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A case study on combined cycle power plant integrated with solar energy in Trinidad and Tobago
Sustainable Energy Technologies and Assessments 32 (2019) 100–110
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A case study on combined cycle power plant integrated with solar energy in Trinidad and Tobago
T
Albert Borettia, , Sarim Al-Zubaidyb ⁎
a b
Independent Scientist, Bundoora, VIC, Australia The University of Trinidad and Tobago, Trinidad and Tobago
ARTICLE INFO
ABSTRACT
Keywords: Renewable energy Natural gas Concentrated solar power Parabolic trough Solar tower Clouds coverage Trinidad and Tobago
Aim of the paper is to evaluate the benefit of a renewable energy initiative for Trinidad and Tobago. Trinidad and Tobago have abundant natural gas, a highly developed power generation system almost entirely based on combustion fuels, high solar irradiation, but skies often covered by clouds, a detrimental factor for concentrated solar power technologies. The simple, consolidated, parabolic trough technology, without the addition of thermal energy storage, has the potential to deliver better than solar photovoltaic capacity factors at a comparable cost when mass produced. Integration with natural gas combustion may permit to address the issues of clouds coverage. A computational analysis is proposed for an Integrated Solar Combined Cycle power plant comprising a reference combined cycle gas turbine plant, and a small solar field, located in Trinidad and Tobago. The simulations demonstrate the advantages, in terms of fuel conversion efficiency, of the small solar field addition. On average over the year, the plant operates over the morning and afternoon periods, of length about 8 h a day, at an efficiency of 57.34%, about 2.58% better, and over the mid-day periods, of length about 4 h a day, at an efficiency of 57.97%, about 3.16% better.
Introduction Refs. [1] and [2] have recently reviewed concentrated solar power (CSP) and solar photovoltaic (PV) plants. The solar tower (ST) with enhanced thermal energy storage (TES) is the suggested “current” technology for CSP plants [3]. However, the single plant utility-size of this kind completed so far in the world, the 110 MW capacity Crescent Dunes, despite the very high capacity-specific cost, has been producing electricity well below the expectations. The construction cost of Crescent Dunes, completed in 2015, was 1b$ [1,2], for an actualized (2017) capacity-specific cost of 9227 $/kW. Operational since the end of 2015, the annual capacity factors of this plant have been 13.21% in 2016, and only 4.36% in 2017, well below the design value of 51.89%. The plant has been out of service due to the TES failure for 7 months in between 2016 and 2017, and in no single month so far, it has matched the planned electricity output. Much better performances of ST at reduced costs have been delivered so far by parabolic trough (PT) plants, that have the potential, after mass production, to compete with PV plants [2] in terms of costs. Opposite to PV, however, CSP dramatically suffers of clouds coverage [4,5,26]. Trinidad and Tobago are the third richest country in the Americas after the United States and Canada by GDP (PPP) per capita. The ⁎
country has large reserves of oil and natural gas, with a predominantly industrial economy based primarily on petroleum and petrochemicals. The main exports are petroleum, liquefied natural gas, methanol, ammonia and urea. Electricity is produced by processing natural gas in high efficiency plants such as the combined cycle Trinidad Generation Unlimited power plant. The already excellent production of electricity may be strengthened by integrating solar energy with the gas generation system in a renewable energy project progressing the renewable energy uptake within the country. If the standalone CSP ST technology with enhanced TES is an extremely expensive and risky opportunity to explore in Trinidad and Tobago, much better perspectives are offered by the simpler, more consolidated, CSP PT technology, without any TES, integrated with natural gas combustion [2]. This technology has the potential to deliver better than PV capacity factors at a reduced cost when mass produced [2]. As Trinidad and Tobago has, in addition to abundant natural gas and a highly developed power generation system, high solar irradiation, but skies often covered by clouds, Fig. 1, that is a detrimental factor to CSP, the integration of the PT CSP technology with natural gas combustion appears one of the avenues to progress renewable energy in the country. Integrated Solar Combined Cycle (ISCC) power plants, Refs. [6–11,27–29] commented hereafter, are a technology with the
Corresponding author. E-mail address: [email protected] (A. Boretti).
https://doi.org/10.1016/j.seta.2019.02.006 Received 19 July 2018; Received in revised form 16 December 2018; Accepted 28 February 2019 2213-1388/ © 2019 Elsevier Ltd. All rights reserved.
Sustainable Energy Technologies and Assessments 32 (2019) 100–110
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Fig. 1. Direct normal irradiance in Trinidad and Tobago. Image reproduced modified after globalsolaratlas.info. In Couva, Couva-Tabaquite-Talparo, Trinidad and Tobago, the DNI (Direct Normal Irradiation), solar radiation component that directly reaches the surface, is 1616 kWh/m2 per year. This is the component relevant for concentrating solar thermal power plants (CSP).
There are few examples of ISCC around the world. The ISCC plant in Hassi R’Mel, Algeria [12,13] has 20 MW from a PT field out of the total output of 150 MW. The solar field is by Abengoa Solar. The solar field aperture area is 183,860 m2. The number of solar collector assemblies (SCAs) is 224, the number of loops is 56, for a SCAs per loop of 4. The SCA length is 150 m. The number of heat collector elements (HCEs) is 8064. The heat transfer fluid type is thermal oil. Inlet temperature is 293 °C and outlet temperature is 393 °C. Cooling is dry. Completed in 2011, cost was 350 m€. Electricity production data is not available. The ISCC plant in Kuraymat, Egypt [14] has an overall capacity of 140 MW, 120 MW combined cycle and 20 MW solar thermal PT. The solar field aperture area is 130,800 m2. The number of SCAs is 140, the
potential to reduce fossil fuel use integrating solar power. In the ISCC, solar energy is used as an auxiliary heat supply, that may be replaced partially, or completely, by burning combustion fuels, supporting the steam cycle of a combined cycle gas turbine/steam turbine. The solar field results in a reduction of the fossil fuel use when the sun shines. Ref. [6] shows reduced costs of solar-generated electricity versus standalone concentrated solar power systems with or without TES while providing dispatchability. Ref. [6] concludes with the recommendation of this technology as a cost-effective baseload electricity generation alternative to speed up transition to sustainable energy systems. Recent reviews of ISCC are provided in [27] and [29]. Variants of the basic design everything but fully optimized are proposed in [28]. 101
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Fig. 2. Modelled operation of a hypothetical CSP plant with TES of 59% capacity factor located in Daggett, CA compared to the Solana PT and Crescent Dunes ST CSP plants with TES.
Fig. 3. Modelled operation of a hypothetical CSP plant with TES of 59% capacity factor located in Daggett, CA compared to the Genesis PT and Ivanpah ST CSP plants without TES. Ivanpah has boost by natural gas combustion for about one third of the production of electricity.
number of loops is 40, for a SCAs per loop of 4. The heat transfer fluid type is thermal oil. Inlet temperature is 293 °C and outlet temperature is 393 °C. Cooling is wet. Completed in 2011, cost is unknown. Electricity production data is not available. The ISCC of Ain Beni Mathar, Morocco [15] has an overall capacity of 470 MW, 450 MW combined cycle and a 20 MW solar thermal PT. The solar field is by Abener/Abengoa Solar. The solar field is about same of The ISCC plant in Hassi R’Mel, Algeria. The solar field aperture area is 183,120 m2. The number of SCAs is 224, the number of loops is 56, for a SCAs per loop of 4. The SCA length is 150 m. The number of heat collector elements (HCEs) is 8064. The heat transfer fluid type is thermal oil. Inlet temperature is 293 °C and outlet temperature is 393 °C. Cooling is wet. Completed in 2010, cost was 554 m$. Electricity production data is not available. In addition to the above plants presently operational, other plants are under constructions. The ISCC of Agua Prieta II, Mexico [16,17] has an overall capacity of 476.4 MW. It includes a 464.4 MW combinedcycle power plant and a 12 MW solar thermal PT. Construction of the project began in March 2011. The solar field is by Abengoa Solar. The combined-cycle power plant is estimated to cost approximately 350 m$, while the solar field is estimated to cost 49.35 m$. The solar field aperture area is 85,000 m2, the number of SCAs is 104, the number of loops is 26 for a SCAs per loop of 4. The SCA length is 150 m. In this paper, the status of CSP technology is first reviewed in detail. Then, the specific solar irradiance data of Trinidad and Tobago is presented. The rationale behind the coupling of a combined cycle gas turbine (CCGT) plant with a small CSP PT solar field is proposed. A model is then built for an ISCC in Trinidad and Tobago. The integration of the small CSP PT solar field with an existing CCGT plant further improves the already excellent fuel conversion efficiency of this plant while introducing renewable energy in an otherwise conventional power generation system. No similar research on CSP has been conducted so far for countries with a good natural gas resource and solar radiation limited by clouds such as Trinidad and Tobago.
introduction, this first plant of the “new generation” of solar thermal plants still suffers from major design issues, in both the ST, and the enhanced TES component. With an actualized (2017) capacity specific construction cost of 9227 $/kW, the plant had capacity factors of 13.21% in 2016, and 4.36% in 2017, while the design value was 51.89%. The much simpler and more consolidated PT technology, without any TES, offers the opportunity to deliver capacity factors of about 30% at reduced costs, albeit producing electricity only during daylight, Refs. [1] and [2]. If we look at the 34-operational CSP stations of capacity above 50 MW in the world, 31 of them are PT, 1 is Fresnel reflector, and only 2 of them are ST. The two-CSP ST power stations are both in the United States, the 377 MW capacity Ivanpah, and the 110 MW capacity Crescent Dunes. Ivanpah has no TES but boost by natural gas combustion. Ivanpah has also performed below expectations, reaching capacity factors of about 20% only burning a large amount of natural gas, and it also had an accident, due to misalignment of the heliostats in one of the three towers, albeit less relevant than in Crescent Dunes. Figs. 2–4 present the monthly average capacity factors for the power stations of Ivanpah and Crescent Dunes, compared to two other recently built, CSP PT plants, the 250 MW Genesis, that has no TES, and the 250 MW Solana, with 6 h of TES. The monthly average capacity factors of the old Solar Energy Generating Systems (SEGS) IX CSP PT plant, operational since 1990, is also presented. This plant has no TES, but it operates with relatively small (when compared to Ivanpah) natural gas combustion to ramp up operation in the morning. It is delivering about same of Ivanpah capacity factors after almost 30 years of operation. The actualized (2017) capacity-specific construction cost is 8258 $/kW for Solana, 5213 $/kW for Genesis and 6084 $/kW for Ivanpah. Electricity
Concentrated solar power technology status As recently discussed in [1] and [2], based on the data of [18], the delivered performance of molten salt TES in CSP ST plants differs considerably from the expected. CSP ST with 10 h of TES is the current CSP technology according to the National Renewable Energy Laboratory (NREL) [3]. It should deliver a 59% capacity factor in an insulation class 5 location such as Daggett, CA, with a capacity specific construction cost of 8133 $/kW. These performances are not yet possible at these costs, as there is only one plant of this kind presently operational in the world, the 110 MW capacity Crescent Dunes. Completed at the end of 2015, it has been producing much less than the expected when has not been shut down for maintenance. As previously written in the
Fig. 4. Modelled operation of a hypothetical CSP plant with TES of 59% capacity factor located in Daggett, CA compared to the SEGS IX PT and Ivanpah ST CSP plants without TES. SEGS IX also features natural gas combustion same of Ivanpah, but in a smaller extent, only to ramp up production. 102
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production data are from the Energy Information Administration (EIA) [18]. The figures also show a hypothetical CSP PT with TES delivering the 59% capacity factor. A thermo-fluid model [19] has been used for this plant. The plant is supposed to be in Daggett, CA. The TES is oversized to permit 24 h power generation every day of the year. The solar field is similarly oversized. It produces a flow of the receiver fluid that is approximately twice the amount needed to run the power plant at 100% capacity 4.15 PM of the autumnal equinox with clear sky (haze index 0.1). The computed mid-summer, autumnal equinox, and mid-winter capacity factors, including minimum, average and maximum clouds coverage, are 82%, 64% and 28%. The resulting annual capacity factor is 59% as requested. This plant would obviously have a much larger capacity specific construction cost than the 9227 $/kW of Crescent Dunes, but the cost is not relevant to the present analysis. While the power plant of hypothetical 59% capacity factor and the power plants of Solana, Crescent Dunes and Genesis are 100% solar, Ivanpah power plant has a boost by natural gas combustion. The design capacity factor is 43.11% for Solana, 51.89% for Crescent Dunes, and 26.48% for Genesis and it is 32.68% for Ivanpah with negligible boost by natural gas combustion. The measured 2017 capacity factors are 21.81% for Ivanpah, 33.06% for Solana, 28.67% for Genesis and 4.36% for Crescent Dunes [2]. The 2016 measured capacity factors are 21.29% for Ivanpah, 29.39% for Solana, 28.50 for Genesis and 13.21% for Crescent Dunes [2]. The operation since even more than 3 decades of the units composing the 354 MW SEGS solar complex in northern San Bernardino County, California is another key advantage of the PT technology without any TES but boost by natural gas combustion. This complex comprises 9 units, SEGS I–II (44 MW) located at Daggett, CA, SEGS III–VII (150 MW) located at Kramer Junction, CA, and SEGS VIII–IX (160 MW) located at Harper Lake, CA. These units were completed between 1985 and 1990 and they have been producing electricity since then, with capacity factors well exceeding 20%, and small boost by natural gas combustion to ramp up operation [1]. As shown in the Fig. 3, from 2001 (first year of the EIA data [18]) to 2017, the 80 MW SEGS VIII and IX in Kramer Junction, CA, have been working with annual capacity factors maximum, minimum and average of 31%, 20% and 24%, and 33%, 20% and 25%, burning relatively small quantities of natural gas if compared to Ivanpah. From Figs. 2–4, and the SEGS experience, both enhanced TES, and ST, technologies appear to be still far from an industrial deployment and still in need of substantial research and development. Conversely, the PT installation, without any TES, reliably produces the expected electricity at about 30% capacity factor when the sun shines. It may therefore serve the basis for a possible industrial product. In theory, with mass production, like the solar photovoltaics in China, it is expected that the CSP PT standalone technology, with no TES, may be competitive with other renewable energy options, starting with solar photovoltaics [2]. The reason why PTs are significantly more reliable than STs are intuitive. CSP concentrates a large area of sunlight onto a small area. A ST is an array of many dual-axis tracking reflectors (heliostats) that concentrate much more sunlight on a small, central receiver atop a tall tower. The concentrated sunlight heats molten-salt. The heat absorbed by the salt is stored to heat water to produce the superheated steam of the Rankine power cycle. The many thousands of mirrors motorized to track the sun’s path over the course of the day must provide a nearly perfect focusing of the sunlight over a prolonged operation. This is simply too expensive to be done properly in today’s low-cost environment. A PT is based on a much simpler single-axis tracking linear parabolic reflector concentrating light onto the coaxial receiver. The sunlight must be concentrated much less. Solar collectors concentrate sunlight to heat a synthetic oil, which then heats water to produce the superheated steam of the Rankine
power cycle. To design a plant, within acceptable cost constraints, then working properly over a long timeframe while ensuring a nearly perfect tracking system, it is much easier with the PT than the ST design. This is the main reason why ST plants built thus far have been outperformed by PT plants, even if the expectations were the opposite. About molten-salt TES, the increased complications of this design, where crystallization of the salt has often been a major issue, is similarly the reason why many plants with TES have failed to deliver even same performances of plants without TES despite the dramatically increased costs. Industrial products must be simple to be efficient and reliable within cost constraints. Finally, for the specific application of CSP discussed later, a small CSP solar field used to supplement the combustion fuel heat flow during daylight in Trinidad and Tobago, PT has not only the advantages of maturity, reliability, specific land use, cost and efficiency vs. ST. In an area subjected to storms, few single axis wind resistant collectors are preferably to many more fragile double axis heliostats and a tall tower. Solar irradiance in Trinidad and Tobago Trinidad and Tobago’s southerly location keeps temperatures stable year-round, with a daily average of 27 °C. There are two seasons, the rainy season, June to November, and the dry season, December to May. Weather conditions for Trinidad and Tobago, including temperatures, clouds coverage, daylight and sun energy, are available from weatherspark.com. Piarco International Airport has coordinates 10.5977° N, 61.3395° W. The solar irradiance of Trinidad and Tobago is considered not exceptional by [5,4]. The Direct Normal Irradiance (DNI) at a location is the amount of solar energy falling per m2 per day at that location. The DNI for a sunny region is approximately 6 kWh/m2/day. Ref. [4] excludes the Caribbean from the regions where the incoming solar energy is more than more than 2000 kWh/m2/y (about 5.5 kWh/m2/day), a value they consider as a threshold for economically viable standalone solar only CSP plants. Ref. [5] dismisses the standalone CSP option, however promoting the solar water heating and the solar photovoltaic options. globalsolaratlas.info proposes for Trinidad and Tobago an annual average DNI of 4.43 kWh/m2/day. The major issue in the Caribbean is the clouds coverage. To avoid clouds interference to a strong solar resource, CSP development in the United States has been mostly in the Southwest. However, CSP plants have also been recently proposed for areas such as Florida and Hawaii having haze index not far from the Caribbean [20]. With reference to typical locations where CSP plants have been built, for example Seville, Spain, Trinidad and Tobago are characterized by a much more significant clouds coverage. CSP uses very high temperatures, temporary cloud cover produces larger variations in electricity production that solar photovoltaic systems face [21]. globalsolaratlas.info proposes for Seville a much larger an annual average DNI of 5.66 kWh/m2/day. The average percentage of the sky covered by clouds experiences mild seasonal variation over the course of the year. The clearer part of the year is June to September. The clearest day of the year, the sky is clear, mostly clear, or partly cloudy 39% of the time, and overcast or mostly cloudy 61% of the time. The cloudier part of the year is September to June. The cloudiest day of the year, the sky is overcast or mostly cloudy 73% of the time, and clear, mostly clear, or partly cloudy 27% of the time. Fig. 5 presents a comparison of the clouds coverage in Trinidad and Tobago and Seville, Spain. The figure presents the percentage of time spent in each cloud cover band, categorized by the percentage of the sky covered by clouds, clear < 20% < mostly clear < 40% < partly cloudy < 60% < mostly cloudy < 80% < overcast. The length of the day does not vary substantially over the course of the year, staying within 44 min of 12 h throughout the year. The shortest day has 11 h, 30 min of daylight. The longest day has 12 h, 103
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Fig. 5. Percentage of time spent in each cloud cover band, categorized by the percentage of the sky covered by clouds. On the left, percentage of clear sky, on the right, percentage of cloudy sky. a, Piarco International Airport, Trinidad & Tobago, b, Seville San Pablo Airport Spain. Images reproduced modified after weatherspark.com.
45 min of daylight. The earliest sunrise is at 5:42 AM, and the latest sunrise is at 6:28 AM. The earliest sunset is at 5:39 PM, and the latest sunset is at 6:31 PM. Opposite to Spain, daylight saving time (DST) is not observed in Trinidad & Tobago. Considering the seasonal variations in the length of the day, the elevation of the Sun above the horizon, and the absorption by clouds and other atmospheric constituents, Fig. 6 presents the total daily incident shortwave solar energy reaching the surface of the ground. The shortwave radiation includes visible light and ultraviolet radiation. The average daily incident shortwave solar energy experiences some seasonal variation over the course of the year, with a brighter period of the year lasts for 2.6 months, from February 19 to May 7, with an average daily incident shortwave energy per square meter above 6.5 kWh. The brightest day of the year is March 29, with an average of 7.0 kWh. The darker period of the year lasts for 2.7 months, from September 13 to December 4, with an average daily incident shortwave energy per square meter below 5.1 kWh. The darkest day of the year is October 14, with an average of 4.6 kWh. In Seville, Spain, the average daily shortwave solar energy reaching the ground is 2.30 and 8.30 kwh/m2 respectively in winter and summer. Daylights are 9.35 and 14.45 h per day. In Trinidad and Tobago, the average daily shortwave solar energy reaching the ground is 4.60 and 7.00 kWh/m2 respectively in the dark and bright periods.
Daylights are 11.80 and 12.10 h per day. With reference to Seville, the average daily shortwave solar energy reaching the ground inclusive of clouds coverage is better in Trinidad and Tobago. Unfortunately, this result is misleading, as not all the shortwave solar energy reaching the ground may then be converted in heat in a CSP field. Fig. 6 presents the total daily incident shortwave solar energy per square meter, reaching the surface of the ground over a wide area, taking full account of the length of the day, the elevation of the Sun above the horizon, and the absorption by clouds and other atmospheric constituents. However, this is not the amount of solar energy that can be used by a CSP plant, where only the direct normal irradiance (DNI) play a role. Table 1 summarizes the DNI irradiance data for Trinidad and Tobago and Seville. We do only have the annual average DNI for the two locations, plus the information of Figs. 5 and 6, to derive the daily DNI of maximum, minimum and shoulders days. We take the daily DNI proportional to the daily total irradiance and daily cloud coverage, then requesting the average of the four days being equal to the annual DNI. Solar irradiance data for Trinidad and Tobago is provided in [22] for the wet and dry seasons. Over the period 2001–2010, the average daily global solar radiation, average total global solar radiation, average daily number of sunshine hours, and average total number of sunshine hours were 4.70 ± 0.20 kWh/m2/day, 0.71 ± 0.03 GJ/m2, 104
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Fig. 6. Average daily shortwave solar energy reaching the ground per square meter (orange line), with 25th to 75th and 10th to 90th percentile bands. a, Piarco International Airport, Trinidad & Tobago, b, for comparison, Seville San Pablo Airport Spain. Images reproduced modified after weatherspark.com.
8.49 ± 44 h/day and 12826 ± 67 h, for the dry season, and 4.31 ± 0.225 kWh/m2/day, 0.92 ± 0.05 GJ/m2, 7.03 ± 038 h/day, and 15046 ± 81 h for the wet season. The average of the two daily global solar radiations wet and dry season is not far from the DNI 4.43 kWh/m2/day of globalsolaratlas.info.
natural gas combustion. The boost by natural gas combustion to ramp up production in the morning, or compensate for the clouds, with a simple natural gas boiler, is thermally not the best opportunity of using the fuel energy. The thermal efficiency of a standalone CSP plant is only about 30%-40%, well below the efficiency of a combined cycle gas turbine plant that is about 55%-60%. There is therefore the opportunity to better integrate the CSP PT solar field with the natural gas combustion within combined cycle installations. If we consider the 377 MW Ivanpah power plant [24], the heliostat solar field aperture area is 2,600,000 m2. There are 173,500 heliostats of aperture area 15 m2 each. The land area is 3500 acres, or 14.16 km2. If we consider the 110 MW Crescent Dunes power plant [25], the heliostat solar field aperture area is 1,197,148 m2. There are 10,347 heliostats of aperture area 115.7 m2 each. The land area is 1600 acres, or 6.47 km2. Opposite to the solar field of the ISCC of Kuraymat, Egypt, Ain Beni Mathar, Morocco, Hassi R’Mel, Algeria or Agua Prieta II, Mexico, the land requirements are much more demanding for a country such as Trinidad and Tobago of total land area 5130 km2 with a population density of 268 peoples per km2. In the Integrated Solar Combined Cycle (ISCC) showcased in [19], the CSP PT solar field is integrated with an otherwise traditional gas turbine/steam turbine power plant. The sun energy is introduced as high pressure saturated steam, mixed with Heat Recovery Steam Generator (HRSG) High Pressure (HP) steam, and superheated for
Integrated solar combined cycle in Trinidad and Tobago From Figs. 2–4, we therefore see clear potentials for the development of an industrial product based on the CSP PT technology without any TES, that in the specific of Trinidad and Tobago, must be more deeply integrated with the natural gas combustion than simply having a back-up gas boiler. An addition to a combined cycle plant, rather than a standalone facility, may provide the best cost-to-benefit ratio. The integration of CSP with natural gas combustion also addresses the issue of cloud coverage, Fig. 5, with a back-up natural gas burner replacing the solar heat when unavailable in part or completely. Despite Trinidad and Tobago have escaped major devastating hurricanes, storms must be considered in the design of the structure. Also, under this aspect, the PT technology is superior to the ST technology. Trinidad and Tobago have a natural gas contribution to the energy generation mix of 99% (2010 data, [23]), and energy consumption by sector 64.9% commercial (2011 data, [23]). In the specific of Trinidad and Tobago, where the electricity system is very well developed, and natural gas is abundant, the PT technology must be integrated with 105
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Table 1 Irradiance data for Trinidad and Tobago and Seville. The daily DNI is estimated from the annual DNI and the daily total irradiation and percentage of partly cloudy.
source: globalsolaratlas.info Lat. Long. GHI DNI DIF GTI DNI day of max solar irradiance
day of min solar irradiance
shoulder days
source: weatherspark.com daily total irradiation daylight reference power partly cloudy computed values DNI reference DNI power source: weatherspark.com total energy daylight reference power partly cloudy computed values DNI reference DNI power source: weatherspark.com total energy daylight reference power partly cloudy computed values DNI reference DNI power
Trinidad and Tobago
Seville
deg. def. kWh/m2/year kWh/m2/year kWh/m2/year kWh/m2/year kWh/m2/day
10.4686 −61.2532 1978 1616 859 2011 4.43
37.4232 −5.9000 1833 2065 595 2107 5.66
kWh/m2/day h kWh/m2 %
7.00 12.1 0.58 30
8.30 14.45 0.57 93
kWh/m2/day kWh/m2
5.32 0.44
8.30 0.57
kWh/m2/day h kWh/m2 %
4.60 11.8 0.390 27
2.30 9.35 0.246 55
kWh/m2/day kWh/m2
3.40 0.289
2.03 0.217
kWh/m2/day h kWh/m2 %
5.3 12 0.442 34
5 12 0.417 63
kWh/m2/day kWh/m2
4.16 0.346
4.57 0.381
when the solar generator is unavailable. The plant is sized for about ¼ of HP steam generation in the solar generator, and ¾ in the HRSG. The solar field, sized for the irradiance conditions of Seville, Spain, has a total surface of 0.3 km2. The solar generator contributes up to 35% of HP steam at peak summer conditions, and much less at winter conditions. The combined cycle alone requires a land area of about 0.035 km2, for a combined land area of about 0.335 km2. Summer peak capacity is 415 MW. Operation at peak summer condition with the solar field contributes approximately 27.5 MW of power, or 6.5% of the total plant power. In terms of fuel conversion efficiency, the solar field adds about 3.9% to the plant efficiency, to move from a 55% to a 59% fuel conversion efficiency. The success in improving the conventional power plant’s fuel conversion efficiency depends on how specifically the solar field supplements heat to the other plant, and obviously at which costs. The above efficiency improvements are associated with a minimal impact of the solar field addition on the combined cycle operation. Larger solar contributions may impact more on power and efficiency, but at the price of added complexity of plant design and operation in non-solar mode. Results of preliminary computations for the operation of the ISCC plant of Fig. 7 relocated in Trinidad and Tobago are presented below. The model is a validated Thermoflow (www.thermoflow.com) model of an ISCC that is only adapted to the specific solar conditions and temperatures of Trinidad and Tobago. All the detailed ISCC model parameters are given by Thermoflow (www.thermoflow.com). The solar conditions for Trinidad and Tobago are those only guessed in Table 1. The results are thus easily reproducible by anyone having the specific model and the specific software. Better accuracy may only follow a proper measurement campaign for the DNI in Trinidad and Tobago.
admission to the turbine. With steam condensed in a dry air-cooled condenser, and desert like conditions of temperature and humidity, with 49.3 MW heat input from the solar field, and 276.3 MW heat input from the natural gas combustion, the plant can produce 157.6 MW of electric output for a 57.0% fuel conversion efficiency. Hence, accepting the use of CSP to boost efficiency of natural gas plants, rather than replacing these plants, there is the opportunity to increase the efficiency of a gas turbine/steam turbine plant from 48.4 to 57.0%, thus reducing the consumption of fossil fuels for the same electricity produced. In Trinidad and Tobago, by simply using a water-cooled condenser, the efficiency would be further improved. Results of simulations In the Thermoflow model of Fig. 7, a 1x1 9FA gas turbine/steam turbine combined cycle power plant (www.ge.com) is coupled to a PT solar thermal steam generator capable of producing partially superheated HP steam. GE’s 9FA combined cycle technology is adopted in many power plants operating worldwide. The exhaust gas from the gas turbine generator is converted to the steam driving the steam turbinegenerator. Combined cycle technologies enable the plant to produce additional power without increasing the fuel consumption. Integration with a solar field may further improve the fuel economy during transients as well as during steady state operation. The solar field heats Therminol oil to about 400 °C. The oil is pumped through a series of shell and tube heat exchangers to preheat feedwater and generate and superheat steam. Final superheating of the steam in the HRSG is required. The solar generator receives feedwater partially preheated from the HRSG and returns superheated steam to the HRSG. This steam is mixed with the HP steam exiting the first super-heater (HPS0). The mixture is superheated to final steam turbine throttle conditions of 550 °C. A duct burner is installed in the HRSG to raise additional steam 106
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Fig. 7. Thermoflow (www.thermoflow.com) model of an Integrated Solar Combined Cycle (ISCC) plant of peak summer capacity 415 MW having a solar field contribution of 27.5 MW.
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Fig. 8. Irradiance in day 88 (brighter day), day 181 (shoulder day) and day 287 (darker day) in Trinidad and Tobago.
The wet cooling tower may be conveniently replaced with a pump feed from a water reservoir and a water sink. The results for the baseline Combined Cycle (CC) plant without any solar field input are also presented. The major source of inaccuracy in the computation is the simulation of the clouds effects across the year. The solar irradiance is estimated from site data as described in [4]. The solar irradiance is computed based on the site latitude (10.69 N), the day of the year, the hour of the day (solar time), and a clouds parameter, the haze index or the clear sky correction factor. The atmospheric transmissivity depends on the distance the radiation travels through the atmosphere and the condition of the atmosphere. The beam pathlength in the atmosphere is computed using the solar zenith angle and the site altitude. The zenith angle is then computed based on the site-specific data and a geometric representation of relative sun-earth
positioning throughout the year. The clouds effect is either represented by interpolation between two conditions, clear-day (haze index = 0, 23 km visibility) and hazy-day (haze index = 1, 5 km visibility) or, alternatively, a clear sky correction factor, based on the average solar radiation for the selected month. Unfortunately, there are not enough data to properly tune these two models. As a first guess, Fig. 8 presents the prescribed irradiance during the brighter (day 88), darker (day 287) and shoulder day (day 181), computed by using the clear sky correction factor model with input the daily direct irradiation per square meter of Table 1. Fig. 9 presents the ISCC and CC results for the brighter day. Morning and afternoon, the solar field heat supply permits fuel savings translating in an efficiency increase from 54.76 to 58.45%, while mid-day, the efficiency increase is from 54.81 to 57.73%. 108
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Fig. 9. Efficiency of ISCC (left) and baseline CC (right) plant operation during the brighter day.
Fig. 10. Efficiency of ISCC (left) and baseline CC (right) plant operation during the shoulder days.
Fig. 10 presents the results for one of the two shoulders days. Morning and afternoon, the solar field heat supply permits fuel savings translating in an efficiency increase from 54.76 to 57.57%, while midday, the efficiency increase is from 54.81 to 58.26%. Fig. 11 finally presents results of computations for the operation during the darker day. Morning and afternoon, the solar field heat supply permits fuel savings translating in an efficiency increase from 54.76 to 56.48%, while mid-day, the efficiency increase is from 54.81 to 56.91%. Over the year, the plant operates at an efficiency of 54.93% overnight, for about 12 h a day, with obviously no improvements vs. the conventional power plant without the solar field. Over the morning and afternoon periods, of length about 8 h a day, the plant operates at an efficiency of 57.34%, about 2.58% better than the efficiency of the conventional power plant without the solar field at 54.76%. Over the mid-day periods, of length about 4 h a day, the plant operates at an efficiency of 57.97%, about 3.16% better than the efficiency of the conventional power plant without the solar field at 54.81%.
Conclusions Trinidad and Tobago have interest in supporting renewable energy and energy efficiency, developing new economic sectors and reducing the government’s fuel subsidy liabilities. The deployment of CSP PT, without any TES, but integrated with natural gas combustion, in an ISCC plant is key initiative to contribute with renewable energy to the electricity production of Trinidad and Tobago, while improving local employment, manufacturing potentials and export of industrial products. The novelty of this work is the application of a validated model of a ISCC featuring a commercial CCGT plant coupled to a small CSP PT solar field with solar irradiance input (and temperature) specific to the location of Trinidad and Tobago. Opposite to what has been concluded in reference works such as [4] and [5], the relatively high clouds coverage does not prevent the ISCC from delivering a few percentage points better fuel conversion efficiency than the standalone CCGT plant at affordable costs. Better estimations may only follow the construction of a small demonstration plant. The work has reference values for applications of CSP to areas with high cloud coverage. 109
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Fig. 11. Efficiency of ISCC (left) and baseline CC (right) plant operation during the darker day.
Appendix A. Supplementary data
[14] National Renewable Energy Laboratory (NREL). ISCC Kuraymat. Available online: www.nrel.gov/csp/solarpaces/project_detail.cfm/projectID=65. [15] National Renewable Energy Laboratory (NREL). ISCC Ain Beni Mathar. Available online: www.nrel.gov/csp/solarpaces/project_detail.cfm/projectID=43. [16] Abengoasolar, Concentrated Solar Power Plant Agua Prieta II – 14 MW. Available online: www.abengoa.com.mx/web/en/areas-de-actividad/ingenieria-yconstruccion-industrial/energia-renovable/obra/Concentrated-Solar-Power-PlantAgua-Prieta-II-14-MW/. [17] National Renewable Energy Laboratory (NREL). Agua Prieta II. Available online: www.nrel.gov/csp/solarpaces/project_detail.cfm/projectID=135. [18] Energy Information Administration (EIA). Electricity data browser – Plant Level Data. Available online: www.eia.gov/electricity/data/browser/. [19] Thermoflow, Solar Thermal Pamphlet 2012. Available online: www.thermoflow. com/images/Solar%20Thermal%20Pamphlet%202012.pdf. [20] National Renewable Energy Laboratory (NREL). 2014. Concentrating solar power projects in the United States. Available online: www.nrel.gov/ concentrated solar power/solarpaces/by_country_detail.cfm/country=US. [21] Jorgensen J, Denholm P, Mehos M. Estimating the value of utility-scale solar technologies in california under a 40% renewable portfolio standard. Golden, CO: National Renewable Energy Laboratory; 2014www.nrel.gov/docs/fy14osti/61685. pdf. [22] De Souza K, Andrews R. Models for daily global solar radiation for the Caribbean island of Trinidad. J Renewable Sustain Energy 2015;7(1):013132. [23] Energy Transition Initiative, Energy Snapshot Trinidad and Tobago. Available online: www.nrel.gov/docs/fy15osti/64117.pdf. [24] National Renewable Energy Laboratory (NREL). Ivanpah Solar Electric Generating System. Available online: www.nrel.gov/csp/solarpaces/project_detail.cfm/ projectID=62. [25] National Renewable Energy Laboratory (NREL). Crescent Dunes Solar Energy Project. Available online: www.nrel.gov/csp/solarpaces/project_detail.cfm/ projectID=60. [26] Trieb, F., Schillings, C., O’sullivan, M., Pregger, T. and Hoyer-Klick, C., (2009). September. Global potential of concentrating solar power. In SolarPACES Conference (pp. 15-18). Available online: www.dlr.de/tt/en/desktopdefault.aspx/ tabid-2885/4422_read-16596/. [27] Behar O, Khellaf A, Mohammedi K, Ait-Kaci S. A review of integrated solar combined cycle system (ISCCS) with a parabolic trough technology. Renew Sustain Energy Rev 2014;39:223–50. [28] Li Y, Yang Y. Thermodynamic analysis of a novel integrated solar combined cycle. Appl Energy 2014;122:133–42. [29] Rovira A, Barbero R, Montes MJ, Abbas R, Varela F. Analysis and comparison of integrated solar combined cycles using parabolic troughs and linear fresnel reflectors as concentrating systems. Appl Energy 2016;162:990–1000.
Supplementary data to this article can be found online at https:// doi.org/10.1016/j.seta.2019.02.006. References [1] Boretti A, Castelletto S, Al-Zubaidy S. Concentrating solar power tower technology: present status and outlook. Nonlin Eng 2018. https://doi.org/10.1515/nleng-20170171. [2] Boretti A. Cost and production analysis of the latest solar thermal and solar photovoltaics electricity plants in the united states. Renew Energy Focus 2018. in press. [3] National Renewable Energy Laboratory (NREL). 2017 Annual Technology Baseline. Golden, CO: National Renewable Energy Laboratory. Available online: www.nrel. gov/analysis/data_tech_baseline.html. [4] Hottel HC. A simple model for estimating the transmittance of direct solar radiation through clear atmospheres. Sol Energy 1996;18:129–34. [5] Loy D, Klein J, Casado Cañeque F, Marzolf, NC, 2015. A unique approach for sustainable energy in trinidad and tobago. IDB Monograph (Infrastructure and environment sector. Energy Division); IDB-MG-382. [6] Alqahtani BJ, Patiño-Echeverri D. Integrated solar combined cycle power plants: paving the way for thermal solar. Appl Energy 2016;169:927–36. [7] Manente G. High performance integrated solar combined cycles with minimum modifications to the combined cycle power plant design. Energy Convers Manage 2016;111:186–97. [8] Dersch J, Geyer M, Herrmann U, Jones SA, Kelly B, Kistner R, et al. Trough integration into power plants-a study on the performance and economy of integrated solar combined cycle systems. Energy 2004;29(5–6):947–59. [9] Montes MJ, Rovira A, Muñoz M, Martínez-Val JM. Performance analysis of an integrated solar combined cycle using direct steam generation in parabolic trough collectors. Appl Energy 2011;88(9):3228–38. [10] Baghernejad A, Yaghoubi M. Exergoeconomic analysis and optimization of an integrated solar combined cycle system (ISCCS) using genetic algorithm. Energy Convers Manage 2011;52(5):2193–203. [11] Kelly B, Hermann U, Hale M. Optimization studies for integrated solar combined cycle systems. Solar Eng 2001:393–8. [12] Abengoasolar, Integrated solar combined-cycle (ISCC) plant in Algeria. Available online: www.abengoasolar.com/web/en/plantas_solares/plantas_para_terceros/ argelia/index.html. [13] National Renewable Energy Laboratory (NREL). ISCC Hassi R'mel. Available online: www.nrel.gov/csp/solarpaces/project_detail.cfm/projectID=44.
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A case study on combined cycle power plant integrated with solar energy in Trinidad and Tobago
T
Albert Borettia, , Sarim Al-Zubaidyb ⁎
a b
Independent Scientist, Bundoora, VIC, Australia The University of Trinidad and Tobago, Trinidad and Tobago
ARTICLE INFO
ABSTRACT
Keywords: Renewable energy Natural gas Concentrated solar power Parabolic trough Solar tower Clouds coverage Trinidad and Tobago
Aim of the paper is to evaluate the benefit of a renewable energy initiative for Trinidad and Tobago. Trinidad and Tobago have abundant natural gas, a highly developed power generation system almost entirely based on combustion fuels, high solar irradiation, but skies often covered by clouds, a detrimental factor for concentrated solar power technologies. The simple, consolidated, parabolic trough technology, without the addition of thermal energy storage, has the potential to deliver better than solar photovoltaic capacity factors at a comparable cost when mass produced. Integration with natural gas combustion may permit to address the issues of clouds coverage. A computational analysis is proposed for an Integrated Solar Combined Cycle power plant comprising a reference combined cycle gas turbine plant, and a small solar field, located in Trinidad and Tobago. The simulations demonstrate the advantages, in terms of fuel conversion efficiency, of the small solar field addition. On average over the year, the plant operates over the morning and afternoon periods, of length about 8 h a day, at an efficiency of 57.34%, about 2.58% better, and over the mid-day periods, of length about 4 h a day, at an efficiency of 57.97%, about 3.16% better.
Introduction Refs. [1] and [2] have recently reviewed concentrated solar power (CSP) and solar photovoltaic (PV) plants. The solar tower (ST) with enhanced thermal energy storage (TES) is the suggested “current” technology for CSP plants [3]. However, the single plant utility-size of this kind completed so far in the world, the 110 MW capacity Crescent Dunes, despite the very high capacity-specific cost, has been producing electricity well below the expectations. The construction cost of Crescent Dunes, completed in 2015, was 1b$ [1,2], for an actualized (2017) capacity-specific cost of 9227 $/kW. Operational since the end of 2015, the annual capacity factors of this plant have been 13.21% in 2016, and only 4.36% in 2017, well below the design value of 51.89%. The plant has been out of service due to the TES failure for 7 months in between 2016 and 2017, and in no single month so far, it has matched the planned electricity output. Much better performances of ST at reduced costs have been delivered so far by parabolic trough (PT) plants, that have the potential, after mass production, to compete with PV plants [2] in terms of costs. Opposite to PV, however, CSP dramatically suffers of clouds coverage [4,5,26]. Trinidad and Tobago are the third richest country in the Americas after the United States and Canada by GDP (PPP) per capita. The ⁎
country has large reserves of oil and natural gas, with a predominantly industrial economy based primarily on petroleum and petrochemicals. The main exports are petroleum, liquefied natural gas, methanol, ammonia and urea. Electricity is produced by processing natural gas in high efficiency plants such as the combined cycle Trinidad Generation Unlimited power plant. The already excellent production of electricity may be strengthened by integrating solar energy with the gas generation system in a renewable energy project progressing the renewable energy uptake within the country. If the standalone CSP ST technology with enhanced TES is an extremely expensive and risky opportunity to explore in Trinidad and Tobago, much better perspectives are offered by the simpler, more consolidated, CSP PT technology, without any TES, integrated with natural gas combustion [2]. This technology has the potential to deliver better than PV capacity factors at a reduced cost when mass produced [2]. As Trinidad and Tobago has, in addition to abundant natural gas and a highly developed power generation system, high solar irradiation, but skies often covered by clouds, Fig. 1, that is a detrimental factor to CSP, the integration of the PT CSP technology with natural gas combustion appears one of the avenues to progress renewable energy in the country. Integrated Solar Combined Cycle (ISCC) power plants, Refs. [6–11,27–29] commented hereafter, are a technology with the
Corresponding author. E-mail address: [email protected] (A. Boretti).
https://doi.org/10.1016/j.seta.2019.02.006 Received 19 July 2018; Received in revised form 16 December 2018; Accepted 28 February 2019 2213-1388/ © 2019 Elsevier Ltd. All rights reserved.
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Fig. 1. Direct normal irradiance in Trinidad and Tobago. Image reproduced modified after globalsolaratlas.info. In Couva, Couva-Tabaquite-Talparo, Trinidad and Tobago, the DNI (Direct Normal Irradiation), solar radiation component that directly reaches the surface, is 1616 kWh/m2 per year. This is the component relevant for concentrating solar thermal power plants (CSP).
There are few examples of ISCC around the world. The ISCC plant in Hassi R’Mel, Algeria [12,13] has 20 MW from a PT field out of the total output of 150 MW. The solar field is by Abengoa Solar. The solar field aperture area is 183,860 m2. The number of solar collector assemblies (SCAs) is 224, the number of loops is 56, for a SCAs per loop of 4. The SCA length is 150 m. The number of heat collector elements (HCEs) is 8064. The heat transfer fluid type is thermal oil. Inlet temperature is 293 °C and outlet temperature is 393 °C. Cooling is dry. Completed in 2011, cost was 350 m€. Electricity production data is not available. The ISCC plant in Kuraymat, Egypt [14] has an overall capacity of 140 MW, 120 MW combined cycle and 20 MW solar thermal PT. The solar field aperture area is 130,800 m2. The number of SCAs is 140, the
potential to reduce fossil fuel use integrating solar power. In the ISCC, solar energy is used as an auxiliary heat supply, that may be replaced partially, or completely, by burning combustion fuels, supporting the steam cycle of a combined cycle gas turbine/steam turbine. The solar field results in a reduction of the fossil fuel use when the sun shines. Ref. [6] shows reduced costs of solar-generated electricity versus standalone concentrated solar power systems with or without TES while providing dispatchability. Ref. [6] concludes with the recommendation of this technology as a cost-effective baseload electricity generation alternative to speed up transition to sustainable energy systems. Recent reviews of ISCC are provided in [27] and [29]. Variants of the basic design everything but fully optimized are proposed in [28]. 101
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Fig. 2. Modelled operation of a hypothetical CSP plant with TES of 59% capacity factor located in Daggett, CA compared to the Solana PT and Crescent Dunes ST CSP plants with TES.
Fig. 3. Modelled operation of a hypothetical CSP plant with TES of 59% capacity factor located in Daggett, CA compared to the Genesis PT and Ivanpah ST CSP plants without TES. Ivanpah has boost by natural gas combustion for about one third of the production of electricity.
number of loops is 40, for a SCAs per loop of 4. The heat transfer fluid type is thermal oil. Inlet temperature is 293 °C and outlet temperature is 393 °C. Cooling is wet. Completed in 2011, cost is unknown. Electricity production data is not available. The ISCC of Ain Beni Mathar, Morocco [15] has an overall capacity of 470 MW, 450 MW combined cycle and a 20 MW solar thermal PT. The solar field is by Abener/Abengoa Solar. The solar field is about same of The ISCC plant in Hassi R’Mel, Algeria. The solar field aperture area is 183,120 m2. The number of SCAs is 224, the number of loops is 56, for a SCAs per loop of 4. The SCA length is 150 m. The number of heat collector elements (HCEs) is 8064. The heat transfer fluid type is thermal oil. Inlet temperature is 293 °C and outlet temperature is 393 °C. Cooling is wet. Completed in 2010, cost was 554 m$. Electricity production data is not available. In addition to the above plants presently operational, other plants are under constructions. The ISCC of Agua Prieta II, Mexico [16,17] has an overall capacity of 476.4 MW. It includes a 464.4 MW combinedcycle power plant and a 12 MW solar thermal PT. Construction of the project began in March 2011. The solar field is by Abengoa Solar. The combined-cycle power plant is estimated to cost approximately 350 m$, while the solar field is estimated to cost 49.35 m$. The solar field aperture area is 85,000 m2, the number of SCAs is 104, the number of loops is 26 for a SCAs per loop of 4. The SCA length is 150 m. In this paper, the status of CSP technology is first reviewed in detail. Then, the specific solar irradiance data of Trinidad and Tobago is presented. The rationale behind the coupling of a combined cycle gas turbine (CCGT) plant with a small CSP PT solar field is proposed. A model is then built for an ISCC in Trinidad and Tobago. The integration of the small CSP PT solar field with an existing CCGT plant further improves the already excellent fuel conversion efficiency of this plant while introducing renewable energy in an otherwise conventional power generation system. No similar research on CSP has been conducted so far for countries with a good natural gas resource and solar radiation limited by clouds such as Trinidad and Tobago.
introduction, this first plant of the “new generation” of solar thermal plants still suffers from major design issues, in both the ST, and the enhanced TES component. With an actualized (2017) capacity specific construction cost of 9227 $/kW, the plant had capacity factors of 13.21% in 2016, and 4.36% in 2017, while the design value was 51.89%. The much simpler and more consolidated PT technology, without any TES, offers the opportunity to deliver capacity factors of about 30% at reduced costs, albeit producing electricity only during daylight, Refs. [1] and [2]. If we look at the 34-operational CSP stations of capacity above 50 MW in the world, 31 of them are PT, 1 is Fresnel reflector, and only 2 of them are ST. The two-CSP ST power stations are both in the United States, the 377 MW capacity Ivanpah, and the 110 MW capacity Crescent Dunes. Ivanpah has no TES but boost by natural gas combustion. Ivanpah has also performed below expectations, reaching capacity factors of about 20% only burning a large amount of natural gas, and it also had an accident, due to misalignment of the heliostats in one of the three towers, albeit less relevant than in Crescent Dunes. Figs. 2–4 present the monthly average capacity factors for the power stations of Ivanpah and Crescent Dunes, compared to two other recently built, CSP PT plants, the 250 MW Genesis, that has no TES, and the 250 MW Solana, with 6 h of TES. The monthly average capacity factors of the old Solar Energy Generating Systems (SEGS) IX CSP PT plant, operational since 1990, is also presented. This plant has no TES, but it operates with relatively small (when compared to Ivanpah) natural gas combustion to ramp up operation in the morning. It is delivering about same of Ivanpah capacity factors after almost 30 years of operation. The actualized (2017) capacity-specific construction cost is 8258 $/kW for Solana, 5213 $/kW for Genesis and 6084 $/kW for Ivanpah. Electricity
Concentrated solar power technology status As recently discussed in [1] and [2], based on the data of [18], the delivered performance of molten salt TES in CSP ST plants differs considerably from the expected. CSP ST with 10 h of TES is the current CSP technology according to the National Renewable Energy Laboratory (NREL) [3]. It should deliver a 59% capacity factor in an insulation class 5 location such as Daggett, CA, with a capacity specific construction cost of 8133 $/kW. These performances are not yet possible at these costs, as there is only one plant of this kind presently operational in the world, the 110 MW capacity Crescent Dunes. Completed at the end of 2015, it has been producing much less than the expected when has not been shut down for maintenance. As previously written in the
Fig. 4. Modelled operation of a hypothetical CSP plant with TES of 59% capacity factor located in Daggett, CA compared to the SEGS IX PT and Ivanpah ST CSP plants without TES. SEGS IX also features natural gas combustion same of Ivanpah, but in a smaller extent, only to ramp up production. 102
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production data are from the Energy Information Administration (EIA) [18]. The figures also show a hypothetical CSP PT with TES delivering the 59% capacity factor. A thermo-fluid model [19] has been used for this plant. The plant is supposed to be in Daggett, CA. The TES is oversized to permit 24 h power generation every day of the year. The solar field is similarly oversized. It produces a flow of the receiver fluid that is approximately twice the amount needed to run the power plant at 100% capacity 4.15 PM of the autumnal equinox with clear sky (haze index 0.1). The computed mid-summer, autumnal equinox, and mid-winter capacity factors, including minimum, average and maximum clouds coverage, are 82%, 64% and 28%. The resulting annual capacity factor is 59% as requested. This plant would obviously have a much larger capacity specific construction cost than the 9227 $/kW of Crescent Dunes, but the cost is not relevant to the present analysis. While the power plant of hypothetical 59% capacity factor and the power plants of Solana, Crescent Dunes and Genesis are 100% solar, Ivanpah power plant has a boost by natural gas combustion. The design capacity factor is 43.11% for Solana, 51.89% for Crescent Dunes, and 26.48% for Genesis and it is 32.68% for Ivanpah with negligible boost by natural gas combustion. The measured 2017 capacity factors are 21.81% for Ivanpah, 33.06% for Solana, 28.67% for Genesis and 4.36% for Crescent Dunes [2]. The 2016 measured capacity factors are 21.29% for Ivanpah, 29.39% for Solana, 28.50 for Genesis and 13.21% for Crescent Dunes [2]. The operation since even more than 3 decades of the units composing the 354 MW SEGS solar complex in northern San Bernardino County, California is another key advantage of the PT technology without any TES but boost by natural gas combustion. This complex comprises 9 units, SEGS I–II (44 MW) located at Daggett, CA, SEGS III–VII (150 MW) located at Kramer Junction, CA, and SEGS VIII–IX (160 MW) located at Harper Lake, CA. These units were completed between 1985 and 1990 and they have been producing electricity since then, with capacity factors well exceeding 20%, and small boost by natural gas combustion to ramp up operation [1]. As shown in the Fig. 3, from 2001 (first year of the EIA data [18]) to 2017, the 80 MW SEGS VIII and IX in Kramer Junction, CA, have been working with annual capacity factors maximum, minimum and average of 31%, 20% and 24%, and 33%, 20% and 25%, burning relatively small quantities of natural gas if compared to Ivanpah. From Figs. 2–4, and the SEGS experience, both enhanced TES, and ST, technologies appear to be still far from an industrial deployment and still in need of substantial research and development. Conversely, the PT installation, without any TES, reliably produces the expected electricity at about 30% capacity factor when the sun shines. It may therefore serve the basis for a possible industrial product. In theory, with mass production, like the solar photovoltaics in China, it is expected that the CSP PT standalone technology, with no TES, may be competitive with other renewable energy options, starting with solar photovoltaics [2]. The reason why PTs are significantly more reliable than STs are intuitive. CSP concentrates a large area of sunlight onto a small area. A ST is an array of many dual-axis tracking reflectors (heliostats) that concentrate much more sunlight on a small, central receiver atop a tall tower. The concentrated sunlight heats molten-salt. The heat absorbed by the salt is stored to heat water to produce the superheated steam of the Rankine power cycle. The many thousands of mirrors motorized to track the sun’s path over the course of the day must provide a nearly perfect focusing of the sunlight over a prolonged operation. This is simply too expensive to be done properly in today’s low-cost environment. A PT is based on a much simpler single-axis tracking linear parabolic reflector concentrating light onto the coaxial receiver. The sunlight must be concentrated much less. Solar collectors concentrate sunlight to heat a synthetic oil, which then heats water to produce the superheated steam of the Rankine
power cycle. To design a plant, within acceptable cost constraints, then working properly over a long timeframe while ensuring a nearly perfect tracking system, it is much easier with the PT than the ST design. This is the main reason why ST plants built thus far have been outperformed by PT plants, even if the expectations were the opposite. About molten-salt TES, the increased complications of this design, where crystallization of the salt has often been a major issue, is similarly the reason why many plants with TES have failed to deliver even same performances of plants without TES despite the dramatically increased costs. Industrial products must be simple to be efficient and reliable within cost constraints. Finally, for the specific application of CSP discussed later, a small CSP solar field used to supplement the combustion fuel heat flow during daylight in Trinidad and Tobago, PT has not only the advantages of maturity, reliability, specific land use, cost and efficiency vs. ST. In an area subjected to storms, few single axis wind resistant collectors are preferably to many more fragile double axis heliostats and a tall tower. Solar irradiance in Trinidad and Tobago Trinidad and Tobago’s southerly location keeps temperatures stable year-round, with a daily average of 27 °C. There are two seasons, the rainy season, June to November, and the dry season, December to May. Weather conditions for Trinidad and Tobago, including temperatures, clouds coverage, daylight and sun energy, are available from weatherspark.com. Piarco International Airport has coordinates 10.5977° N, 61.3395° W. The solar irradiance of Trinidad and Tobago is considered not exceptional by [5,4]. The Direct Normal Irradiance (DNI) at a location is the amount of solar energy falling per m2 per day at that location. The DNI for a sunny region is approximately 6 kWh/m2/day. Ref. [4] excludes the Caribbean from the regions where the incoming solar energy is more than more than 2000 kWh/m2/y (about 5.5 kWh/m2/day), a value they consider as a threshold for economically viable standalone solar only CSP plants. Ref. [5] dismisses the standalone CSP option, however promoting the solar water heating and the solar photovoltaic options. globalsolaratlas.info proposes for Trinidad and Tobago an annual average DNI of 4.43 kWh/m2/day. The major issue in the Caribbean is the clouds coverage. To avoid clouds interference to a strong solar resource, CSP development in the United States has been mostly in the Southwest. However, CSP plants have also been recently proposed for areas such as Florida and Hawaii having haze index not far from the Caribbean [20]. With reference to typical locations where CSP plants have been built, for example Seville, Spain, Trinidad and Tobago are characterized by a much more significant clouds coverage. CSP uses very high temperatures, temporary cloud cover produces larger variations in electricity production that solar photovoltaic systems face [21]. globalsolaratlas.info proposes for Seville a much larger an annual average DNI of 5.66 kWh/m2/day. The average percentage of the sky covered by clouds experiences mild seasonal variation over the course of the year. The clearer part of the year is June to September. The clearest day of the year, the sky is clear, mostly clear, or partly cloudy 39% of the time, and overcast or mostly cloudy 61% of the time. The cloudier part of the year is September to June. The cloudiest day of the year, the sky is overcast or mostly cloudy 73% of the time, and clear, mostly clear, or partly cloudy 27% of the time. Fig. 5 presents a comparison of the clouds coverage in Trinidad and Tobago and Seville, Spain. The figure presents the percentage of time spent in each cloud cover band, categorized by the percentage of the sky covered by clouds, clear < 20% < mostly clear < 40% < partly cloudy < 60% < mostly cloudy < 80% < overcast. The length of the day does not vary substantially over the course of the year, staying within 44 min of 12 h throughout the year. The shortest day has 11 h, 30 min of daylight. The longest day has 12 h, 103
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Fig. 5. Percentage of time spent in each cloud cover band, categorized by the percentage of the sky covered by clouds. On the left, percentage of clear sky, on the right, percentage of cloudy sky. a, Piarco International Airport, Trinidad & Tobago, b, Seville San Pablo Airport Spain. Images reproduced modified after weatherspark.com.
45 min of daylight. The earliest sunrise is at 5:42 AM, and the latest sunrise is at 6:28 AM. The earliest sunset is at 5:39 PM, and the latest sunset is at 6:31 PM. Opposite to Spain, daylight saving time (DST) is not observed in Trinidad & Tobago. Considering the seasonal variations in the length of the day, the elevation of the Sun above the horizon, and the absorption by clouds and other atmospheric constituents, Fig. 6 presents the total daily incident shortwave solar energy reaching the surface of the ground. The shortwave radiation includes visible light and ultraviolet radiation. The average daily incident shortwave solar energy experiences some seasonal variation over the course of the year, with a brighter period of the year lasts for 2.6 months, from February 19 to May 7, with an average daily incident shortwave energy per square meter above 6.5 kWh. The brightest day of the year is March 29, with an average of 7.0 kWh. The darker period of the year lasts for 2.7 months, from September 13 to December 4, with an average daily incident shortwave energy per square meter below 5.1 kWh. The darkest day of the year is October 14, with an average of 4.6 kWh. In Seville, Spain, the average daily shortwave solar energy reaching the ground is 2.30 and 8.30 kwh/m2 respectively in winter and summer. Daylights are 9.35 and 14.45 h per day. In Trinidad and Tobago, the average daily shortwave solar energy reaching the ground is 4.60 and 7.00 kWh/m2 respectively in the dark and bright periods.
Daylights are 11.80 and 12.10 h per day. With reference to Seville, the average daily shortwave solar energy reaching the ground inclusive of clouds coverage is better in Trinidad and Tobago. Unfortunately, this result is misleading, as not all the shortwave solar energy reaching the ground may then be converted in heat in a CSP field. Fig. 6 presents the total daily incident shortwave solar energy per square meter, reaching the surface of the ground over a wide area, taking full account of the length of the day, the elevation of the Sun above the horizon, and the absorption by clouds and other atmospheric constituents. However, this is not the amount of solar energy that can be used by a CSP plant, where only the direct normal irradiance (DNI) play a role. Table 1 summarizes the DNI irradiance data for Trinidad and Tobago and Seville. We do only have the annual average DNI for the two locations, plus the information of Figs. 5 and 6, to derive the daily DNI of maximum, minimum and shoulders days. We take the daily DNI proportional to the daily total irradiance and daily cloud coverage, then requesting the average of the four days being equal to the annual DNI. Solar irradiance data for Trinidad and Tobago is provided in [22] for the wet and dry seasons. Over the period 2001–2010, the average daily global solar radiation, average total global solar radiation, average daily number of sunshine hours, and average total number of sunshine hours were 4.70 ± 0.20 kWh/m2/day, 0.71 ± 0.03 GJ/m2, 104
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Fig. 6. Average daily shortwave solar energy reaching the ground per square meter (orange line), with 25th to 75th and 10th to 90th percentile bands. a, Piarco International Airport, Trinidad & Tobago, b, for comparison, Seville San Pablo Airport Spain. Images reproduced modified after weatherspark.com.
8.49 ± 44 h/day and 12826 ± 67 h, for the dry season, and 4.31 ± 0.225 kWh/m2/day, 0.92 ± 0.05 GJ/m2, 7.03 ± 038 h/day, and 15046 ± 81 h for the wet season. The average of the two daily global solar radiations wet and dry season is not far from the DNI 4.43 kWh/m2/day of globalsolaratlas.info.
natural gas combustion. The boost by natural gas combustion to ramp up production in the morning, or compensate for the clouds, with a simple natural gas boiler, is thermally not the best opportunity of using the fuel energy. The thermal efficiency of a standalone CSP plant is only about 30%-40%, well below the efficiency of a combined cycle gas turbine plant that is about 55%-60%. There is therefore the opportunity to better integrate the CSP PT solar field with the natural gas combustion within combined cycle installations. If we consider the 377 MW Ivanpah power plant [24], the heliostat solar field aperture area is 2,600,000 m2. There are 173,500 heliostats of aperture area 15 m2 each. The land area is 3500 acres, or 14.16 km2. If we consider the 110 MW Crescent Dunes power plant [25], the heliostat solar field aperture area is 1,197,148 m2. There are 10,347 heliostats of aperture area 115.7 m2 each. The land area is 1600 acres, or 6.47 km2. Opposite to the solar field of the ISCC of Kuraymat, Egypt, Ain Beni Mathar, Morocco, Hassi R’Mel, Algeria or Agua Prieta II, Mexico, the land requirements are much more demanding for a country such as Trinidad and Tobago of total land area 5130 km2 with a population density of 268 peoples per km2. In the Integrated Solar Combined Cycle (ISCC) showcased in [19], the CSP PT solar field is integrated with an otherwise traditional gas turbine/steam turbine power plant. The sun energy is introduced as high pressure saturated steam, mixed with Heat Recovery Steam Generator (HRSG) High Pressure (HP) steam, and superheated for
Integrated solar combined cycle in Trinidad and Tobago From Figs. 2–4, we therefore see clear potentials for the development of an industrial product based on the CSP PT technology without any TES, that in the specific of Trinidad and Tobago, must be more deeply integrated with the natural gas combustion than simply having a back-up gas boiler. An addition to a combined cycle plant, rather than a standalone facility, may provide the best cost-to-benefit ratio. The integration of CSP with natural gas combustion also addresses the issue of cloud coverage, Fig. 5, with a back-up natural gas burner replacing the solar heat when unavailable in part or completely. Despite Trinidad and Tobago have escaped major devastating hurricanes, storms must be considered in the design of the structure. Also, under this aspect, the PT technology is superior to the ST technology. Trinidad and Tobago have a natural gas contribution to the energy generation mix of 99% (2010 data, [23]), and energy consumption by sector 64.9% commercial (2011 data, [23]). In the specific of Trinidad and Tobago, where the electricity system is very well developed, and natural gas is abundant, the PT technology must be integrated with 105
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Table 1 Irradiance data for Trinidad and Tobago and Seville. The daily DNI is estimated from the annual DNI and the daily total irradiation and percentage of partly cloudy.
source: globalsolaratlas.info Lat. Long. GHI DNI DIF GTI DNI day of max solar irradiance
day of min solar irradiance
shoulder days
source: weatherspark.com daily total irradiation daylight reference power partly cloudy computed values DNI reference DNI power source: weatherspark.com total energy daylight reference power partly cloudy computed values DNI reference DNI power source: weatherspark.com total energy daylight reference power partly cloudy computed values DNI reference DNI power
Trinidad and Tobago
Seville
deg. def. kWh/m2/year kWh/m2/year kWh/m2/year kWh/m2/year kWh/m2/day
10.4686 −61.2532 1978 1616 859 2011 4.43
37.4232 −5.9000 1833 2065 595 2107 5.66
kWh/m2/day h kWh/m2 %
7.00 12.1 0.58 30
8.30 14.45 0.57 93
kWh/m2/day kWh/m2
5.32 0.44
8.30 0.57
kWh/m2/day h kWh/m2 %
4.60 11.8 0.390 27
2.30 9.35 0.246 55
kWh/m2/day kWh/m2
3.40 0.289
2.03 0.217
kWh/m2/day h kWh/m2 %
5.3 12 0.442 34
5 12 0.417 63
kWh/m2/day kWh/m2
4.16 0.346
4.57 0.381
when the solar generator is unavailable. The plant is sized for about ¼ of HP steam generation in the solar generator, and ¾ in the HRSG. The solar field, sized for the irradiance conditions of Seville, Spain, has a total surface of 0.3 km2. The solar generator contributes up to 35% of HP steam at peak summer conditions, and much less at winter conditions. The combined cycle alone requires a land area of about 0.035 km2, for a combined land area of about 0.335 km2. Summer peak capacity is 415 MW. Operation at peak summer condition with the solar field contributes approximately 27.5 MW of power, or 6.5% of the total plant power. In terms of fuel conversion efficiency, the solar field adds about 3.9% to the plant efficiency, to move from a 55% to a 59% fuel conversion efficiency. The success in improving the conventional power plant’s fuel conversion efficiency depends on how specifically the solar field supplements heat to the other plant, and obviously at which costs. The above efficiency improvements are associated with a minimal impact of the solar field addition on the combined cycle operation. Larger solar contributions may impact more on power and efficiency, but at the price of added complexity of plant design and operation in non-solar mode. Results of preliminary computations for the operation of the ISCC plant of Fig. 7 relocated in Trinidad and Tobago are presented below. The model is a validated Thermoflow (www.thermoflow.com) model of an ISCC that is only adapted to the specific solar conditions and temperatures of Trinidad and Tobago. All the detailed ISCC model parameters are given by Thermoflow (www.thermoflow.com). The solar conditions for Trinidad and Tobago are those only guessed in Table 1. The results are thus easily reproducible by anyone having the specific model and the specific software. Better accuracy may only follow a proper measurement campaign for the DNI in Trinidad and Tobago.
admission to the turbine. With steam condensed in a dry air-cooled condenser, and desert like conditions of temperature and humidity, with 49.3 MW heat input from the solar field, and 276.3 MW heat input from the natural gas combustion, the plant can produce 157.6 MW of electric output for a 57.0% fuel conversion efficiency. Hence, accepting the use of CSP to boost efficiency of natural gas plants, rather than replacing these plants, there is the opportunity to increase the efficiency of a gas turbine/steam turbine plant from 48.4 to 57.0%, thus reducing the consumption of fossil fuels for the same electricity produced. In Trinidad and Tobago, by simply using a water-cooled condenser, the efficiency would be further improved. Results of simulations In the Thermoflow model of Fig. 7, a 1x1 9FA gas turbine/steam turbine combined cycle power plant (www.ge.com) is coupled to a PT solar thermal steam generator capable of producing partially superheated HP steam. GE’s 9FA combined cycle technology is adopted in many power plants operating worldwide. The exhaust gas from the gas turbine generator is converted to the steam driving the steam turbinegenerator. Combined cycle technologies enable the plant to produce additional power without increasing the fuel consumption. Integration with a solar field may further improve the fuel economy during transients as well as during steady state operation. The solar field heats Therminol oil to about 400 °C. The oil is pumped through a series of shell and tube heat exchangers to preheat feedwater and generate and superheat steam. Final superheating of the steam in the HRSG is required. The solar generator receives feedwater partially preheated from the HRSG and returns superheated steam to the HRSG. This steam is mixed with the HP steam exiting the first super-heater (HPS0). The mixture is superheated to final steam turbine throttle conditions of 550 °C. A duct burner is installed in the HRSG to raise additional steam 106
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Fig. 7. Thermoflow (www.thermoflow.com) model of an Integrated Solar Combined Cycle (ISCC) plant of peak summer capacity 415 MW having a solar field contribution of 27.5 MW.
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Fig. 8. Irradiance in day 88 (brighter day), day 181 (shoulder day) and day 287 (darker day) in Trinidad and Tobago.
The wet cooling tower may be conveniently replaced with a pump feed from a water reservoir and a water sink. The results for the baseline Combined Cycle (CC) plant without any solar field input are also presented. The major source of inaccuracy in the computation is the simulation of the clouds effects across the year. The solar irradiance is estimated from site data as described in [4]. The solar irradiance is computed based on the site latitude (10.69 N), the day of the year, the hour of the day (solar time), and a clouds parameter, the haze index or the clear sky correction factor. The atmospheric transmissivity depends on the distance the radiation travels through the atmosphere and the condition of the atmosphere. The beam pathlength in the atmosphere is computed using the solar zenith angle and the site altitude. The zenith angle is then computed based on the site-specific data and a geometric representation of relative sun-earth
positioning throughout the year. The clouds effect is either represented by interpolation between two conditions, clear-day (haze index = 0, 23 km visibility) and hazy-day (haze index = 1, 5 km visibility) or, alternatively, a clear sky correction factor, based on the average solar radiation for the selected month. Unfortunately, there are not enough data to properly tune these two models. As a first guess, Fig. 8 presents the prescribed irradiance during the brighter (day 88), darker (day 287) and shoulder day (day 181), computed by using the clear sky correction factor model with input the daily direct irradiation per square meter of Table 1. Fig. 9 presents the ISCC and CC results for the brighter day. Morning and afternoon, the solar field heat supply permits fuel savings translating in an efficiency increase from 54.76 to 58.45%, while mid-day, the efficiency increase is from 54.81 to 57.73%. 108
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Fig. 9. Efficiency of ISCC (left) and baseline CC (right) plant operation during the brighter day.
Fig. 10. Efficiency of ISCC (left) and baseline CC (right) plant operation during the shoulder days.
Fig. 10 presents the results for one of the two shoulders days. Morning and afternoon, the solar field heat supply permits fuel savings translating in an efficiency increase from 54.76 to 57.57%, while midday, the efficiency increase is from 54.81 to 58.26%. Fig. 11 finally presents results of computations for the operation during the darker day. Morning and afternoon, the solar field heat supply permits fuel savings translating in an efficiency increase from 54.76 to 56.48%, while mid-day, the efficiency increase is from 54.81 to 56.91%. Over the year, the plant operates at an efficiency of 54.93% overnight, for about 12 h a day, with obviously no improvements vs. the conventional power plant without the solar field. Over the morning and afternoon periods, of length about 8 h a day, the plant operates at an efficiency of 57.34%, about 2.58% better than the efficiency of the conventional power plant without the solar field at 54.76%. Over the mid-day periods, of length about 4 h a day, the plant operates at an efficiency of 57.97%, about 3.16% better than the efficiency of the conventional power plant without the solar field at 54.81%.
Conclusions Trinidad and Tobago have interest in supporting renewable energy and energy efficiency, developing new economic sectors and reducing the government’s fuel subsidy liabilities. The deployment of CSP PT, without any TES, but integrated with natural gas combustion, in an ISCC plant is key initiative to contribute with renewable energy to the electricity production of Trinidad and Tobago, while improving local employment, manufacturing potentials and export of industrial products. The novelty of this work is the application of a validated model of a ISCC featuring a commercial CCGT plant coupled to a small CSP PT solar field with solar irradiance input (and temperature) specific to the location of Trinidad and Tobago. Opposite to what has been concluded in reference works such as [4] and [5], the relatively high clouds coverage does not prevent the ISCC from delivering a few percentage points better fuel conversion efficiency than the standalone CCGT plant at affordable costs. Better estimations may only follow the construction of a small demonstration plant. The work has reference values for applications of CSP to areas with high cloud coverage. 109
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Fig. 11. Efficiency of ISCC (left) and baseline CC (right) plant operation during the darker day.
Appendix A. Supplementary data
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