, sooner or later the cost of balancing the grid will have to be shared among the different facilities supplying intermittent electricity, and the cost will have to be proportional to the value of the mean ε, as well as to a parameter such as the δ expressing the variability.

There have been expectations of unrealistic LCOE for specific CSP technology, ST with TES, to compete price-wise with wind and solar PV, without accounting for dispatchability. CSP is not competitive with solar PV or wind without factoring in dispatchability. CSP is however a key component of renewable energy-only grid, where not controllable electricity from wind and solar PV must be integrated with continuous or dispatchable electricity from CSP, hydro, or enhanced geothermal systems (EGS) plus the affordable amount of batteries and pumped hydro to have supply matching demand (Boretti, 2021a).

The claim of a present cost of CSP ST with TES of US 0.061 per kWh, further projected to reach US 0.05 per kWh by 2030, are speculations not based on any real-world data that have worsened rather than improved the perspectives of CSP ST with TES. It will take years to recover the sector from the bad reputation gathered from the Crescent Dunes and Aurora experiences.

The failure of Crescent Dunes is only the result of the attempt to compete price-wise with wind and solar PV without accounting for dispatchability. Regarding the Gemasolar CSP ST with TES design, Crescent Dunes had a smaller size of the solar field of heliostats per MW of turbine power (10,911 m 2 vs. 15,900 m 2 ). Accounting for the higher solar resource of Crescent Dunes, this is still significantly less (solar input per MW of power 28,915,162 kWh/yr. vs. 33,390,000 kWh/yr.). Thermal storage was also less, 10 vs. 15 h.

By exploring, in the default model of SAM (NREL, 2020) for CSP ST with TES, that includes the latest costs of performances by NREL, the opportunity of adopting a larger TES as well as a larger solar field vs. the suggested optimum, for a 110 MW plant in the specific location of NEOM City, it is found (Boretti and Castelletto, 2021a) that:

• Increasing the TES from 10 to 16 h LCOE, mean ε and δ all improve;
• By increasing the size of the solar field from less than 10,000 12.2 × 12.2 m 2 heliostats to 13,000–13,500 heliostats LCOE, mean ε and δ all improve;
• By further increasing the size of the solar field with heliostats above 13,500, mean ε and δ all improve, but LCOE increases.
• By increasing the number of heliostats from 13,500 to 18,500 permits ε ~ 95% at an LCOE of less than 8 c/kWh for continuous electricity supply in NEOM city.
• Also accepting 20% higher costs, the solution would be very competitive with solar PV and batteries, of expected life and performance much worse in the Kingdom of Saudi Arabia than elsewhere cause sand, dust, and high temperatures.

Apart from failures, regarding the modeling of CSP ST, there is the issue of the real operation of components differing from the design conditions. For example, heliostats lose tracking in time subjected to atmospheric load, and other components suffer from real-world operation performance differing from the operation assumed in the models. Especially in ST, the solar field collection is dramatically affected by the presence of clouds. Accurate models validated under realistic Cloud coverage are still missing, even because real-world instantaneous data of electricity production and irradiance are missing. The effects of clouds make unreliable every prediction of CSP ST with molten-salt TES plants’ performances. Thermal transients are particularly challenging in CSP ST with molten-salt TES.

The further progress of CSP will depend on the successful operation of the novel solar facilities such as Dubai One, featuring CSP parabolic trough with TES, CSP solar tower with TES, and PV in the different units. Only full transparency on the construction and maintenance costs, as well as of electricity production sampled with high frequency, plus the sharing of plant characteristics and high-frequency data of system and components operation, resource and other environmental variables for modeling, may bring back confidence in the CSP technology.

Conclusions

The work has reported the CSP plants that have been developed or proposed, locally and overseas, highlighting the reasons for the poor uptake of this technology, especially in Australia. CSP is more sophisticated, less widespread, and therefore more expensive and less reliable than wind and solar PV. During the early growth phase of renewable energy, when the interest is to quickly build up capacity, wind and solar PV have huge advantages vs. CSP having a cost per unit installed power that is much less. The attempt to compete price-wise with wind and solar PV is what has produced substandard developments that have undermined the reputation of CSP technology. It is in the current growth phase of renewable energy, where the aim is to make a grid renewable energy only without any supply from combustion fuels, that the energy storage issue is coming out, and CSP is gaining new interest. Opposite to wind and solar PV power plants that may deliver power to the grid only phased with the contemporary, instantaneous, availability of the wind and solar resource, and thus necessitates of huge energy storage, which is economically very expensive, CSP plants have the advantage of dispatchability, i.e., production of electricity on demand, thanks to the much cheaper internal thermal energy storage. Further developed for higher temperatures, (Boretti and Castelletto, 2021b), CSP may have better efficiencies of the thermal cycle and reduced LCOE. While a CSP plant cannot have a levelised cost of generic electricity lower than a PV solar plant, it may have a much lower cost of similarly dispatchable electricity from a PV solar plant plus BES. Aiming at a renewable energy-only grid, CSP is therefore expected to grow even more than solar PV and wind, in a grid managed by artificial intelligence (Boretti, 2021a) that is however built on the supply of power of different characteristics from wind, solar PV, and CSP, stabilized by BES and PHES, and production of green hydrogen. the hydrogen economy is complementary and synergetic to the electric economy (Boretti, 2021b)—with further quality contributors hydroelectric, biomass and possibly enhanced geothermal energy (Boretti, 2021c) and nuclear. While renewable hydrogen production is expected to progress in the current phase as green hydrogen, from excess wind and solar photovoltaic electricity and electrolysis, it must be mentioned that higher temperature concentrated solar energy and thermal energy storage may be used to run a thermochemical hydrogen production plant rather than a high-temperature power cycle with clear synergies between electricity production and production of hydrogen (Boretti, 2021d, e). CSP ST with TES is the most promising renewable energy technology permitting dispatchability. It must be competitive when dispatchability is factored in, not without. Until the pricing will include dispatchability, it will suffer from the competition of the much cheaper wind and solar PV, which, however, are not dispatchable without the unaffordable batteries. Fully dispatchable solar electricity from CSP ST with TES is achievable in Australia for 8–10 c/kWh, well below every alternative.

Data availability

No new data were generated in this work. The data used across the work are available at the listed references.

Acknowledgements

The authors want to thank Andrew Miskelly for permission to reuse the images of his website in the manuscript.

Author information

Authors and Affiliations

• Deanship of Research, Prince Mohammad Bin Fahd University, Al Khobar, 34754, Saudi Arabia Alberto Boretti
• School of Engineering, Royal Melbourne Institute of Technology (RMIT) University, 3083 Bundoora, Melbourne, VIC, Australia Stefania Castelletto

Concentrated solar thermal

Home / Energy Power / Renewables / Concentrated Solar Power Market

Concentrated Solar Power (CSP) Market Size, Share COVID-19 Impact Analysis, By Technology (Parabolic Trough, Power Tower, Linear Fresnel), By Application (Residential, Non-Residential, Utility) and Regional Forecasts, 2021-2028

Report Format: PDF | Latest Update: Feb, 2023 | Published Date: Nov, 2021 | Report ID: FBI100751 | Status : Published

The concentrated solar power (CSP) market size was USD 37.25 billion in 2020 and is projected to grow from USD 41.68 billion in 2021 to USD 119.52 billion in 2028 at a CAGR of 16.2% in the 2021-2028 periods.The global impact of COVID-19 has been unprecedented and staggering, with the concentrated solar power industry witnessing a negative demand shock across all regions amid the pandemic. Based on our analysis, this market exhibited growth at a stagnant pace of 6.3% in 2020. The sudden rise in CAGR is attributable to this market’s demand and growth returning to pre-pandemic levels once the pandemic is over.

Concentrated solar power involves the use of mirrors to concentrate the received sunlight, a central focal point. Here this energy is converted into heat, which can then be used to produce steam to drive a turbine or be used as industrial process heat. These systems can integrate thermal energy storage systems, which can generate electricity during cloudy periods and the absence of sunlight. Several modern technologies such as parabolic troughs, fresnel reflectors, and power towers are available for this technology, and depending upon the given conditions, the best one can be deployed.

Harmful Effects of COVID-19 on Renewable Energy

The COVID-19 crisis has had an alarming effect on the entire renewable energy industry. The global supply chain has been heavily impacted as the imports of raw materials came to a halt for a certain period. The CSP plants require a huge human force to be on the field to complete the installations, and the lockdowns in many countries have resulted in a shortage of laborers. Many ongoing projects have been put on hold for an unspecified timeline across the globe due to the import dependency and logistical delays. Around 40% of the imports of solar trackers and other required equipment are from China, which has been the first nation to be heavily impacted by the COVID-19 threat. In China, acknowledging the growing destruction, solar modules and concerning equipment were being halted, which brought the global market to a halt.

Following this condition, government bodies and private companies have pushed forward the commissioning dates for certain projects to be brought into operation in the coming months. This will certainly affect the investments being made in the market in the coming years and delay the pipeline projects. But on the brighter side, the solar energy industry is expected to be back on track in a short period compared to other industries such as oil and gas. This will propel the investments for CSP technology in many countries around the globe and therefore drive the market at a healthy rate.

LATEST TRENDS

Push Towards Advance Solar Energy Technologies Will Attract Investment in the Market

As solar energy installations have increased and higher operating efficacies recorded across the world, major industry players are now working on bringing in more advanced technologies, which will boost the current power generation. New heat transfer fluids such as high-temperature salts, sCO2, proppants are being tried, which increase the heat transfer capability with minimum losses. Also, researchers are working on new coatings for receivers, which will reduce the amount of light reflected away.

Steps to Decrease the Cost of Various Equipment in CSP System Will Fuel Capacity Additions

As concentrated solar power is now being adopted across different countries, governments can take steps to reduce the cost of CSP systems. As these systems offer various operational advantages and are highly efficient, these are expected to play a major role in achieving green energy targets for many countries in the coming years. Therefore, lowering the cost of installation will attract investors, and CSP would be integrated into utilities on a global scale. For instance, the U.S. government is working on measures that would reduce the cost of CSP systems by offering incentives.

DRIVING FACTORS

Growing Adoption of Renewable Sources for Power Generation to Boost the Market

The growing demand for never-ending energy sources and the need to control carbon emissions across the globe has put renewable energy sources in the limelight over the last decade. Considering the increasing CSP installations, the global capacity at the end of 2010 was 1.3 GW, which has grown exponentially to reach more than 6 GW in 2019. This trend of growth in renewable energies in the power mix of every nation is expected to continue with more and more investments planned in the coming years. Currently, renewable sources account for around 29% of the total electricity generation across the globe, which is expected to rise at an exponential rate in the coming years and therefore drive the growth of the market.

Higher Efficiency and Low Operating Cost as Compared to Solar PV to Aid Growth

As several countries are putting in strong efforts to reduce carbon emissions, they are looking for highly efficient systems and produce a large amount of power. Concentrated solar power plants can stand as the best possible solution for this as these are capable of power generation with higher efficiencies and lower operating costs as compared to solar PV. Also, these systems can use thermal storage to match the supply-demand and are scalable to large capacities.

RESTRAINING FACTORS

Heavy Capital Investment and Higher Cost of Electricity Per Unit Poses Threat to Market Growth

The key market restraint for this market is the heavy capital investment to be made for installing this plant. Also, the requirement of a large area may lead customers to prefer solar PV installation over this technology at residential and commercial locations. Further, the average cost of electricity generated by CSP is USD 0.20/kWh, and for solar PV, it is between USD 0.5-0.10/kWh, which stands as a major drawback of the system.

SEGMENTATION

By Technology Analysis

Preference of Parabolic Trough Systems Over Others Will Drive the Growth of this Segment

Based on technology, the concentrated solar power market is segmented into the parabolic trough, power tower, and linear Fresnel. Parabolic trough being the most advanced amongst the available technologies is expected to lead the market. Also, it requires less capital investment as compared to its counterparts. Out of the projects granted in 2019, 45% used the parabolic trough technology. Power towers are expected to have healthy growth due to their higher efficiency and better capability to store energy.

By Application Analysis

Growing Solar-Grid Integration Will Drive the Growth of Utility Segment

In terms of application, the market is segmented into residential, non-residential, and utility. As the concentrated solar power installation requires huge capital investment, their penetration at residential and commercial centers is very low compared to utilities. CSP installation for utilities help in managing the power demand, peak load shaving and allow integrated thermal storage with varying time for varying technologies. These factors have led to the lion’s share of the utility segment in the global market. Furthermore, numerous financial and economic benefits, including Feed-in Tariffs (FiT) and tax credits offered by several governments across the globe, will augment the segment growth.

REGIONAL INSIGHTS

The concentrated solar power market has been analyzed geographically across five key regions, including North America, Europe, Asia Pacific, the Middle East Africa, and Latin America. In the Middle East, the UAE, Morocco, and South Africa are the major contributors to the Concentrated Solar Power (CSP) market growth. The growing need to produce continuous renewable power to support rising economic activities is boosting the market growth in the region.

In Europe, Spain has been the leading country for concentrated solar installation in the region. The presence of leading global players and the high success rate of the initial projects have been the catalyst for the country’s lion share in the global market. Following Europe, North America has maximum operating concentrated solar projects. In 2016, Europe and North America together formed approximately 3/4th of the global market, which has now been reduced to around 60% in 2019. In North America, the U.S. has many CSP projects with an installed capacity of 1,741 MW.

The Asia Pacific has witnessed a substantial increase between 2016 and 2019, with projects commissioned in India and China. China has rolled out plans for 20 concentrated solar pilot projects to be run within the country starting from 2016. In September 2019, Power China Gonghe 50MW Molten Salt Tower Project was successfully connected to the grid. In Latin America, Chile and Mexico have concentrated solar plants under construction and are expected to operate in 2021.

KEY INDUSTRY PLAYERS

Siemens, Abengoa Solar, BrightSource Energy Are Amongst the Leading Players in the Market

The competitive landscape of the concentrated solar power market depicts a market dominated by companies focused on technological advancements that lead to increased efficiencies at a lower production cost. Companies such as Siemens, BrightSource, and Abengoa Solar have a strong presence in Europe and North America, which are the leading CSP installations. These companies are working towards establishing a strong foothold in the market as investments in this technology are expected to boost in other regions such as the Asia Pacific and the Middle East. In December 2019, BrightSource Energy developed a new kind of absorber coating, i.e., solar-cured coating, for the Dubai Electricity Water Authority (DEWA) Tower project. The coating was designed for extended service lifetime and higher absorption than the standard Pyromark coating and to help reduce OM costs.

With the market’s growth, the other industry key players such as Sener, Abors Green GmbH, Solar Reserve are expected to have ample opportunities, which will lead towards a competitive market for CSP sales in the coming years.

LIST OF KEY COMPANIES PROFILED:

• BrightSource Energy (U.S.)
• Abengoa Solar (Spain)
• Siemens (Germany)
• Acciona (Spain)
• Solar Reserve (U.S.)
• ACWA Power (Saudi Arabia)
• Torresol Energy (Spain)
• Trivelli Energia (Italy)
• Abors Green GmbH (Germany)
• Parvolen CSP Technologies (Greece)
• Sener (Spain)
• Rioglass (Belgium)

REPORT COVERAGE

The concentrated solar power market report provides a detailed analysis of the market and focuses on key aspects such as leading companies, product types, and leading product applications. Besides this, the report offers insights into the market trends and highlights key industry developments. In addition to the aforementioned factors, the report encompasses several factors that have contributed to the market’s growth in recent years.

Report Scope Segmentation

Study Period

High-power potential: the future of concentrated solar power

We speak to Hyperlight Energy to learn how concentrated solar power’s efficient and flexible characteristics could aid in the energy transition.

JP Casey

Solar power, alongside wind, is something of a poster child for renewable power, and with images of rooftop-mounted panels and swathes of undeveloped land covered in solar farms a mainstay of energy writing, it is easy to see why. Solar has enjoyed decades of consistent growth, with Our World In Data reporting that from the first recorded instance of solar power in 1983, to its most recent figures in 2020, global electricity consumption from solar sources passed 2,000TWh.

Still, solar power is not a one-size-fits-all practice – as evidenced by the difference between rooftop panels and utility-scale plants – and perhaps the greatest variance within the sector is between photovoltaic (PV) panels and concentrated solar power (CSP). Simply put, CSP uses mirrors to concentrate the sun’s rays to particular points on solar panels, dramatically improving the efficiency of the practice, at the cost of additional manufacturing complexity at the beginning of the construction process.

Environment Sustainability in Power: Quantum Dot Solar Cell Manufacturing

Hyperlight Energy

CSP Inc

Yet CSP has been historically under-utilised compared to its more conventional cousin, PV. University College London reported that by the end of 2014, there was more than 140GW of PV capacity installed around the world, compared to just 5GW of CSP. With high-profile failures and industrial caution urging investors to stay away from high-reward CSP practices, will the future of solar power remain dominated by PV systems?

CSP versus PV

One company pushing back against this imbalance is Hyperlight Energy, an American firm whose work includes the Hylux solar steam technology and that has already received a 5.4m grant from the California Energy Commission to develop CSP solutions in the state.

“For utility scale, [a solar photovoltaic panel] will go on many 100-acre or 100-hectare deployments,” explains Hyperlight CEO and founder John King, who remains keenly aware of the imbalance in the solar sector. “Then it connects directly to the grid and provides electric power, so the photovoltaic effect is native electric, photons moving electrons. CSP, over the last decade and a half, has not been as widely deployed.”

“It has advantages and disadvantages, [including] concentration, where you are using mirrors instead of PV panels, a silicon-based technology,” King continues, going into detail about the role of the mirrors in CSP. “Mirrors bounce the photons and aim them all on a common target, so that’s where you get concentrated, and that target gets very hot. I like to say it’s just like a kid using a magnifying glass to burn a hole in a leaf. When you concentrate sunlight, it’s very powerful.”

Despite what may or may not be common assumptions about the high start-up costs of CSP facilities, King is optimistic that the improved efficiency of the CSP process can yield dividends in the long-term. This is particularly significant considering the inherent inefficiencies associated with PV technology.

A combination of technological limitations and the inflexibility of a system that does not move as the sun moves has combined to create solar panels whose efficiency often hovers around 20%, with the most efficient panels for home use boasting efficiencies of just 22%.

“For PV panels, you’re just capturing the visible portion of the spectrum,” says King, who notes that the relative maturity of technologies such as mirrors further improves the economic efficiency of the entire CSP project. “About half the energy in sunlight is visible and about half is infrared, which is heat, and PV only gets the visible. When you’re bouncing photons, you bounce all over them.

“You have about twice the energy capture possible per unit of surface area, and the surface area you’re using to get the photons is cheaper.”

Scaling challenges

Of course, there are reasons for the relatively under-developed CSP sector, beginning with the logistical and manufacturing challenges associated with a technology predicated on tracking and responding to the sun’s movements.

“If you’re aiming and the sun moves, your reflection is off, so you have to move,” says King. “These giant reflectors are like aeroplane wings; a single gust of wind gives lift and will knock you off of alignment. So you have these very complicated, expensive metal structures to make sure that doesn’t happen, and so that eats into your cost advantage.

“Picture a 95m² mirror on a pedestal. That’s an enormous amount of lift, that’s the size of an aeroplane. You can lift jumbo jets in the air with that much lift, that’s how much lift we’re talking.”

There is also something of an unfavourable reputation tarnishing the idea of CSP, especially in the US, thanks to the publication of the ‘Concentrating Solar Power Best Practices Study’ in 2020. The report, led by the National Renewable Energy Lab, compiled feedback from representatives from around 80% of the world’s operating CSP plants, and found 1,008 technological and operational issues associated with these projects.

In fairness, the report’s introduction notes that its authors are confident “that future tower and trough plants can be built on time and within budget and will perform as expected”, but the range of problems identified will do little to encourage greater adoption of a technology that is already under-utilised. Similarly, the high-profile failure of the Crescent Dunes facility in the US state of Nevada, where leaks to molten salt tanks caused the facility’s production to drop to as low as 3% of its total capacity, raised questions about the economic and productive viability of large-scale CSP plants.

“You’re chasing economies of scale,” says King, pointing out how the pursuit of large-scale production can lead to similarly large-scale issues. “So what everybody in the industry, except us, did was they would build a 500KW pilot design, and then go raise 100m, a billion dollars to then build a multi-100MW plant.”

“You’re going up 1,000x scale in one step. When that happens you have problems that manifest at 1,000x scale, and you have to fix it at 1000x.”

A flexible renewable future

CSP does offer one distinctive advantage over PV, however, and this is a benefit that also extends beyond most other forms of renewable power: its use of heat. In 2018, the International Energy Agency reported that heat makes up two-thirds of the energy demand of the world’s industries.

The production of this heat accounts for one-fifth of the world’s total energy consumption, meaning that securing a reliable and clean source of heat could make a significant difference to the world’s carbon footprint.

“For heavy industry, they actually need the heat,” says King, explaining how CSP’s FOCUS on generating heat, rather than electricity, grants it a unique position to provide power to industrial facilities. “Large sections of the economy, large sections of industry, need the heat, they don’t need electricity.

“So for the right kind of site, the right kind of end-use, we can come in and displace fuel, usually natural gas, burned for process heat, and then you don’t have to build that power plant.”

King also pointed towards the flexibility of CSP infrastructure as a potential benefit, not just for CSP but the energy industry as a whole. The need to construct CSP facilities alongside other power plants or energy facilities, and the fact that CSP produces both heat and electricity, means that CSP can work in tandem with a range of other energy sources, helping to both generate power on its own, and decarbonise other energy industries.

“I think in the future, one of the things that could happen, and that I hope does happen, is the infrastructure we’ve put in place, and if others put in place too, the oil patch, California, could be leveraged going forward,” explains King.

“You might get the mirrors in place to generate the steam, to go downhole and get the oil out. [Eventually] the well runs dry and then you’re out of oil; that’s probably going to happen on a timeframe where you still have a lot of useful life on the solar equipment.

“So I could see a world in which you say ‘well, the solar equipment is long since paid for, let’s build a power plant and keep it in service and do some green power type of thing’.”

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He also pointed to the work of Ørsted, which became an excellent example of decarbonising industry by shifting its business from 85% oil and gas to 85% offshore wind in a decade. With time to achieve the world’s

climate goals quickly running out, and many climate challenges taking on a complex, multi-faceted nature, perhaps the flexible elements of CSP could help accelerate its adoption in the future.

Solar Thermal Storage

Concentrated Solar Power ( CSP ) plants require the use of a specific heat transfer fluid (HTF) that is designed to work to the correct temperature for prolonged periods in solar thermal electricity applications.

How does concentrated solar power work?

CSP uses reflectors to concentrate sunlight onto a receiver containing heat transfer fluid. which is heated and used to convert water to steam. The steam turns turbines, leading to electricity generation. The heat transfer fluid can also be used to store energy from the sunlight, allowing consistent power provision despite the intermittent supply of sunlight.

Globaltherm ® Omnitech is a high performance synthetic heat transfer fluid designed to meet the demands of liquid or vapour phase systems and indirect heat transfer. The no.1 choice for concentrated solar power and thermal electricity applications, PET and plastics production and chemical industries.

About Globaltherm® Omnitech

Globaltherm ® Omnitech is a synthetic thermal fluid which combines low viscosity and exceptional thermal stability for consistent performance.

• Globaltherm® Omnitech is a diphenyl ether- biphenyl HTF mixture
• The eutectic mixture of diphenyl oxide and biphenylgives this heat transfer fluid flexibility to perform in both vapour and liquid phases. It is miscible and interchangeable (for top-up or dilution purposes) with other similar mix thermal fluids.
• Globaltherm Omnitech HTF has low viscosity (2.5 cst at 40°C [104°F])
• This thermal fluid is excellent for use in heat transfer fluid systems which require very precise temperature control due its ability to operate as a vapour phase fluid
• This heat transfer fluid is highly dependable

Contact us for more information on high temperature thermal oils

We provide advice on how to choose the most appropriate oil for your heat transfer applications and provide our customers with continued technical support.

Call us on 44 (0)1785 760555 for more information

Globaltherm ® Omnipure is a highly efficient non-toxic, heat transfer fluid that is designed specifically for Concentrated Solar Plant ( CSP ) and thermal storage applications, PET and plastics production and chemical industries.

About Globaltherm® Omnipure

This heat transfer fluid is made from highly refined mineral oil and has superior oxidation properties for optimum performance.

• Globaltherm® Omnipure thermal fluid is made from severely hydro-treated base stocks and has outstanding thermal oxidation stability allowing for operation at high temperatures for extended periods.
• Globaltherm® Omnipure is non-hazardous, non-toxic, water white and odourless.
• This heat transfer fluid is specifically developed for non-pressurised, indirectly heated, liquid phase heat transfer systems found in Concentrated Solar Plant ( CSP ) and thermal storage applications that require bulk temperatures up to 326°C (619°F)

Contact us for more information on high temperature thermal oils

We provide advice on how to choose the most appropriate oil for your heat transfer applications and provide our customers with continued technical support.

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Non-hazardous, low toxicity, silicone based heat transfer fluid. Globaltherm ® Omnisol is the high temperature silicone based thermal fluid for Concentrated Solar Power ( CSP ) thermal storage applications.

About Globaltherm® Omnisol

• Globaltherm® Omnisol – is a silicone based heat transfer media used in solar thermal storage applications at high temperatures.
• Omnisol can safely withstand temperatures up to 425°C (797°F).
• Globaltherm® Omnisol delivers the high thermal stability and reliable heat transfer of a polydimethylsiloxane mixture with a low pumpability point of.65°C (-85°F). Globaltherm ® Omnisol is a high performing low toxicity, low fire risk, heat transfer fluid for CSP applications operating up to 425°C (797°F).
• Globaltherm® Omnisol is suitable for use in parabolic trough applications requiring a low freeze point and low temperature pumpability.

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Non-toxic and non-flammable heat transfer media. Globaltherm ® Omnistore MS-600 is the high temperature heat transfer media for Concentrated Solar Power (CSP) and thermal electricity storage applications.

About Globaltherm® Omnistore MS-600

• Globaltherm® Omnistore MS-600 – is a molten salt heat transfer media used in solar thermal storage applications at very high temperatures.
• Omnistore MS-600 can safely withstand temperatures up to 600°C (1076°F), higher than most heat transfer media on the market today.
• Globaltherm® Omnistore MS-600 molten salt heat transfer media has excellent thermo-physical properties in the liquid state, such as low viscosity. high heat capacity, and high thermal conductivity. Globaltherm’s heat transfer molten salts provide long-term heat storage for high-temperature applications.
• Globaltherm® Omnistore MS-600 minimises safety hazards and the need for high-pressure equipment.

Contact us for more information on high temperature thermal oils

We provide advice on how to choose the most appropriate oil for your heat transfer applications and provide our customers with continued technical support.

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Globaltherm ® S is a high performance heat transfer fluid for use in closed loop, non-pressurised heat transfer systems. Primary uses are chemical industries and plastic processing applications.

Globaltherm ® S is recommended for use in an upper temperature range from 250°C (482°F) to 350°C (662°F), but can be used intermittently at film temperatures as high as 380°C (716° F).

• Globaltherm® S heat transfer fluid is non-corrosive and can be used in non-pressurised heat transfer systems
• This heat transfer fluid can be used in systems requiring start-up temperatures as low as.5°C (23°F) without the need for heat tracing
• Globaltherm® S thermal fluid is thermally stable up to 300°C (572°F) and can be used for several years below this temperature with no adverse impact on performance
• Low viscosity 17cSt @ 40°C (104°F) with a pumping limit at.5°C (23°F)
• This thermal fluid has a high ASTM D93 flash point at 200°C – the highest in class
• Globaltherm® S has high thermal stress resistance in the bulk temperature range from 60°C-350°C (140°F. 662°F)
• Globaltherm® S has a highly aromatic structure with a boiling point range of 385°C.395°C (725°F.743°F). the highest in class

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We provide advice on how to choose the most appropriate oil for your heat transfer applications and provide our customers with continued technical support.

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There are four optical types of CSP system:

These are the most well developed CSP systems. They use parabolic reflectors to concentrate sunlight onto a receiver directly above the middle of the parabolic reflector. The receiver is filled with heat transfer fluid. which absorbs the thermal energy from the sunlight. The reflectors track the sun along a single axis to maximise the amount of thermal energy they pick up.

Also known as central receiver systems, solar power towers use an array of dual axis mirrors called heliostats, which track sunlight. These systems offer higher energy efficiency and better thermal energy storage capability than parabolic troughs.

These systems consist of a stand-alone parabolic reflector that concentrates sunlight onto a receiver. The reflector tracks the sun along two axes and the system uses a Stirling Engine to generate power.

Linear Fresnel reflectors

These systems are made of multiple thin, flat reflectors that concentrate sunlight onto tubes through which heat transfer fluid is pumped.

What are the thermal fluid options?

Globaltherm ® has a range of heat transfer fluids designed for use in CSP applications. They work at precise temperatures for prolonged periods of time. The range is highly efficient and each product has different qualities to suit a range of applications. These fluids also have superior anti- oxidation properties for optimum performance.

How long will my heat transfer fluid last?

All heat transfers will degrade over time and engineers should monitor the degradation process to ensure that it does not impact production. When operated at a high temperature for long periods of time the fluid will begin to break down.

When the bonds between of hydrocarbon chains break, this produces short-chained “light ends”. The higher the operating temperature, the more light ends are generated, and the rate at which they are produced is dependent on the oil type and the operating temperature.

Light ends boil and ignite at lower temperatures and reduce the flash point of thermal fluid. This creates a fire hazard and companies have a duty to manage this in line with the Dangerous Substances and Explosive Atmospheres Regulations (DSEAR) as well as with the explosive atmosphere ( ATEX ) regulations. Light ends also lead to cavitation in thermal fluid system pumps, which can lead to operational problems. When light ends are generated, both system and workforce safety are severely compromised.

How will I know if the flash point has dropped?

The heat transfer fluid cannot be seen when circulating inside the system, so it is difficult to monitor its condition. Implementing regular thermal fluid testing and analysis is the best way to understand what is happening inside the system.

Global Heat Transfer’s flash point management service includes two flash point tests. Engineers will do an open test to test the fluid when it comes into contact with oxygen and a closed test when the fluid is contained in the system.

If sample analysis shows that the flash point temperature has dropped then it is highly likely that there are light-ends contained in the fluid.

How do I remove light-ends?

Light-ends removal kits for thermal fluid regeneration are specifically designed to manage the flash point by removing volatile light ends from a heat transfer system. The light ends removal thermal fluid regeneration kit is tailored to the heating system and the thermal oil used.

It can be used on both large and small systems, which may be open or closed, and used with both mineral and synthetic thermal fluids. It can be used for a fixed duration on a temporary basis when using the active pump-fed unit, or as a permanent installation to manage light ends on a continuous basis.

How else can I extend fluid lifespan?

As a part of Global Heat Transfer’s preventative maintenance programme, Thermocare, manufacturers can receive 24 hour engineering support for their systems. These engineers will also take regular samples and analyse the fluid to give concentrated solar power plant managers an accurate representation of what is happening inside the system.

Where can I get more advice about choosing and monitoring heat transfer fluids for solar?

We offer a range of thermal fluids and services that will ensure your heat transfer system is always running efficiently.

For more personalised advice, call our team on 44 (0)1785 760 555 or visit our contact page.

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