Economic evaluation of solar thermal hybrid H2O turbine power generation systems

Energy 28 (2003) 185–198 www.elsevier.com/locate/energy

Economic evaluation of solar thermal hybrid H2O turbine power generation systems Takanobu Kosugi a,∗, Pyong Sik Pak b a

Systems Analysis Group, Research Institute of Innovative Technology for the Earth, 9-2 Kizugawadai, Kizu-cho, Soraku-gun, Kyoto 619-0292 Japan b Department of Bioinformatic Engineering, Graduate School of Information Science and Technology, Osaka University, 2-1 Yamada-oka, Suita, Osaka 565-0871 Japan Received 14 June 2002

Abstract The economics of two proposed solar thermal hybrid power generation systems (STHSs) have been evaluated. Each system consists of direct-steam-generation solar collectors, a steam accumulator and a gas turbine power generation system which uses steam as its working fluid. One (STHS-A) of the proposed systems emits CO2 generated by burning fuel, whereas the other (STHS-B) captures the CO2. Assuming that the systems are located in San Francisco, USA, where solar radiation energy is approximately the same as the global average, the levelized electricity costs (LECs) of the STHSs have been estimated considering future uncertainty of fuel cost and the capital cost of the solar collector. The LECs of combined cycle plants, which are considered to be one of the major thermal power generation systems in the near future, have also been estimated to evaluate the economics of the proposed systems. When fuel (methane) cost is 4.5 $/GJ, for example, the STHS-A has been estimated to be the most economical among the evaluated systems where the carbon tax is higher than a value in the range of 106–244 $/t-C, whereas the STHS-B is the most economical where the carbon tax is higher than a value between 368 and 475 $/t-C.  2002 Elsevier Science Ltd. All rights reserved.

1. Introduction In order to reduce fossil fuel consumption and carbon dioxide (CO2) emissions, promoting the utilization of renewable energy and improving the efficiency of energy utilization are important. Solar thermal energy, the most abundant renewable energy source, has been used to generate

∗

Corresponding author. Fax: +81-774-75-2317. E-mail address: [email protected] (T. Kosugi).

0360-5442/03/$ - see front matter  2002 Elsevier Science Ltd. All rights reserved. doi:10.1016/S0360-5442(02)00092-0

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electric power energy in limited regions where solar radiation energy is abundant [1]. The Solar Electric Generating System (SEGS) plants currently operating in California, the United States of America (USA), are the best examples of the state of the art of the technology of solar thermal energy generation systems. In the SEGS plant, steam is generated by making use of the thermal energy of synthetic oil which is heated through parabolic-trough solar collectors, and is fed to a steam turbine power generation system. We should note that the economics of these conventional SEGS type solar thermal energy systems deteriorate when the systems are located in other regions, however [2]. For improving the economics of the solar thermal energy systems, several hybrid systems using fuel as another energy source have been proposed; e.g., a system where the steam produced by using solar energy is superheated through a fuel-fired superheater [3,4], and a system integrated with a conventional combined cycle power plant, called the Integrated Solar Combined Cycle System (ISCCS), where the solar-produced steam is superheated through a waste heat recovery heat exchanger by making use of the heat energy of gas turbine exhaust gas [5]. A 100-150 MW ISCCS is planned to be realized by 2003 in Egypt with the support of the Global Environment Facility Counsel [6]. Research on a Direct-Steam-Generation (DSG) type solar collector, which can generate steam directly in the absorber pipe of the collector, has also been promoted; a six-year project named Direct Solar Steam (DISS) has been underway within the framework of the Joule Programme since 1996 [7]. The solar energy-to-steam conversion efficiency of the DSG type collector is higher than that of a conventional solar collector, since in the DSG collector there is no heat transfer fluid temperature drop and heat exchanger loss [8]. Accordingly, solar thermal systems with the DSG type collectors become more economical than the systems with conventional collectors. Capturing CO2 from fossil-fired power plants is also expected to be an excellent method of reducing CO2 emissions. However, additional energy is required to capture the CO2 from the stack gas of a conventional thermal power plant so that the net thermal efficiency is degraded by approximately 10%. The unit cost of generated power energy of a CO2-capturing conventional natural gas-fired plant has been estimated to be 1.5–2 times higher than that of a CO2-emitting plant owing not only to the additional fuel cost caused by the degradation in thermal efficiency but also to the extra capital costs of CO2 separation and liquefaction equipment [9,10]. Several kinds of gas turbine-based CO2-capturing systems with oxygen combustion have been proposed by the authors [11] and other researchers [12,13] to improve the net efficiency and economics. In these systems, fuel gas is combusted by using pure oxygen, and CO2 plus H2O are recycled from the exhaust gas. These systems do not require special equipment for CO2 separation (e.g., an amine scrubber) different from conventional air-combusting systems. The system proposed by the authors in Ref. [11] was a dual fluid gas turbine system where CO2 and H2O gases are used as the main and sub working fluids of a gas turbine, respectively. That is, the gas turbine exhaust gas is utilized in a waste heat recovery boiler to produce steam which is injected into a combustor to increase power output. We have extended this concept to propose a gas turbine power generation system utilizing steam, produced by using waste heat from factories, etc., as its main working fluid [14]. In this system, steam is introduced into a combustor after being heated through a regenerator by making use of the energy included in gas turbine exhaust gas [15]. The temperature of the steam is raised to higher than 1300 K by burning

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the fuel with pure oxygen. The authors refer to this type of gas turbine as a H2O turbine. For more detailed information on the H2O turbine, see Refs. [14,15]. This paper shows that use of solar energy and fossil-fuel together with CO2 capturing by means of oxygen combustion is a more cost effective way for reducing CO2 emissions in many regions. The CO2-capturing solar thermal hybrid H2O turbine power generation system proposed by the authors [16] is a system which uses both solar energy and fossil-fuel. Since the H2O turbine is incorporated in this system, the maximum operating temperature can be made much higher than that of steam turbines used in the SEGS type systems, and thus the energy efficiency can be remarkably higher. It has been estimated that the proposed system has a net fuel-to-electricity efficiency, which is defined as the ratio of net generated electricity to input fuel energy excluding solar energy, higher than 60% even when both the energy to produce high pressure oxygen and to liquefy the captured CO2 are taken into account [16]. In the present paper, two types of solar thermal hybrid H2O turbine power generation systems are evaluated from thermodynamic characteristic and economic viewpoints. One of the systems emits generated CO2 whereas the other captures the CO2. Assuming an economic penalty for emitting CO2, i.e., a carbon tax, the economic feasibility of the two systems is investigated by comparing them with combined cycle plants. 2. System structure Fig. 1 shows the total structure of the solar thermal hybrid H2O turbine power generation systems (referred to as STHSs) evaluated previously [17]. In these systems, saturated steam is produced by using solar thermal energy and is utilized as the working fluid of the H2O turbine power generation system [15]. The DSG type collectors are assumed to be adopted considering their performance advantages. A steam accumulator is incorporated as a heat storage device to store surplus steam produced during the day when solar radiation is large and to use the steam when solar radiation is low [17]. When storing the steam produced in the collectors, the internal pressure in the accumulator increases according to the stored heat energy amount. By opening the valve at the accumulator outlet, the steam is released from the accumulator, and the internal pressure decreases. Fig. 2 (a) shows the structure of the CO2-capturing H2O turbine power generation system [15]. In this system, fuel is combusted with pure oxygen so that the generated CO2 is easily captured

Fig. 1. Total structure of the proposed system.

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Fig. 2. Structure of the H2O turbine power generation system. (a) the system which captures CO2 (CO2-capturing system), (b) the system which does not capture CO2 (CO2-emitting system).

by the cooling operation of the turbine exhaust gas. The structure of the H2O turbine power generation system (CO2-emitting system), which does not capture the CO2, shown in Fig. 2 (b) is also investigated. In this system, neither O2 production equipment nor CO2 liquefaction equipment is incorporated; the air required for combusting the fuel is compressed by using a small scale compressor. The CO2-emitting system is expected to be economically superior to the CO2capturing system. In the following sections, the CO2-emitting H2O turbine power generation system is referred to as STHS-A and the CO2-capturing H2O turbine power generation system as STHS-B.

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3. Characteristics and economics of the proposed systems 3.1. Assumptions For estimating characteristics of the two proposed systems, STHS-A and the STHS-B, computer simulation models have been developed based on thermodynamics [18]. Table 1 shows the Table 1 Exogenous variables and parameters of the simulation models (a) Exogenous variables Item

Reference value

Total aperture area of solar collectors Steam temperature produced by using solar energy Internal volume of steam accumulator Minimum steam pressure at steam accumulator outlet Turbine inlet temperature Maximum operating temperature of regenerator Fuel Net maximum power output Excess air (oxygen) ratio in combustor Condenser outlet pressure Condenser outlet temperature

100,000 m2 543 K 4000 m3 0.98 Mpa 1573 K 873 K Methane to be determined 1% 19.6 kPa 306 K

(b) Exogenous parameters Item

Reference value

Optical efficiency of solar collector Concentration ratio of solar collector Effective emittance of solar collector Enthalpy loss rate in thermal transportation tube Pressure loss at the inlet and outlet of steam accumulator Enthalpy loss rate in steam accumulator Adiabatic efficiency of turbine Combustion efficiency of combustor Pressure loss rate in combustor Pressure loss rate at nozzle Pressure loss rate in filter silencer Unit oxygen production power energy Adiabatic efficiency of compressor Temperature efficiency of regenerator Pressure loss rate of steam and turbine exhaust gas in regenerator Exhaust gas pressure loss in waste heat recovery heat exchanger Generator efficiency Inhouse power consumption rate Coefficient of performance of chiller Chiller outlet gas temperature Adiabatic efficiency of CO2 compressor Intermediate cooling temperature of CO2 compressor

77% 26 0.19 5% 68.6 kPa; 39.2 kPa 0.5%/d 87.5% 99% 5% 20% 2% 0.34 kWh/Nm3 85% 75% 2%; 5% 4.90 kPa 98% 3% 3.5 280 K 85% 323 K

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exogenous variables and parameters of the models. The reference values of the variables and parameters used are also listed in Table 1. These values are assumed so as to represent an upto-date technological state of solar collectors and medium scale thermal power plants [8,15,18]. The DSG type collectors with single-axis-tracking devices are assumed to be located on the north– south axis, and the total aperture area of the collectors is 100,000 m2. The saturated steam temperature produced in the collectors by using solar energy is set as 543 K, the temperature at which the fuel-to-electricity efficiency has been estimated to be maximum [19]. The steam temperature is raised to 1573 K at the combustor outlet by burning natural gas (assumed to be pure methane for simplicity). The installed location is assumed to be San Francisco, USA, where the annual total horizontal solar radiation energy is 1764 kWh/m2/yr (in 1990), approximately the same as the global average solar radiation of 1700 kWh/m2/yr [9]. Hourly solar radiation data in San Francisco, provided by the Renewable Resource Data Center [20], was used for the computer simulation. The economics of the systems have been evaluated on the basis of levelized electricity cost (LEC), i.e., the unit cost of generated power energy. The cost data used for calculating the LEC are listed in Table 2. Note that all costs are presented in 1990 US dollars. Capital costs are assumed according to Refs. [10,21]. The net maximum power output of each system is determined so as to minimize the LEC. Though the technology of the H2O turbine has not been established, the H2O turbine is based on gas turbine technologies, so that its production cost on a mass production basis is expected to be close to that of a conventional gas turbine. The moderate cost estimates for conventional gas turbines and combined cycles are 346 and 593 $/kW, respectively, in industrialized countries Table 2 Cost data assumed for economics evaluation Item Capital costs of the proposed STHSs: Solar collector Steam accumulator H2O turbine power generation system (excluding O2 production equipment and CO2 liquefaction equipment) O2 production equipment CO2 liquefaction equipment Capital costs of the CCSs: Combined cycle power generation system (excluding CO2 absorption equipment and CO2 liquefaction equipment) CO2 absorption equipment CO2 liquefaction equipment Fuel cost Disposal cost of captured CO2 Capital interest rate System lifetime Remained value rate of system Maintenance cost rate Capacity factor of the CCSs

Reference value

see Table 3 407 $/m3 530 $/kW 5.92 × 105 $/(t-O2/h) 2.36 × 106 $/(t-C/h) 593 $/kW 2.02 × 106 $/(t-C/h) 2.36 × 106 $/(t-C/h) see Table 3 67.6 $/t-C 6%/yr 15 yr 10% 5%/yr 70%

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Table 3 Definitions for the cases assumed Case 1

Case 2

Case 3

Item

-a

-b

-a

-b

-a

-b

Fuel cost ($/GJ) Capital cost of solar collector ($/m2)

2.2 122

2.2 91.3

4.5 122

4.5 91.3

5.5 122

5.5 91.3

in the future according to Ref. [21]. Thus, the authors set the capital cost of the H2O turbine power generation system (excluding O2 production equipment and CO2 liquefaction equipment) at 530 $/kW by considering its system structure. The disposal cost of the captured CO2 is set at 67.6 $/t-C [22] assuming that the captured CO2 is transported to a disposal site located 100 km distant from the system by tankers and is piped to the ocean bottom at a depth deeper than 3000 m. Three sets of scenarios, Cases 1, 2 and 3, are analyzed for taking future uncertainties of fuel cost and the capital cost of solar collector into consideration. The details of the scenarios are given in Table 3. Case 1 assumes that the fuel cost remains at the 1990s’ level (2.2 $/GJ), whereas Cases 2 and 3 presume that the fuel cost increases to be approximately doubled (4.5 $/GJ) and higher (5.5 $/GJ), respectively, caused by the depletion of fuel resources, etc. These three values of the fuel cost correspond to the Intergovernmental Panel on Climate Change (IPCC) second assessment report [9]. Each case is divided into two sub-scenarios addressing improvements in design and production process of the solar collector. High (122 $/m2) and low (91.3 $/m2) values are assumed as the capital cost of the collector based on a statistically investigated cost prospect [21] from the International Institute for Applied Systems Analysis (IIASA) CO2 Technology Data Bank (CO2DB) [23]. In Case 1, for example, the two scenarios are denoted by the Cases 1-a and 1-b corresponding to the assumed high and low capital costs of the collector, respectively. 3.2. Estimated power generation characteristics The major estimated power generation characteristics of the proposed systems are shown in Table 4. For the STHS-A, the net maximum power output is estimated to be 22.4 MW, which is 83% larger than that of the STHS-B. This difference in the power output between the two STHSs occurs because the maximum flow rate of the working fluid gas of the H2O turbine in the STHS-A is larger than that in the STHS-B, since the amount of air required for heating a unit amount of the steam to the assumed turbine inlet temperature is larger than the amount of pure oxygen. The net fuel-to-electricity efficiency is estimated to be 71.6% for the STHS-A and to be 70.1% for the STHS-B on a lower heating value basis, respectively. The gross and net efficiencies on the basis of fuel are shown in Fig. 3, where the gross efficiency can be calculated by dividing the gross generated power by the consumed fuel energy. For the STHS-A, the gross efficiency is estimated to be 98.9%, but the net efficiency is decreased to

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Table 4 Major estimated characteristics and economics

Net maximum power output (MW) Net generated power energy (GWh/yr) Fuel consumptionc (TJ/yr) Net fuel-to-electricity efficiencyc (%) Solar-produced steam consumption (TJ/yr) CO2 emission (tC/yr) CO2 emission coefficient (gC/kWh) Levelized electricity cost, LEC (cent/kWh) Case 1 -a -b

STHS -Aa

-Bb

CCS -Aa

22.4

12.4

600

491

149

81.0

3679

3010

749

416

24080

24080

71.6

70.1

55

45

421

421

0

0

11.2

0

360

75.2

0

97.9

-Bb

36.0 12.0

3.82 3.51

6.83 6.25

2.92 2.92

5.60 5.60

Case 2

-a -b

4.98 4.66

8.01 7.43

4.42 4.42

7.44 7.44

Case 3

-a -b

5.48 5.17

8.52 7.95

5.08 5.08

8.24 8.24

a b c

CO2-emitting system CO2-capturing system on lower heating value basis

Fig. 3.

Estimated gross and net efficiencies on the basis of fuel.

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71.6%, owing to the power consumed for air compression and other processes. For the STHS-B, the net efficiency is only 1.5% lower compared to the STHS-A, though the gross efficiency is 8.0% lower. This is because that the power consumption for compressing O2 in the STHS-B is only about a quarter of that for compressing the air in the STHS-A. The energy of the consumed fuel is 77.9% larger than the enthalpy of the solar-produced steam fed into the H2O turbine for the STHS-A, whereas they are almost the same for the STHS-B. That is, the STHS-B, which captures CO2, is less dependent on fuel for its power generation. As shown in Table 4, the CO2 emission coefficient, that is defined as the amount of CO2 emission per unit net generated power energy, of the STHS-A is estimated to be 75.2 g-C/kWh. The STHS-B emits no CO2 into the atmosphere in its operation process. 3.3. Estimated economics The LECs of the systems are obtained by dividing the levelized annual total cost by the net generated electric power energy given in Table 4. Here the levelized annual total cost can be calculated as the annual sum of the depreciation of the capital cost, the system maintenance cost, the fuel cost and, when necessary, the disposal cost of the captured CO2 and the carbon tax. The annual depreciation of the capital cost is the product of the total capital cost of all equipment comprising the system multiplied by the capital recovery factor R, which is defined as R ⫽ r[1⫺L / (1 ⫹ r)n] / [1⫺1 / (1 ⫹ r)n]

(1)

where r is the capital interest rate (yr⫺1), n is the system lifetime (yr) and L is the remaining value rate of the system. Other costs can be obtained easily; for example, the annual fuel cost is calculated by multiplying the annual fuel consumption by the unit fuel cost. The average unit costs of the solar-produced steam, calculated from the enthalpy of the produced steam and the levelized annual cost of the solar collectors, are 4.31 and 3.40 $/GJ for the assumed high and low capital costs, respectively. Though these costs of the steam are higher than the fuel cost of the 1990s’ level, they are less expensive than the two higher values of the fuel cost assumed in Section 3.1. The most important reason for the inexpensiveness of the solarproduced steam is that the temperature of the steam in the STHSs, 543 K, is lower than that in the SEGS plants, approximately 620–670 K. If the temperature of the steam is higher, the heat collection efficiency of the solar collector decreases so that the unit cost of the steam rises [16]. The estimated LECs of the proposed systems are also shown in Table 4. In Cases 1, 2 and 3, the LECs of the STHS-B are estimated to be about 78, 60 and 50% higher than those of the STHS-A, respectively. This is because the additional capital costs of the O2 production and CO2 liquefaction equipment are required for the STHS-B.

4. Economic comparison with combined cycle systems 4.1. Characteristics and economics of combined cycle power generation systems Combined cycle power generation systems (referred to as CCSs) have been widely installed in the last decade and will be one of the major thermal power generation systems in the near future.

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In this paper, CO2-emitting and CO2-capturing natural gas-fired CCSs, referred to as CCS-A and CCS-B, respectively, are adopted and compared with the proposed systems. The net maximum power output of the CCS-A is set at 600 MW. In the CCS-B, 90% of the generated CO2 is assumed to be captured from the stack gas by using the method of chemical absorption. The major characteristics of the CCSs are also listed in Table 4. The net fuel-to-electricity efficiencies of 55 and 45% for the CCS-A and CCS-B, respectively, are assumed according to Ref. [10]. These values are 17 and 25% lower than those of the proposed STHS-A and STHSB, respectively. Table 4 also shows the LECs of the CCSs which have been calculated based on the assumed cost data shown in Table 2. The LECs of the CCS-B are calculated to be 92, 68 and 62% higher than those of the CCS-A for Cases 1, 2 and 3, respectively. Compared to the proposed system (the increase rates of the LEC by adopting CO2 capture for the STHSs have been estimated to be 78, 60 and 50% in Cases 1, 2 and 3, respectively), we can see that capturing CO2 in the combined cycle system is less economical than that in the proposed system. 4.2. Comparison of levelized electricity costs under a carbon tax Although the CCS-A has the lowest LEC among the evaluated systems in all the cases as shown in Table 4, the STHSs and the CCS-B are expected to be more economical than the CCSA if an economic penalty for emitting CO2, e.g. the carbon tax, which has been partly imposed in some north European countries, is imposed. Fig. 4 shows the estimated LECs of the evaluated systems when the carbon tax is imposed for each case. In Fig. 4, two (high and low) values of the LEC of each proposed system correspond to the two scenarios, e.g., Case 1-a and 1-b scenarios. The LECs of the STHS-A and the CCSs increase linearly with the carbon tax because these systems emit CO2. The LECs of the systems increase also with an increase in the fuel cost at the rates of the values in inverse proportion to the net fuel-to-electricity efficiencies.

Fig. 4. Estimated levelized electricity costs (LECs) under a carbon tax. (a) Case 1, (b) Case 2, (c) Case 3.

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The evaluated results of the economic comparison between the STHSs and the CCSs can be described as follows. In Case 1 when the fuel cost is set at the 1990s’ level (2.2 $/GJ), the LECs of the CCSs are lower than those of the STHSs in general. In the Case 1-a scenario where the capital cost of the collector is high (122 $/m2), the CCS-A is the most economical among the investigated systems when the carbon tax is lower than 312 $/t-C; the CCS-B is the most economical when the carbon tax is raised above 312 $/t-C. The LEC of the STHS-A is the lowest only when the carbon tax is in the range of 259–331 $/t-C in the Case 1-b scenario where the collector cost is low (91.3 $/m2). The STHS-B is not estimated to be the most economical even when the carbon tax is raised to 500 $/t-C. In Case 2 when the fuel cost increases to 4.5 $/GJ, the difference in LEC between the STHSs and the CCSs becomes small compared to Case 1. In the Case 2-a scenario, the most economical system is shifted from the CCS-A to the STHS-A when the carbon tax is raised to 244 $/t-C; the CCS-B is the most economical when the carbon tax is in the range of 389–475 $/t-C, and the STHS-B is when the carbon tax is raised above 475 $/t-C. In the Case 2-b scenario, the LECs of the STHSs become lower so that the CCS-B cannot be the most economical. For Case 3 when the fuel cost increases to 5.5 $/GJ, the STHSs become the most economical under a lower carbon tax than for the Case 2. The most economical systems are the CCS-A, the STHS-A, and the STHS-B when the carbon tax is lower than 178 $/t-C, in the range of 178–405 $/t-C, and above 405 $/t-C, respectively, in the Case 3-a scenario. The LEC of the STHS-A is the lowest when the carbon tax is in the range of 39–370 $/t-C, and the STHS-B is when the carbon tax is raised above 370 $/t-C, in the Case 3-b scenario. Fig. 5 depicts the systems whose LECs are estimated to be the lowest among the investigated systems. 4.3. Discussion on the estimated values of the carbon tax Ellerman et al. [24] have estimated the marginal costs of realizing the target for greenhouse gas emissions reduction for the years centered on 2010 described in the Kyoto Protocol to the United Nations Framework Convention on Climate Change. The estimated marginal costs are 223, 327 and 700 $/t-C for the USA, the European Union and Japan, respectively, assuming that

Fig. 5. Systems estimated to be the most economical for each case.

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the parties mentioned in Annex B of the Kyoto Protocol act independently; the marginal cost will be 152 $/t-C when there is a tradable emissions permits market for the Annex B regions. In another study [25], the world average macroeconomic cost per ton of carbon reduction is estimated to increase from 140 $/t-C in 2020 to a bit less than 500 $/t-C in 2100 in order to stabilize the atmospheric carbon concentration at or below 550 ppmv under a plausible scenario, i.e., the B2 scenario developed by the Working Group III of the IPCC [26]. The estimated values of the carbon tax necessary for the proposed systems to be economically viable as shown in the previous subsection are thus expected to be comparable to the macroeconomic costs of carbon reduction by the mid-21st century to avoid serious global warming in the future.

5. Conclusion The power generation characteristics of the proposed CO2-emitting and CO2-capturing solar thermal hybrid H2O turbine power generation systems (proposed systems or STHSs) have been estimated for evaluating their economics assuming that the systems are located in San Francisco, USA, where solar radiation energy is approximately the same as the global average value. It has been shown that the fuel-to-electricity efficiencies are 71.6 and 70.1% for the CO2-emitting and CO2-capturing proposed systems. These efficiencies are 16.6 and 25.1% higher than those for the CO2-emitting and CO2-capturing conventional combined cycle systems (CCSs). The CO2 emission coefficient of the proposed CO2-emitting system is estimated to be 23.2% lower than that of the CO2-emitting CCS. The CO2-capturing proposed system emits no CO2. Through the economic evaluation of the STHSs in comparison with CCSs, the necessary conditions have been analyzed for the proposed systems to be economically advantageous based on the levelized electricity cost (LEC) assuming that the carbon tax is imposed. If the fuel cost remained at the 1990s’ value (2.2 $/GJ), the LEC of the CO2-emitting CCS was estimated to be the lowest, and the CO2-capturing CCS was the most economical when the carbon tax was raised above about 300 $/t-C. However, when the fuel cost increased, the CCSs became less economical owing to their lower fuel-to-electricity efficiencies compared to the proposed systems. If the fuel cost was approximately doubled (4.5 $/GJ), the CO2-capturing proposed system was estimated to be the most economical when the carbon tax was higher than 475 $/t-C. The CO2-emitting proposed system was estimated to have economical advantage during the period when the carbon tax was in the range of 244–389 $/t-C; i.e., when the CO2 emission constraint was not so strict. The minimum values of the carbon tax necessary for the proposed systems to be the most economical was estimated to be decreased to 106 and 368 $/t-C for the CO2-emitting and CO2-capturing proposed systems, respectively, when the assumed solar collector cost was low, and the values became 39 and 370 $/t-C, respectively, when the fuel cost became higher. It can be concluded that the proposed systems become one of the most efficient and economical power generation systems in the future when the fuel cost becomes high and CO2 emission constraint is imposed.

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